Monthly Gas News Commentary: January – February 2018


India’s push to more than double the share natural gas has in its energy mix to 15 percent by 2022 will require a huge increase in imports and the construction of LNG terminals. India has four terminals to receive LNG and imports around 20 mt of the super-chilled fuel a year. But over the next seven year the government plans to build another 11 terminals. That would raise India’s LNG import capacity to more than 70 mt per year in the coming seven years, in what would be one of the fastest gas import expansions since China embarked on its huge gasification programme last year. India would eventually require even more than 15 terminals to meet its demand. India has stated it plans to raise the share of natural gas in its energy mix to 15 percent by 2022 from about 6.5 percent now. The 70 mt a year target a few years later would mean Indian would need to import more than China took last year via both pipelines and tankers, and it would put India close to what top importer Japan currently buys. India plans to electrify millions of households that still burn wood for light, heat and cooking. Like China, it also plans to reduce its heavy reliance on thermal coal, a bigger polluter than gas. Gas would also be needed to provide power to electric vehicles, which India plans to account for all new car sales by 2030. India is also pushing for more scooters and motorcycles to run on CNG with pilot schemes recently launched in major cities including New Delhi and Mumbai. Beyond LNG, India is looking to access untapped domestic gas reserves off its east coast. As part of its drive to reduce pollution by increasing natural gas use the government was encouraging Indian railway companies and LNG importers to look at fuelling trains by LNG instead of diesel. India also wants to become a hub for supplying ships that run on LNG, with plans to build more facilities like a fuelling station at Kochi port. LNG as a shipping fuel is being pushed by International Maritime Organization rules that come into effect by 2020 and require the use of cleaner fuels.

IGS an equal joint venture of BP and RIL in 2011 plans to begin selling imported LNG to Indian customers in 12-18 months to cater to the rising natural gas demand in the country. India Gas Solution administers the existing gas sales contracts to customers for production from the RIL-BP’s KGD6 block and is actively pursuing opportunities for marketing the proposed output from R-Series field in the KG Basin. R-Series is expected to begin producing 12 mmscmd from 2020. The firm was in talks with all the players in the value chain, including customers, suppliers, pipeline owners and the regasification terminal operators, and everything would come together soon. BP has a huge presence globally in the LNG trading business, is hoping to lean on that experience and network to bring Indian gas consumers a competitive deal. By entering LNG supply business in India, India Gas will directly compete with state-run suppliers such as GAIL (India) Ltd, Indian Oil and Petronet LNG.

RIL and BP Plc, partners in a gas block in the KG basin, have started approaching prospective customers to sell gas that will start flowing from their R-series field in 2020. The firms will sell gas through IGS for the sourcing and marketing of gas. New gas production from the D6 field in the KG block will flow from 2020 and is expected to bring a total 30-35 mmscmd phased over 2020-22. So far, only the D6 field in KG block is producing gas. The R-Series and other satellite fields are yet to be developed. The six satellite fields include D2, 6, 19, 22, 29 and 30, in the KG block. While the development of the six satellite fields would be taken up together, D-34 or R-Series and D-55 (MJ) would be developed separately. RIL and BP announced an investment of ₹ 400 billion in their satellite fields, R-Series and MJ gas discoveries, to reverse flagging production from the KG block. This investment will boost production as much as fivefold over the next three to five years. IGS is also pursuing options to import and market LNG into India and looking to pick up stake or administer capacity in LNG regasification facilities and gas transportation pipelines. RIL and BP are partners in the KG block, which currently produces around 7-8 mmscmd. While RIL holds a 60% stake in the gas block, BP owns 30%. Canada-based Niko Resources Ltd owns the rest. The D6 field began gas production in April 2009 and was to hit a peak output of 69.43 mmscmd in March 2010. However, water and sand ingress forced the closure of some wells, leading to a drop in production. BP and RIL began their partnership in 2011, when BP picked up a 30% stake in RIL’s 21 oil and gas blocks for $7.2 billion.

ONGC’s gas production rose 7.9% and crude output went up 1.5% in the first nine months of the current fiscal against the previous corresponding period. The ONGC board had approved projects worth over ₹ 780 billion in the last three years. These projects will lead to additional oil and gas output of over 180 mtoe. The acquisition of government’s 51.11% stake in HPCL will make ONGC India’s third-largest refiner and the first fully vertically integrated energy company, straddling the entire hydrocarbon value chain. The acquisition of HPCL will bolster the kitty of MRPL, ONGC’s refining subsidiary that processed a record 16.5 mt of crude.

Hiranandani Group-promoted H-Energy, which is executing a ₹ 35 billion project to import and distribute LNG in West Bengal, has decided upon the shore-based regasification terminal model to expedite work. The company expects to complete the LNG project at Haldia within the next 18-24 months. Transportation major ‘K’ Line has a 26 percent stake in a joint venture with H-Energy to execute and manage the storage and literage part (FSU) of the imported LNG project valued at $300 million. ‘K’ Line is estimated to supply 155,000 m3 LNG FSU. However, the regasification terminal at the shore near Digha will require about $250 million, which will be executed solely by the Hiranandani Group. H-Energy intends to execute the LNG project in phases, slowly ramping up capacity from 1.0 to 4.0 mtpa. It can be later scaled up to 6.0 mtpa. The company will construct a station near Haldia to receive LNG by shuttle carriers, where it is stored and regasified in a Floating Storage and Regasification Unit, holding approximately 40,000 m3. The initial capacity of this unit will be around 1.0 mtpa. H-Energy will be constructing pipelines of about 100 km to supply gas in Haldia and West Bengal. The natural gas is also proposed to be exported to Bangladesh.

India put on auction a record exploration acreage for prospecting of oil and gas, from 55 blocks, in the first bid round in eight years. Each block on offer has been carved out by prospective bidders under the open acreage licensing of the new Hydrocarbon Exploration and Licensing Policy. Blocks would be awarded to the company which offers highest share of oil and gas to the government as well as commits to do maximum exploration work by way of shooting 2D and 3D seismic survey and drilling exploration wells. Increased exploration would lead to more oil and gas production, helping the world’s third largest oil importer to cut import dependence. India had in July last year allowed companies to carve out blocks of their choice with a view to bringing about 2.8 million square kilometres of unexplored area in the country under exploration. Under this policy, companies are allowed to put in the EoI for prospecting of oil and gas in any area that is presently not under any production or exploration licence. The EoIs can be put in at anytime of the year but they are accumulated twice annually. The blocks or areas that receive EoIs at the end of the cycle are put up for auction with the originator or the firm that originally selected the area getting a 5-mark advantage. The 55 blocks have a total area of 59,282 square km. This compares to about 1,02,000 square km being under exploration currently. ONGC and Cairn India – a unit of Vedanta Ltd, had put in 41 out of 57 bids received in November last year. Private player Hindustan Oil Exploration Company bid for one area in a round. Of the 57 EoIs put only 55 blocks were cleared for bidding after eliminating areas that are under no-go zone or overlapping with existing mining lease. He said the opening up of 2.8 million square km of sedimentary basins for oil and gas exploration will help raise domestic production and cut excessive dependence on imports. The new policy replaced the old system of government carving out areas and bidding them out. It guarantees marketing and pricing freedom and moves away from production sharing model of previous rounds to a revenue sharing model where companies offering maximum share of oil and gas to government are awarded the block. Till now, the government has been selecting and demarcating areas it feels can be offered for bidding in an exploration licensing round.

The government has approved RIL and British energy giant BP plc acquiring their cash-strapped partner Niko Resources’ 10% stake in gas discovery block NEC-25 in the Bay of Bengal. Niko had in mid-2015 chosen to withdraw from the NEC-25 block and relinquish its interest to the remaining stakeholders. RIL is the operator of the block with 60% interest while BP of the UK has the remaining 30% stake. The 10% stake has been split between RIL and BP in proportion to their equity stake. Gas discoveries in North-East Coast block NEC-0SN-97/1 (NEC-25) hold recoverable reserves of 1.032 trillion cubic feet. The Canadian company has been facing cash problems and had even put up for sale its interest in NEC-25 as well as 10% stake in RIL’s Krishna Godavari basin oil and gas producing block KGDWN-98/3 or KG-D6. It could not find a buyer though. Last year, RIL had stated that the block oversight panel, called Management Committee, has reviewed the declaration of commerciality of gas find D-32 in the block. RIL in March 2013 had submitted a $3.5 billion Integrated Field Development Plan for producing 10 mmscmd of gas from the discoveries D- 32, D-40, D-9 and D-10 in NEC-25 by mid-2019.

Shell India, the operator of the Panna-Mukta-Tapti fields, a joint venture, has shelved its plan to sell its 30% stake in the Panna and Mukta oil fields. Panna and Mukta are oil fields while Tapti is a gas field located near ONGC’s Mumbai High complex. Shell and RIL hold 30% stake each in the PMT joint venture, while ONGC holds the remaining 40%. PSC for the PMT fields is scheduled to expire in December 2019 and the three partners have not applied for an extension of the same. During the third quarter of this fiscal, the Panna-Mukta fields produced 1.32 million barrels of crude oil and 15.2 billion cubic feet of natural gas, a drop of 10% in crude oil and 3% in natural gas on an on-year basis. The Tapti field is being abandoned due to a significant drop in reserves. It will be the first offshore field to be abandoned in India.

A 5 mtpa LNG import terminal at Mundra in Gujarat state on the west coast of India, part owned by the Adani Group, will likely be operational in April or May. The terminal will have receiving, storage and re-gasification facilities for LNG and will be connected to Gujarat State Petronet’s existing pipeline network at Anjaar, Gujarat. Construction on the terminal is completed, but Adani is unable to commission operations due to issues with a 90 km section of pipeline, executive director of the company’s LNG and LPG division. Adani’s plans are in line with a broad push in India to more than double the share natural gas has in the country’s energy mix to 15 percent by 2022. India has four LNG terminals now and imports around 20 mt of the super-chilled fuel a year, but the government plans to build another 11 terminals over the next seven years.

Petronet LNG Ltd, India’s biggest importer of gas, and its Japanese partners will invest $300 million to set up Sri Lanka’s first LNG terminal near Colombo. The Indo-Japanese partnership will set up a 2.6-2.7 mt a year floating LNG receipt facility off the island’s western coast, bigger than the previously envisaged 1.5-2 mt a year facility. Petronet will hold 47.5 percent stake in the project while Japan’s Mitsubishi and Sojitz Corp will take 37.5 percent stake. The remaining 15 percent will be held by a Sri Lankan entity. Explaining the reasons for setting up a bigger capacity LNG terminal, he said Sri Lanka requires 2.5-3 mt of liquid gas to fire power plants. Sri Lankan government had in September last year issued a Letter of Intent to the company to build a floating LNG import facility to supply gas to power plants and the transport sector in the island nation. The import terminal is to be set up at Kerawalapitiya on the west coast. The terminal in Sri Lanka is part of Petronets vision to own 30 mt per annum of LNG import and regasification capacity by 2020. Petronet already operates a 15 mt per annum import facility at Dahej in Gujarat and has another 5 mt terminal in Kochi in Kerala. It has signed preliminary agreement to build a 7.5 mt LNG terminal in Bangladesh and is also looking at setting up a smaller facility in Mauritius. Dahej is also being expanded to 17.5 mt over the next two years. The India-Japan collaboration comes after a string of Chinese successes in Sri Lanka.

GAIL incorporated in August 1984 by spinning off gas business of ONGC, GAIL owns and operates about 11,000 km of natural gas pipelines in the country. It sells around 60 percent of natural gas in the country. In 2006, the Government issued the Policy for Development of Natural Gas Pipelines and City or Local Natural Gas Distribution Networks. Also, the policy and the provisions of the PNGRB Act, 2006 provide for all entities authorised to lay pipelines including GAIL to provide mandatory open access to their gas pipeline infrastructure on common carrier principle at non-discriminatory basis. At present, GAIL has about 11,000 km long gas pipeline network and is also developing about 3,500 km long pipelines projects in the country.

GAIL has placed an order worth ₹ 4.4 billion for laying 350 km pipeline from Vijaipur in Madhya Pradesh to Auraiya in Uttar Pradesh. The company said this is part of the spurline of 665 km from Vijaipur to Phulpur in Uttar Pradesh to the existing upgradation pipeline system. The pipeline laying contracts for the 315 km stretch from Auraiya to Phulpur was awarded in November 2016. The Vijaipur to Phulpur pipeline will provide the gas feed to the ongoing 2,655 km long Jagdispur-Haldia-Bokaro-Dhamra Pipeline project of GAIL, also known as the ‘Pradhan Mantri Urja Ganga’ project. Chairman and Managing Director of GAIL BC Tripathi, also said that all of GAIL’s group companies have made detailed plans for expansion of City Gas Distribution infrastructure in coming years.

The downstream regulator is reworking city gas licensing rules, readying to launch 100 new city gas distribution licences, and cut myriad litigations it’s been caught in with gas companies, to rebuild itself into a more effective and credible watchdog that can help country achieve its target of raising the share of natural gas in the energy mix from 6% to 15% by 2030. PNGRB has often been criticised in the past for less than optimal rules needed to support the development of the gas sector in the country. PNGRB will announce the names of 100 more districts for which it intends to award licences. The choice of districts will be such that more highways have gas coverage, making inter-city commute for CNG vehicles possible, he added. So far only 91city gas licences have been awarded in the country, including 14 delivered in the last one month. Before the auction for 100 new licences are launched by March, PNGRB plans to rework bidding norms, hoping to plug the loopholes in the existing rules often blamed for poor growth of city gas. As per the draft guidelines, open to stakeholder consultation, winner will be chosen on the basis of the number of consumers connection and CNG stations, and the length of gas pipeline bidders promise to achieve in a given time frame.

After “one paisa” bids spoilt the initial auction rounds, oil regulator PNGRB has proposed to radically change the bidding parameters for obtaining a licence to retail CNG and piped cooking gas in cities. The PNGRB has proposed to conduct future auctions by asking companies to quote the tariff they will charge for transportation of CNG and piped natural gas or PNG within the city, with lowest rate getting preference. They would also be asked to quote the number of CNG stations and households proposed to be connected within a given timeframe, according to PNGRB. Besides, bidders will also have to quote how much pipeline would they lay on winning the licence. PNGRB has so far held eight rounds of bidding where companies were asked to quote the tariff for pipeline that carries gas within the city limits. This bidding criteria did not include the rate at which an entity would sell CNG to automobiles or piped natural gas to households using the same pipeline network, leading to companies offering one paisa as tariff to win licences. PNGRB in the notice invited comments on the draft bidding regulations by February 2 after which it will finalise the criteria.

Rest of the World

BP expects gas to overtake oil as the world’s primary energy source in around 2040 as demand for the least polluting fossil fuel grows. Emery highlighted estimates for demand growth for gas in China of around 15 percent year-on-year last year and said BP expects overall gas demand to grow around 1.6 percent a year for years to come, compared with 0.8 percent for oil. In terms of demand for gas from different sectors, industry is especially resilient and transport is fast-growing, albeit from a low base, at annual rates of three to four percent. BP is due to reveal more details in its next energy outlook on February 20. In its last outlook it said it saw gas overtaking coal’s share in the primary energy market to become the second-largest fuel source by 2035. BP’s previous forecast to 2035 forecast oil’s share shrinking from around 33 percent to around 30 percent and gas’ share grow from the low 20s to the mid 20-percentage range. One of the biggest challenges for the gas industry was reducing methane leakages from pipelines, which he said was estimated at around 1.3 to 1.4 percent.

BP has commenced gas production from the $1 bn Atoll phase one field offshore Egypt, seven months ahead of schedule. Located in the North Damietta Concession offshore Egypt in the East Nile Delta, the Atoll field was discovered by BP in March 2015. It is being developed in phases. BP estimates the Atoll field’s main reservoir to hold 1.5 trillion cubic feet of natural gas and 31 million metric barrel of condensates. The project, which is now producing 350 million cubic feet of gas a day and 10,000 barrels a day of condensate, was delivered 33% below the initial cost estimate, BP said. The Atoll Phase One involved the recompletion of the original Atoll exploration well to a producing well as well as drilling of two more production wells. Production from the Atoll gas field is being exported to the existing onshore West Harbor gas processing plant. Located offshore on the border between Mauritania and Senegal, the Tortue/Ahmeyim gas field is estimated to contain 15 trillion cubic feet of gas resources.

Cheniere Energy Inc said LNG production from its Sabine Pass export plant in Louisiana will not be affected following an order to shut two cracked storage tanks that leaked the super-cold fuel. The US Department of PHMSA ordered Cheniere to shut two LNG storage tanks after plant workers discovered a one-to-six foot long crack at one tank that leaked the fuel into an outer layer. The order comes as Cheniere is preparing to expand another LNG export facility at Corpus Christi in Texas that is under construction after signing a multi-year deal to sell fuel to a company in China. During the investigation of the Sabine site, PHMSA discovered a second tank had also experienced releases of LNG from the inner tank, raising the possibility that similar leaks may have occurred in multiple tanks, it said. Cheniere’s Sabine Pass terminal in Louisiana is currently the only big LNG export facility operating in the country. Several other companies are building other trains at six sites which is expected to make the United States into the third biggest LNG exporter by capacity in 2018.

Russia’s oldest natural gas buyer is ready to break up after more than 74 years. Poland, which relies on Kremlin-controlled Gazprom PJSC for about two-thirds of its gas, says diversification trumps potential price cuts it could leverage from building an import link to access Norwegian fuel. That comes after the eastern European nation in 2016 completed a liquefied natural gas terminal to diversify away from the Russian gas it’s been buying since 1944. Poland is also vying with Gazprom over the Russian company’s plan to expand its Baltic Sea gas pipeline to Germany, called Nord Stream 2. Poland argues that the project would make countries like Ukraine more vulnerable if Russia decided to shut down gas links running across its territory to western Europe. PGNiG gets 10 bcm a year under the Gazprom contract. It doubled its LNG purchases from Qatar as of this year to about 3 bcm and signed a mid-term deal for US deliveries. The LNG terminal’s capacity is set to rise 50 percent to 7.5 bcm a year after 2020. At the same time, the Polish company committed to transit 8.78 bcm a year via the Baltic Pipe when it starts. Additionally, the country produces more than 4 bcm of its own gas a year and in order to export an excess it may have post-2022 it’s building links with neighbouring countries including Slovakia, Lithuania, the Czech Republic and Ukraine.

The Nord Stream 2 pipeline project has received a permit for construction and operation in German territorial waters and the landfall area around eastern Germany’s Lubmin, the project’s operator said. Nord Stream 2 said it has fulfilled all requirements and expects permits to be issued by other countries in time for construction to begin as scheduled in 2018. Nord Stream 2 would double the existing Nord Stream pipeline’s current annual capacity of 55 billion cubic meters. Nord Stream runs on the bed of the Baltic Sea from Russia to Germany.

Mozambique’s council of ministers approved the development plan for Anadarko Petroleum Corp’s LNG project in the north of the nation, an investment estimated at about $20 billion. Anadarko and its partners have agreed the price and volumes for 5.1 million metric tons a year of gas production, out of the 8.5 million tons required to reach financial close, the company said. During the last quarter of 2017, it signed an agreement with Tohoku Electric Power Co. of Japan to sell it gas. Anadarko said it’s already started resettling communities from the land where it plans to build its LNG plant. Exxon Mobil Corp and Eni SpA are developing another gas project near Anadarko’s. The development of Mozambique’s gas deposits could make the southeastern African nation the world’s fourth-biggest natural gas exporter.

Croatia will pass a special law to speed up the construction of a LNG terminal in the northern Adriatic. Croatia produces more than half of its gas consumption, some 2.5 bcm a year. Once the LNG terminal is built it hopes to be able to supply both its own market as well as central and eastern European countries. The European Union has decided to put the floating LNG terminal on the island of Krk on its list of projects of common interest since it wants to diversify sources of supply and reduce dependence on Russian gas. Brussels will invest € 101.4 million, or 28 percent of the project’s assessed value. Croatia aims to bring a final investment decision this year and plans to make the terminal operational in early 2020. Croatia’s plan is to construct a terminal with an initial capacity of 2.6 bcm of gas a year, which could be gradually expanded to as much as 7.0 bcm a year.

China announced retroactive adjustments in reference prices for importers to use as a base for tax rebates, part of a long-standing policy started in 2011 to give importers some respite on tax payments. Reference prices for LNG will be set at 26.64 yuan ($4.21) for each Joule (GL), retroactive from October 1 of last year, and pipeline gas at 0.94 yuan per cubic metres, according to the finance ministry. Between July and September last year, LNG reference prices were set at 27.49 yuan per GL and pipeline gas at 0.97 yuan per cubic metre.

Tehran is ready to file a case with the International Court of Arbitration over the quality and price of gas it receives from Turkmenistan, the Iranian oil minister said, as a dispute between the two nations over payments escalates. The Central Asian nation stopped gas exports to Iran in January 2017, saying it was owed $1.5 billion to $1.8 billion for gas it had delivered to Iran. Iran, which disputes the claim, has imported Turkmen gas since 1997 to supply its northern region, especially in winter, even though it has large gas fields in the south of the country. Iran was ready to take the dispute over price to the International Court of Arbitration. The National Iranian Gas Company had said in December that Tehran would prefer dialogue to resolve the disputes rather than resorting to international arbitration.

Bangladesh signed an agreement with Indonesia to import LNG as the South Asian country turns to the supercooled fuel to fill a shortfall of domestic natural gas. A letter of intent was signed between two state energy companies, Petrobangla and Pertamina, after a meeting between Prime Minister Sheikh Hasina and Indonesian President Joko Widodo. Bangladesh, a country of more than 160 million people, may import as much as 17.5 mt of LNG a year by 2025, as its domestic gas reserves dwindle and demand grows. Petrobangla is finalising several floating storage and regasification units, the first of which is expected to commence operations in April 2018.

JAPEX said it would book an impairment loss of $608 million on its shale gas project in Canada in the October-December quarter. The loss will hurt its net income in the April-December period by $311 million, but the company is still assessing an impact on its full-year earnings, JAPEX said.

Iraq agreed a deal with US energy company Orion to process natural gas extracted at its giant Nahr Bin Omar oilfield. The memorandum of understanding, signed in Baghdad by representatives of the oil ministry and the US company, will allow Orion Gas Processors to build facilities to capture the gas from the field located in southern Iraq and to transform it into usable fuels. Nahr Bin Omar, operated by Basra Oil Company, is producing more than 40,000 bpd and 25 million cubic feet a day of natural gas. Iraq continues to flare some of the gas extracted alongside crude oil at its fields because it lacks the facilities to process it into fuel for local consumption or exports. Orion will capture and process 100 million to 150 million cubic feet/day of gas. The gas captured will be used to feed power stations and to produce up to 10 million liters of gasoline, equivalent to 32 percent of Iraq’s total imports of the fuel, he said. Gas flaring across Iraq should end by 2021.

Woodside Petroleum expects to reveal plans for expanding its prized Pluto LNG project and connecting it to the North West Shelf LNG complex soon. Talks with the owners of the Scarborough gas resource off Western Australia, led by ExxonMobil Corp, as well as drilling of an exploration well, Ferrand-A, around March, and other tie-ins could help underpin the expansion. Some analysts had speculated that recent drilling disappointment on Woodside’s Swell exploration well could limit any expansion. Woodside said that it has looked at a range of options for expanding Pluto LNG by up to 1.5 mt a year. Pluto, Wheatstone – run by Chevron Corp – and the North West Shelf, Australia’s biggest LNG plant – run by Woodside – are all candidates for processing gas from a number of undeveloped assets off Western Australia, either for expansions or for supplying gas when their existing fields dry up. Woodside is still targeting growth in Myanmar, where it discovered gas last year and expects to drill three wells this year, starting around March or April, even amid a humanitarian crisis involving Rohingya refugees.

LNG: liquefied natural gas, mt: million tonnes, CNG: compressed natural gas, IGS: India Gas Solutions, RIL: Reliance Industries Ltd, mmscmd: million metric standard cubic meter per day, KG: Krishna-Godavari, ONGC: Oil and Natural Gas Corp, mtoe: million tonnes of oil equivalent, HPCL: Hindustan Petroleum Corp Ltd, MRPL: Mangalore Refinery and Petrochemicals Ltd, FSU: Floating Storage Unit, OAL: Open Acreage Licensing, EoI: Expressions of Interest, mtpa: million tonnes per annum, km: kilometre, UK: United Kingdom, PMT: Panna-Mukta-Tapti, PSC: Production Sharing Contract, PNGRB: Petroleum and Natural Gas Regulatory Board, PHMSA: Pipeline and Hazardous Materials Safety Administration, US: United States, bcm: billion cubic meters, JAPEX: Japan Petroleum Exploration Company Ltd

Courtesy: Energy News Monitor | Volume XIV; Issue 37


Over-Supply in Global Coal Market is an Opportunity for India

Ashish Gupta, Observer Research Foundation

Rising import of coal is a cause for concern especially on account of increasing current account deficit. There have been many warnings from expert observers that coal imports will accentuate India’s delicate position. Given the prevailing coal shortages and the recent Supreme Court ruling, coal imports are likely to increase.  Will such an increase be detrimental for India?

Coal Import Bills
Coal Imports ($ Bn)
Source: Department of Commerce, Ministry of Commerce and Industry, Govt. of India

India will be importing coal from various coal exporting countries like Australia, Indonesia, and South Africa but India’s vulnerability is decided by coal prices in the global coal market. Though India and China are considered as major coal markets, India does not decide the price in the global coal market. It is China which will continue to set coal prices in the near future.

China remains the world’s largest market for imported coal with increase in coal demand of around 5.3 percent (196 Mt) for the period up to 2019. This growth rate was substantially lower compared to its ten-year average of 9.7 percent. Despite a growth of 4.1 percent over 2012 coal prices are low in the global coal market. This is due to China growth which is now projected to grow at 7 percent compared to previous years when it was growing at the rate of 9 – 9.6 percent. Apart from this development China is overproducing coal indigenously and therefore coal suppliers in China are selling coal at discounted rates to maintain market share giving no room for any arbitrage opportunity to imported coal. China is now looking for coal with less ash content and so inclined more towards Australian coal market rather than Indonesian coal. This shift has affected Indonesian coal suppliers negatively. Indonesia has increased its coal production capacity to export from approximately 57 Mt in 2000 to 426 Mt in 2013. The share of exports in overall production rose from approximately 72 percent in 2000 to 88 percent in 2013, as domestic coal demand grew only at 8.1 percent per year whereas production increased by 15 percent and exports by 16.8 percent. Therefore if China mostly consumes only internal production and limits the extent of import coal from Australia, then the coal prices in the global market will go down further.

As per IEA’s medium term coal market report 2014, India’s coal demand will grow at around 4.9 percent per year till 2019 compared to China which will grow at round 2.6 percent per year during the same period. A caveat is required that this report was prepared before important developments in India’s coal sector. The recent Supreme Court ruling is one of such incident which changes the coal dynamics all together in India. Apart from this India’s economic growth has come down from 8.5 percent to around 5 percent which puts a downward pressure on electricity demand. Large projections for new power plants need a relook. Given the current dilemma over the policy framework in the coal sector, these new plant capacities may not come online and consequently reduce coal demand in the country. However in the answer given by the Power Minister (to starred question no. 203) on 8th December, 2014 at Rajya Sabha that that ‘in view of the negative coal balance reported by subsidiary coal companies of CIL, new linkages/Letters of Assurance (LoA) have not been granted to any of the sectors since 2010 and there is no proposal to provide fresh coal linkages to private companies for new and upcoming projects’ reflects a deficit scenario. India will therefore be importing coal but since coal is in over supply in the global coal market, the prices will be generally low. Many of the large coal producers in Indonesia are expecting to raise coal production further to achieve further economies of scale. This production if not absorbed in China has to be absorbed by India to some extent but not at a high price. A positive development for India is that it gets some breathing space before it can increase domestic coal production through appropriate policy. Effective utilization of power generating capacity is also a key issue for India as utilization stands at 50 percent currently. Irrespective of whether India reaches the target of 1 billion tonnes of coal production by 2019, India now is now looking at a much better global market, if it has to import coal.

Views are those of the author                    

Author can be contacted at ashishgupta@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 32


Monthly Oil News Commentary: January – February 2018


As the crude oil prices rise, the government may ask upstream firms like ONGC to bear a part of the kerosene and LPG  subsidies, India Ratings and Research said. Producers ONGC and OIL as well as gas utility GAIL (India) Ltd were in past asked to bear between one-third to half of the under-recovery fuel retailers incurred on selling LPG and kerosene below market rate. This subsidy sharing scheme ended last fiscal. India Ratings said given the sharp increase in international crude price, oil marketing companies may be required to bear a part of the under-recoveries. This would be on the lines of past when the government capped the subsidy burden it was willing to share per kilogram and per litre on LPG and kerosene, respectively. Any under-recovery over and above the level up to which the government can bear is to be borne by upstream and oil marketing companies, it said.

The Indian crude oil basket comprises 73 percent sour-grade Dubai and Oman crudes, and the balance in sweet-grade Brent, closed December 2017 at $62.29/bbl according to the oil ministry.  The government remained non-committal on cutting excise duty on petrol and diesel to reduce retail prices. Petrol and diesel prices in India are to a “large extent” aligned to international rates, IOC said in response to the charges of government meddling in fixing of fuel prices. The prices are revised daily based on 15-day rolling average rate of their international benchmark.  The prices at petrol pumps of state-owned fuel retailers like IOC were cut by 1-3 paisa every day in the first fortnight of December. They started moving up immediately after polling for assembly elections in Gujarat concluded, leading to speculation that government may have asked oil companies to hold on to the prices. State-owned oil companies in June last year dumped the 15-year old practice of revising rates on 1st and 16th of every month and instead adopted a dynamic daily price revision to instantly reflect changes in cost. Crude oil, natural gas, diesel, petrol and ATF have not been included in the ambit of GST as of now. The CII said till such time that the five are included in GST, C Form should be continued to avoid high tax incidence on these products. As per the earlier provisions of CST Act, a purchaser can make the interstate purchase of the non-GST goods by availing concessional central sales tax rate of 2 percent against Form-C. Hitherto, fertiliser manufacturers, power producers, automobile manufacturers and other industries were buying natural gas and other petroleum products by paying CST of 2 per cent against Form-C. The central government vide Taxation Laws Amendment Act 2017, amended the definition of ‘Goods’ under the CST Act to include only crude petroleum, diesel, petrol, ATF, natural gas and alcoholic liquor for human consumption. This meant that fertiliser companies are not eligible for C Form as the gas is used to manufacture urea and not for manufacture of natural gas. Likewise, automobile manufacturers are not eligible for C Form for inter-state purchase of diesel, petrol or natural gas, which they have to mandatorily fill in the tanks of new vehicles. The industry association said post GST, since Form-C is not available for inter-state purchase of goods and so the extra tax burden will be shifted to the consumer. It suggested that petroleum products, natural gas, electricity, alcohol and real estate should be covered under GST. Alternatively, since VAT is non-creditable tax, VAT rate should be reduced to 4 percent or lower which was the effective rate when credit on VAT was available before July 1.

The Chief Economic Advisor called for petroleum products to be brought under the ambit of the GST. He also made a case for one rate under the GST for all goods and services down the line. Petrol and diesel prices rose to a three-year high across metro cities. Petrol prices in the national capital were at ₹ 72.49/litre, the highest in over three years. Petrol prices in Kolkata, Mumbai and Chennai were at ₹ 75.19, ₹ 80.39 and ₹ 75.18/litre respectively — all three-year highs. Similarly, diesel prices have also been hitting record levels.

The October 2017 excise duty cut cost the government ₹ 260 billion in annual revenue and about ₹ 130 billion during the remaining part of the current financial year that ends on March 31, 2018. The government had between November 2014 and January 2016 raised excise duty on petrol and diesel on nine occasions to take away gains arising from plummeting global oil prices. Just 4 states and one union territory have cut local sales tax or VAT on petrol and diesel since the October 2017 decision of the Centre to reduce excise duty on the two fuels. As petrol and diesel prices soared to a three-year high, the Centre on October 3, 2017 reduced excise duty on petrol and diesel by  ₹ 2 per litre each and asked states governments to match it with a cut in VAT.  The states which reduced VAT following the October 3, 2017 cut in excise duty were Maharashtra, Gujarat, Madhya Pradesh and Himachal Pradesh. The Centre has cut excise duty only once in October 2017 but raised excise duty on nine occasions to take away benefits of sliding international oil prices between late 2014 and January 2016. Prices of petrol and diesel were ‘freed’ from administrative control from June 26, 2010 and October 10, 2014, respectively.

India has the highest retail prices of petrol and diesel among South Asian nations as taxes account for about 40-50 percent of the pump prices. Petrol and diesel account for about half of India’s refined fuel consumption. A cut in excise duty on petrol and diesel in the budget, due to be unveiled on February 1, would pose challenges as the government is struggling to tackle a widening fiscal gap amid falling tax revenues due to the implementation of a GST regime from July. In 2016/17, the petroleum sector contributed around ₹ 5.2 trillion ($81 billion), about a third of total revenue receipts, for federal and state finances. India raised excise duty nine times between November 2014 and January 2016 to shore up federal finances as global oil prices fell, but then cut the tax last October by ₹ 2/litre. The ministry has also sought inclusion of petrol, diesel, jet fuel and natural gas in the GST to help companies claim tax credits against the tax paid on the purchase of equipment meant to produce refined fuel. The oil ministry said the addition of refined products in GST will help reduce retail prices even if the government levies a charge on top of its highest GST rate of 28 percent. The ministry has also sought federal support for laying fuel and gas pipelines in the northeast of the country to give the region a boost. Economic development in India has largely been concentrated in the western and southern states that have better infrastructure and more accessible energy supplies.

States are not in favour of including petrol and diesel into GST at the moment, ruling out any immediate levy of the new indirect tax on these petroleum products. While GST was rolled out on July 1, real estate as well as crude oil, jet fuel or ATF, natural gas, diesel and petrol were kept out of its purview. This meant that the products continued to attract duties like central excise and VAT. The five petroleum items have been kept out of GST as they are considered cash cows, giving both the Centre and states bulk of their tax revenues. But keeping them out has created compliance issues including taking input tax credit.

ONGC completed the acquisition of government-owned fuel retailer HPCL through an all cash deal worth ₹ 369.15 billion, the company said. The company had tied up ₹ 350 billion with seven banks including three private and four public sector banks to fund the acquisition. While ONGC has secured loans for ₹ 350 billion through banks, the details of funding the rest of the acquisition amount, ₹ 19.15 billion, are not in public domain. The combined market value of ONGC and HPCL is estimated to be around ₹ 3119.25 billion, or $49 billion, comparable with Russian energy giant Rosneft’s $61 billion. The acquisition of HPCL by ONGC has paved the way for the country’s first vertically-integrated oil major. As per the government, the ONGC-HPCL merger is an innovative vertical economic integration of companies being done with a motive that goes beyond mere financial consideration. The aim behind the move was not just financial consideration and that the merger decision was taken considering the price volatility in the oil and gas industry which created the need for a company which could cushion the shocks of oil prices. The government has set a disinvestment target of ₹ 725 billion for the financial year 2017-2018, of which ₹ 543.37 billion has been raised so far. India Ratings said ONGC’s acquisition of HPCL will be credit neutral for ratings of HPCL. ONGC, which is 68.94 percent owned by the government, will acquire the government’s 51.11 percent stake in HPCL for ₹ 369.15 billion. Despite the change in ownership, HPCL will continue to operate as a separate entity with a strong brand. Its strategic importance to the government is likely to remain intact, given the company’s role as the State’s extended arm for fuel policy implementation. It could use one or more of the three sources for funding, fresh debt, cash and cash equivalents, and monetisation of its stake in entities such as GAIL, IOC and Petronet LNG Ltd. The combined value of its stake in the three entities is about ₹ 344 billion. For HPCL, the acquisition may result in some synergies in crude oil procurement with Mangalore Refinery and Petrochemicals Ltd, which is 71.63 percent owned by ONGC. HPCL, along with HPCL-Mittal Energy Ltd and MRPL, represented 15.3 percent of India’s total crude import volume of 249 mt. Also, HPCL may be able to capitalise on ONGC’s petrochemical expertise while expanding its footprint in the segment. The combined entity would be the third-largest refiner in India, with a refining capacity of 43.1 mt behind IOC’s 80.8 mt and RIL’s 62 mt. India Ratings said HPCL may have to resort to additional borrowings in case it was to acquire ONGC’s stake in MRPL for cash. ONGC’s stake in MRPL is worth ₹ 164 billion. ONGC-HPCL deal is unlikely to alter government subsidies for kerosene and LPG.

The government’s plan to farm out a 60 percent stake in about 15 fields of ONGC and OIL to private players might lead to a dual system of contracts. The two state-owned companies may have to continue to pay royalties and cess. This is a major dilemma before the policymakers as to whether two parties can have separate sets of contracts for the same fields. The Directorate General of Hydrocarbons has reportedly zeroed in on 15 fields, 11 of ONGC and four of OIL, including ONGC’s four major oilfields in Gujarat like Kalok, Gandhar, Santhal, and Ankleshwar. These 15 are estimated to have a cumulative reserve of 791.2 mt of crude oil and 333.46 bcm of gas. The plan to rope in private companies is part of the government’s production enhancement policy. However, the government is yet to come up with a Cabinet note in this regard. More than 40 fields of state-run producers have been identified for production enhancement through the technical services model.

The government virtually ruled out giving statutory powers to upstream oil and gas regulator DGH saying the sector has not fully developed and needs government support. There are two regulatory bodies in the oil and gas sector – the Petroleum and Natural Gas Regulatory Board, which is a regulator for the downstream activities like laying of pipelines and fuel marketing but without powers to review pricing. The DGH is a technical arm of the oil ministry which overseas upstream oil and gas exploration and production activities. Various committees have suggested creation of an independent, statutory regulator for the upstream oil sector. He said the sector has not developed fully and still looks at the government for reforms. In 2013, a committee, headed by former finance secretary Vijay Kelkar, had recommended hiving off the DGH’s financial oversight function and vesting it with the income tax authorities. The DGH currently manages petroleum resources besides monitoring PSCs, and assists the government in auctioning oil and gas exploration fields. In 2011, a panel led by former finance secretary Ashok Chawla advised the government to turn the DGH into an ‘independent technical office’ attached to the oil ministry and establish an upstream regulator to focus on regulatory functions. It also said the reconstituted DGH as well as the regulator must not have staff on deputation from regulated firms. A similar panel had in 2001 recommended the setting up of an Upstream Hydrocarbon Regulatory Board, giving DGH a techno-administrative role as a part of the oil ministry.

India was scheduled to lift its biggest volume of Iranian crude in nine months in December, helping to shore up the OPEC producer’s oil exports to Asia last month. Asian buyers were scheduled to lift 1.92 million bpd of Iranian crude in December, down 7 percent from the actual loadings in the previous month. India’s scheduled crude oil loadings from Iran, excluding condensate, an ultra-light oil, were about 550,000 bpd last month, up 78 percent from the previous month and the highest since March.

State oil companies have planned a capital spending of ₹ 890 billion ($14 billion) in 2018-19, half of which will go into E&P. In the current fiscal, these companies had targeted an expenditure of ₹ 874 billion, 70% of which has been spent in the first three quarters. The allocation of ₹ 480 billion towards exploration and production in Budget 2018-19 is lower than ₹ 539.6 billion planned for this year. Spending on refining and marketing would rise to ₹ 358 billion from ₹ 312 billion in 2017-18. Investment in petrochemicals would nearly double to ₹ 39.52 billion next fiscal year from ₹ 21.56 billion in the current year. ONGC has planned the highest investment among all state oil firms, with a capex target of a little over ₹ 320 billion in 2018-19. This would go into developing new oil and gas fields and enhancing production from existing fields. For the current year, its planned capex is about ₹ 372 billion, including a $1.2 billion payment for GSPC’s stake in the KG Basin asset. ONGC’s capex figure will get revised upward sharply after factoring in the ₹ 370 billion purchase of government stake in HPCL.

Saudi Aramco, the state oil company of Saudi Arabia, is considering entering India as part of its Asian expansion. The Saudi government has said it plans to sell about 5 percent of Aramco, hoping to raise some $100 billion or more in what would likely be the world’s biggest initial public offer.

Kochi crude oil refinery in Kerala, operated by fuel retailer BPCL has completed its expansion project to become the largest public sector refinery in the country, surpassing the capacity of Paradip and Panipat refineries operated by the largest retailer IOC. BPCL completed the ₹ 165 billion Integrated Refinery Expansion Project (IREP) at Kochi in October last year, ramping up the capacity of the unit to 15.5 mt from the earlier 12.4 mt. That compares with 15 mt capacity each of IOC’s Paradip refinery in Odisha and Panipat refinery in Haryana. The Kochi oil refinery processed 1.2 mt crude in December 2017 as compared to 1 mt processed in the corresponding month a year ago, data from the PPAC, an arm of the oil ministry, shows. India had a total installed crude oil refining capacity of 247.6 mt at the end of December 2017 including 69.2 mt operated by IOC, 36.5 mt operated by BPCL and 27.1 mt operated by the third state-owned retailer HPCL.

India will showcase its oil sector policy reforms and the investment opportunities at the 16th IEF Ministerial, slated for April in New Delhi, where scores of ministers, top officials and industry executives from across the globe are expected to participate. IEF, comprising 72 member countries, is one of the biggest global forum of oil and gas producers and is currently headed by Saudi Arabia. The Ministerial will be held from April 10 to 12. Ninety percent of the oil and gas producers and consumers would be represented at the event, which would therefore be a good opportunity to present India as an investment destination. The issue of ‘reasonable and responsible pricing’ and the long-standing Indian demand of junking the so-called Asian premium will also be discussed at the Ministerial. Oil consumers have become ‘more assertive’ and they will have a bigger say in the global oil market now, Pradhan said referring to how the global oil industry dynamics has changed over the years. A supply glut resulting in lower prices for the last three years has given heavy consumers like India and China a bigger say in the global markets.

The Jammu and Kashmir government said it has achieved a target of 75 percent in the implementation of Pradhan Mantri Ujjwala Yojana by LPG connections to 370,000 below poverty line households in the state. The females from BPL households were provided with sets of chulha, cylinder, gas pipe, regulator and safety manual.

India needs to increase its refining capacity to 600 million mt by 2040 to meet the rising demand for fuel. About $300 billion would be invested in next 10 years in energy and hydrocarbon sectors. India has decided to meet international best practices by leapfrogging to BS-VI norms by April 2020 in the entire country and by April 2018 in NCT Delhi. The government has planned to set up West Coast Refinery cum Petrochemical Complex of 60 mmtpa with an estimated investment of ₹ 2700 billion. Foundation stone for another grass root Refinery cum Petrochemical Complex in Barmer, Rajasthan with an investment of ₹ 43,000 billion was laid in January 2018.

Indian oil consumption in 2017 grew at its slowest in four years, according to government statistics, hit by the government’s demonetisation move and a tax increase that knocked the gain in fuel use back to a modest 2.3 percent. The low growth also coincided with another year of weak, albeit improving, new vehicle sales. India imports almost all of its oil, shipping in around 4.2 million bpd of crude in 2017, according to trade flow data. India saw some structural demand changes that affected the use of refined oil products. A government push for household to use more LPG has India challenging China as the world’s top LPG importer. For 2018, energy consultancy FGE expects India’s oil demand growth to improve to 4.3 percent. India’s slow oil demand growth has surprised many, given the country has often been touted as the next China in terms of rising oil consumption. If an Indian citizen with an average salary buys 10 gallons of gasoline per month, that would represent nearly 30 percent of the person’s income, while the average Chinese would fork out just 5 percent, data from statistics company Numbeo showed.

Rest of the World

Global oil markets are tightening quickly on falling supply from Venezuela, which posted 2017’s biggest unplanned output fall and could see a further decline in 2018, the IEA said. Debt and infrastructure problems cut Venezuela’s December output to 1.61 million bpd, somewhere near a 30-year low. That helped oil prices top $70 per barrel in early January, their highest level in three years. As a result of lower Venezuelan production, the IEA said OPEC’s crude output in December fell to 32.23 million bpd, boosting the group’s compliance with a deal to curb output to 129 percent. OPEC agreed to lower production in 2017 and has agreed to maintain output cuts for the whole of 2018 to help bring oil stocks in OECD industrialized countries down to their 5-year average. The IEA said that if OPEC and its non-OPEC allies maintained good compliance with the output deal, oil markets would balance in 2018. The recovery in oil prices and a decline in global oil stocks has been helped by robust global demand growth in 2017 but it will slow down in 2018, the IEA said. It kept its oil demand growth estimate for 2018 unchanged at 1.3 million bpd, down from 1.6 million bpd in 2017, mainly due to the impact of higher oil prices and changing patterns of oil use in China.

Goldman Sachs raised its Brent crude price forecasts, saying oil markets have rebalanced six months sooner than expected, citing steady demand growth and continuing compliance with OPEC -led supply cuts. The bank’s three, six and twelve-month Brent oil price forecasts were raised to $75, $82.50 and $75 a barrel respectively, from $62 previously. However, Goldman expects the price to dip again as US shale producers pump more oil to benefit from the price reaction to lower global inventories. Goldman sees a global oil market deficit of 0.2 million bpd in 2018, followed by a global surplus of 0.73 million bpd in 2019. Oil prices pared early gains to stay little changed as OPEC’s strong compliance with a supply reduction pact offset news that US production topped 10 million bpd for the first time in nearly half a century.

OPEC and non-OPEC oil producers have a consensus that they should continue cooperating on production after the end of 2018, when their current agreement on production cuts expires. If oil inventories increase in 2018 as some in the market expect, producers may have to consider rolling the supply cut agreement into 2019, but the exact mechanism for cooperation next year has not yet been decided.

In addition to the OPEC and non-OPEC production cuts of 1.8 million bpd that are due to last until the end of 2018, oil prices have found support from eight consecutive weeks of US crude inventory drops. US commercial crude stocks fell by almost 5 million barrels in the week to January 5, to 419.5 million barrels. That was slightly below the five-year average of just over 420 million barrels, the target for OPEC and others cutting output. But the IEA, warned that while oil prices at $65 to $70 per barrel are good for oil producers now, there IEA also said that there might be a further decline in oil production from OPEC member Venezuela in 2018 as its economic crisis hits output.

Surging shale production is poised to push US oil output to more than 10 million barrels per day – toppling a record set in 1970 and crossing a threshold few could have imagined even a decade ago. And this new record, expected within days, likely won’t last long. The US government forecasts that the nation’s production will climb to 11 million barrels a day by late 2019, a level that would rival Russia, the world’s top producer. US energy exports now compete with Middle East oil for buyers in Asia. Daily trading volumes of US oil futures contracts have more doubled in the past decade, averaging more than 1.2 billion barrels per day in 2017, according to exchange operator CME Group. The US oil price benchmark, West Texas Intermediate crude, is now watched closely worldwide by foreign customers of US gasoline, diesel and crude. Iraqi Oil Minister Jabar al-Luaibi said that the OPEC member’s oil output capacity is nearing 5 million barrels per day, but the country will remain in full compliance with its output target under a global pact to cut supplies. Luaibi said the supply cut agreement between OPEC and non-OPEC producers should continue despite a rise in oil prices. The deal between the OPEC and Russia to cut 1.8 million barrels per day of crude, which started in January 2017, is due to last until the end of 2018. Luaibi said current Iraq’s oil production is about 4.3 million barrels per day. Luaibi also said that his ministry plans to conclude three contracts with international gas companies by mid-2018 to utilize gas from Basra, Maysan and Nassiriyah southern provinces.

Mexico has raised the bar on oil contracts in Latin America after sweetening terms to attract international energy firms, luring $93 billion in future investment in the region’s first big auction this year. Mexico awarded 19 of 29 deepwater blocks onoffer, comfortably more than the seven areas expected to be assigned. Anglo-Dutch oil major Royal Dutch Shell emerged as the biggest winner, with nine blocks. Unique for generous terms such as setting a cap on royalties that oil firms can pledge to the government in bids, Mexico faces off this year with Brazil, Argentina, Ecuador and Uruguay. They will all hold auctions for oil and gas fields in 2018 that require billions of dollars in investment from foreign firms. Mexico is due to hold major auctions in March and July. While Brazil’s prolific deepwater presalt oilfields are expected to attract aggressive bidding from oil majors, other regional rivals could be forced to revise the terms of their auctions if Mexico scores another win in its next auction for shallow water areas in March, analysts said. Oil prices have reached three-year highs near $70 per barrel in 2018, giving the world’s top energy companies a cash boost and improving the chances that they will have the funds needed for big-ticket projects in Latin American. After the government of Mexico started auctioning oilfields in 2015, it tweaked the terms of the bidding process several times, following a historic energy reform that ended state oil firm Pemex’s 75-year monopoly over the sector. The liberalization, the most ambitious plank of President Enrique Pena Nieto’s economic policy, started just as oil prices crashed in 2013-2014.

State oil producer Saudi Aramco is expected to launch a tender in July to build facilities to expand its Marjan oilfield while another tender for the Berri oilfield expansion is expected by the third or fourth quarter of this year. The planned projects are further proof that Saudi Aramco is pushing ahead with oil investments to maintain capacity while also meeting domestic demand for gas to fuel industrial growth. International engineering and construction firms have expressed interest in bidding to build oil and gas facilities at Marjan oilfield whose development is expected to cost more than $10 billion. The expansion will increase the capacity of Marjan, currently at 500,000 bpd, by 300,000 bpd of Arab medium crude. A new gas plant in Tanajib which will handle 2.7 billion standard cubic feet per day is due to be built and the capacity of the NGL fractionation plant at Wasit will expand too. As for Berri, development could cost between $6-8 billion. Aramco plans to raise capacity at the field by 250,000 bpd of Arab light and raise production of associated gas. The construction packages for Marjan and Berri are expected to be awarded next year and both projects are expected to be completed in 2022.

China’s NDRC said it will launch a fresh crackdown on oil refiners that expand capacity without official approval, the latest sweeping move by Beijing to curb unfettered growth in fuel output and illicit oil trade. NDRC said it will close refineries with less than 2 mt per year (40,000 bpd) of capacity if they are found to violate regulations. The penalty for larger refineries will be to curb any expansion projects. Even so, China’s refineries have been churning out and exporting bumper volumes of diesel and gasoline, in a race for profits.

Russia held firm as China’s top crude oil supplier in December for the 10th month and racked up its second year as the No.1 supplier to China in 2017, the data from the General Administration of Customs showed, leaving rival exporter Saudi Arabia in second place once more. Shipments from Russia hit 5.03 million tonnes in December, down 0.2 percent from a year earlier, pushing up its full-year supply by 13.8 percent to 59.7 mt, or 1.194 million bpd. Saudi Arabia’s December shipments were up 31.7 percent from a year ago at 4.71 mt, or about 1.11 million bpd. Whole-year shipments from the Kingdom, OPEC’s top supplier, grew 2.3 percent to 52.18 million tonnes, or 1.044 million bpd, the data showed.

Russia’s Sakhalin-1 oil project, led by ExxonMobil, has ditched plans to raise output by a quarter this year after it was ordered by the authorities to return to previous lower production limits. Sakhalin-1 operates under a Production Sharing Agreement struck in the mid-1990s and all plans must be run by local government. ExxonMobil had received preliminary approval for a new quota in December and set output for January at 250,000 to 260,000 bpd, up from 200,000 bpd last year. But the firm was ordered by the authorities this month to return to the old quota of 200,000 bpd. Sakhalin-1 was now operating under the production quota of 200,000 bpd. Russia’s energy ministry said Sakhalin-1 would continue to operate under previous quotas until the Natural Resources Ministry finished approving a new production scheme. The withdrawal of approval for increased production meant Sakhalin-1 shareholders had to reduce their schedule for Sokol crude loadings for January-March. Under the original schedule based on a production rise, 13 cargoes of 95,000 tonnes each were to be loaded from the De-Kastri terminal on Russia’s Pacific coast in January, compared to nine in December, traders said. In February and March, Sokol crude exports had been set at 11 and 12 cargoes, respectively, traders said. After ExxonMobil was instructed to cut production, loading plans were decreased to 11 cargoes in January, nine cargoes for February and 10 cargoes for March, traders said.

ONGC: Oil and Natural Gas Corp, LPG: liquefied petroleum gas, OIL: Oil India Ltd, bbl: barrel, IOC: Indian Oil Corp, ATF: aviation turbine fuel, GST: Goods and Services Tax,   CST: Central Sales Tax, VAT: Value Added Tax, HPCL: Hindustan Petroleum Corp Ltd, mt: million tonnes, RIL: Reliance Industries Ltd, DGH: Directorate General of Hydrocarbons, PSCs: Production Sharing Contracts, bpd: barrels per day, E&P: Exploration and Production, GSPC: Gujarat State Petroleum Corp, PPAC: Petroleum Planning and Analysis Cell, IEF: International Energy Forum, IEA: International Energy Agency, OPEC: Organization of the Petroleum Exporting Countries, OECD: Organization for Economic Cooperation and Development, BPL: Below Poverty Line, NDRC: National Development & Reform Commission, US: United States

Courtesy: Energy News Monitor | Volume XIV; Issue 36

Auctioning Coal: Will it Clean the Stable?

Lydia Powell, Observer Research Foundation

In a recent interview on coal block auctions, the Minister of State for Coal has said that he had ‘inherited a mess’ and that his mission was to ‘clean the stable’.[1] In the same interview, the Minister has implied that some parties could be hurt and that justice could also be compromised but that all this would be a price worth paying to ‘clean the stable’. The Minister was probably referring to the ‘mess’ caused by the Supreme Court ruling in August 2014, or more correctly the mess caused by Government policy (not just those of the previous Government) rather than the larger mess that coal sector is seen to be in.

The idea of auctioning coal blocks was introduced through an Amendment to the 1997 Mines and Minerals (Development & Regulation) Act in 2012. As per the said Amendment, ‘the grant of reconnaissance permit or prospecting licence or mining licence in respect of an area containing coal or lignite can be made only through auction by competitive bidding even among the eligible entities’.  The sensational report of the Comptroller and Auditor General of India (CAG) on ‘Allocation of Coal Blocks and Augmentation of Coal Production’ for the year ending March 2012 brought this provision into the limelight.  It argued that the delay in introducing competitive bidding for coal blocks to captive users of coal in the power, cement and steel sectors had ensured continuation of undue benefits to private coal block alottees.  The report estimated that financial gains to the tune of Rs 1.86 trillion or roughly $ 30 billion could have accrued to the national exchequer if the decision taken in 2012 to introduce competitive bidding for allocation of coal blocks had been implemented.  The CAG arrived at a value for the potential monetary loss to the Government on the basis of average cost of production and average sale price of coal from opencast mines of CIL in the year 2010-11.

The methodology used by the CAG has been criticised by many observers.  However, the popular media latched on to the ‘mediagenic’ quality of the allegation that the public exchequer had potentially lost Rs 1 trillion and framed the discourse as one of graft arising from the nexus between politics and business.  In reality, the original sin (allocating coal blocks rather than auctioning them) does not appear to have been the result of pre-meditated graft.

As observed in a 2012 paper by ORF, allocations of coal blocks began in the early 1990s when Coal India Limited (CIL) was asked to prepare a list of coal blocks which CIL was not likely to need in the next 50 years.[2] These blocks were to be allocated to end users of Coal by a Steering Committee set up for allocating coal blocks comprised of State and Central Ministries and CIL.  In the early years about half a dozen blocks were said to be allotted to the applicants who were all associated with well-known independent power projects (IPPs). It was a time when blocks were chasing projects rather than projects chasing blocks as one expert put it.  IPPs preferred coal supplied by CIL rather than having their attention diverted to an extraneous activity like mining. In this period it would have been irrational to auction coal blocks because the demand for mining leases was less than that of supply. This changed as the private sector entered into power generation in a big way following the Electricity Act of 2003. The established method of allocating coal to power generators failed to keep up with the pace with which thermal power plants were being set up.

In 1991-91, installed power generation capacity by the private sector was 2.5 GW or 3 percent of the total.  It has increased to over 78 GW or 33 percent of total installed capacity in 2014, which gives a compounded annual growth rate (CAGR) of about 16 percent.[3]  In the same period CAGR of domestic coal production was about 3.4 percent.[4]  If we are blind enough to look narrowly at these two figures, it would be easy to assign blame on the inefficiency of the coal industry and its monopolistic structure.  However a more rounded and balanced analysis would suggest that the blame could be assigned to policy makers who failed to note that a push to open the flood gates for power generation should be accompanies by a similar policy push for fuels.  After all, power generation and fuel production are just parts of a long continuum.

Returning to statements by the Minister, auctioning of coal is unlikely to clean the stable as the stable in question is only part of this long continuum. It could however introduce an element of competition in the sector; it could also change the dominant rationality in coal production from one of administrative planning to one of commerce. However, auctioning of a set of coal blocks is in no way a match for policy adrenalin that continues to be injected into the power generation side (possibly driven by private sector lobbying).  In fact much of the pressure on coal production is the consequence of the rush of adrenalin in the power generation side.  Private investors rushed to install capacity without conducting even basic analysis on growth of fuel supply and growth in power demand which would have been standard practice for investment in any other industrial sector. These power sector investors are now pressing policy makers to find ways to monetise their so called ‘stranded assets’.  Given that private sector concerns are the only concerns that matter today, the Government is rushing to lend a helping hand.

Cleaning the stable is part of this rush but once again, but the Government seems to be overlooking the fact that power generation is just one part of the continuum that begins at the coal mine and ends in the homes, offices, trains and factories of consumers through transmission and distribution networks. As of today production of fuels (coal) and generation of power are the only parts of the continuum that are profitable.  Transmission and distribution continue to lose money. 90 percent of the accumulated losses in the power sector (which amount to about 1 percent of GDP) are on account of losses at the distribution end.  In fact losses at the distribution end have been growing at a CAGR of 9 percent since 2003, the year in which the Electricity Act was introduced. These losses will continue to exert pressure on other parts of the continuum, including the Coal Minister’s stable.

The idea that there is limitless unmet demand for electricity in India justifies a dramatic increase in coal production is also questionable.  27th of August 2014, which recorded the highest demand for electricity last year required only 122 GW of capacity which was roughly half the installed capacity at that time with 15 GW spare capacity was available on power exchanges.  The fact that there is no market demand for power does not mean that there is no need for power but from an economic perspective any rational investor would think twice before adding capacity in this environment.

Then there is the murky area of how much coal is produced in India, how much is round-tripped as imported coal and how much is sold in grey markets. As noted in IEA’s medium term coal market report 2014, in 2013, demand for thermal coal increased by 2 percent while coal based power generation increased by 8.4 percent.  Both cannot be true unless we take into account significant volumes of coal available in the grey market (the report gives a figure of 60 million tonnes).  Any Government that wants to clean the stable must look at all these issues along the continuum. It must also look beyond the concerns of the capitalist entrepreneur, because unfortunately a democracy also has people who are also rate payers and tax payers. If they don’t pick up the entrepreneur’s bills the continuum will collapse.

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

[1] https://in.finance.yahoo.com/news/coal-auctions-will-clean-the-stables-once-and-for-all-063521600.html


[3] http://www.cea.nic.in/reports/monthly/executive_rep/feb14.pdf

[4] https://www.coalindia.in/en-us/performance/physical.aspx

Courtesy: Energy News Monitor | Volume XI; Issue 32


Monthly Non-Fossil Fuels News Commentary: January 2018


As India faces heat at the WTO for giving preference to domestic solar manufacturers in its renewable energy programme, the MNRE has made changes to the content sourcing policy. This comes at a time when the domestic solar manufacturing industry has sought safeguards and anti-dumping duty on import of solar panels from China and Malaysia. CPSUs and states are open to call tender with DCR under the EPC or contractor mode. CPSUs such as NTPC Ltd would be allowed to issue tender for solar project construction with the caveat that the private domestic developer should only be an EPC contractor and not power seller. Also, the new rooftop solar projects policy promotes use of domestic content with central financial assistance and subsidy. MNRE has floated the proposal to increase the amount of CPSUs projects to 13,000 MW from current 1,000 MW. Till last year, 10 percent capacity in each of the tender issued by the central government for solar power project was kept for domestic content sourcing. Earlier it was 50 percent and was brought down after the first appeal made by the US in the WTO in 2014. Apart from this, major PSUs such as NTPC and CIL have committed to build solar power generation capacity from domestic content. The WTO ruling in September 2016 stated that solar projects which are to be taken up by the government, for the government, there should not be any commercial sale. India asked for a year’s time to close all the projects floated on DCR. The deadline expired in December 2017. As the current status of the case stands, India has sent clarification that the Solar Mission is WTO complaint and none of the solar policies flout any trade regulations.

India has proposed to levy a 70 percent safeguard duty on import of solar power equipment from countries like China for 200 days to protect domestic industry from “serious injury”. The safeguard duty would be levied if the finance ministry accepts the recommendations of the DGS. Before final duties or import taxes are levied, DGS will hold further investigation into the injury caused by cheap imports. It would also hold a public hearing on the issue. India has annual manufacturing capacity for solar cells of around 3 GW as against requirement of 20 GW. DGS said import of solar equipment jumped from 1,271 MW in 2014-15 to 4,186 MW in the next year and to 6,375 MW in 2016-17. Current fiscal imports are pegged at 9,474 MW as compared to domestic production of 1,164 MW. Reasoning its decision, it said while China’s exports to India constituted a paltry 1.52 percent of its total global exports during 2012, this increased to 21.58 percent during 2016.

The finance ministry is considering the renewable-energy ministry’s request to tax panels imported for projects won under future solar auctions while exempting those already awarded. The proposed change could imperil the goal of installing 100 gigawatts of solar energy by 2022, especially as developers have relied on low-cost equipment from China to push tariffs to among the lowest in the world. India is planning to offer financial incentives to boost domestic manufacturing and energy security, while probing if Chinese solar-equipment makers are hurting the domestic industry by dumping inventories and driving down prices to unfair levels. Higher global module costs have already pushed up bid rates from record lows in auctions conducted by Solar Energy Corp of India late last year and the import tax could increase prices further.

India hit back at Washington’s latest legal assault on its solar power policies at the WTO, rejecting a US legal claim and exploring possible new protection of India’s own solar industry. The US triggered a new round of litigation at the WTO, arguing that India had failed to abide by a ruling that it had illegally discriminated against foreign suppliers of solar cells and modules. India said it had changed its rules to conform with the ruling and that a US claim for punitive trade sanctions was groundless. It said Washington had skipped legal steps, failed to follow the correct WTO procedure, and omitted to mention any specific level of trade sanctions that it proposed to level on India, leaving India “severely prejudiced”. India would be vindicated if the proper process was followed, it said. Renewable energy has become an area of severe trade friction as major economies compete to dominate a sector that is expected to thrive as reliance on coal and oil dwindles. India unveiled its national solar programme in 2011, seeking to ease chronic energy shortages in Asia’s third-largest economy without creating pollution. But the US complained to the WTO in 2013, saying US solar exports to India had fallen by 90 percent. The WTO judges agreed that India had broken the trade rules by requiring solar power developers to use Indian-made cells and modules. In a separate move that could protect its solar industry from global competitors, not only US rivals, India told the WTO that it was considering the case for imposing temporary emergency tariffs on solar cells, modules and panels, after a petition from the domestic industry.

Solar modules worth more than $150 million are stuck at various Indian ports due to a dispute over their classification and the import tax applicable to them. Indian Solar Association said that up to 2,000 solar module containers are now stranded at four major ports.  Most of the solar modules come from China, but several consignments are now held up because customs officials have demanded that some of them be classified as “electric motors and generators”, attracting a 7.5 percent duty, not as “diodes, transistors and similar semi-conductor devices” with no duty. The Indian unit of Germany’s Enerparc had 30 of its containers stuck at Chennai for three weeks as it finished some “paperwork” and paid a demurrage – a charge for failing to discharge the ship on time – of about ₹ 7 million ($110,471).  The renewable energy ministry has already asked the finance ministry to resolve the matter without disrupting business. Any duty is bad news for project developers such as SoftBank-backed SB Energy but good for local solar component makers such as Indosolar and Moser Baer. Indian manufacturers have struggled to compete with Chinese companies such as Trina Solar and Yingli and have sought anti-dumping duties as well as long-term safeguards. The finance ministry is examining a proposal from the renewable ministry to exempt projects bid earlier from paying the duty.

The Madras High Court has issued a temporary stay on a preliminary report of the DGS recommending imposition of 70% safeguard duty on imported solar equipment. Shapoorji Pallonji Infrastructure, a contractor-cum-developer of solar projects and part of the Shapoorji Pallonji Group, had petitioned the court against the recommendation, maintaining the company was never given a chance to respond to the original petition on the basis of which DGS suggested imposing 70% duty. The DGS had on December 19 last year sent a notice to all stakeholders saying it had initiated an enquiry into the matter on the basis of a petition filed by Indian Solar Manufacturers Association claiming that large scale imports of solar panels and modules from China, Malaysia, Taiwan and Singapore were causing “serious injury” to domestic manufacturers of similar equipment. The notice gave stakeholders 30 days to reply. However, the DGS announced preliminary findings on January 5. Solar developers prefer imported equipment because they are 25-30% cheaper than domestic ones, thanks to economies of scale and government subsidies in the exporting countries. Independent Solar Power Producers Alliance, an association of solar developers, too, has filed a petition in Delhi High Court seeking a stay on the recommendation.

Uttar Pradesh Electricity Regulatory Commission rapped the six solar power companies that had proposed to set up power plants in the state, saying it could not allow them to sell solar power at a rate much higher than prevailing market prices. The companies, including Adani Green Energy, had approached the commission nearly six months after UPPCL issued them a notice seeking cancellation of their agreement with New Energy Development Authority over high cost of power and delay in setting up projects despite an agreement in 2015. The Commission noted that the cost of power proposed to be supplied by the companies ₹ 7.02/kWh was much higher than the prevailing market prices of ₹ 2.44 to ₹ 4/kWh. The six plants, with a combined capacity of 80 MW, belong to Adani Green Energy, Sahastradhara Energy, Pinnacle Air, Awadh Rubber Prop Madras Elastomers, Technical Associates and Sudhakara Infratech. According to the agreements signed in 2015, the developers had to complete the projects by January 2017. That did not happen, forcing the state government to extend the deadline till March 2017.

Private sector lender Yes Bank said it will mobilise $1 billion by 2023 for financing solar energy projects in India. Yes Bank signed five solar energy co-financing Letters of Intent with Tata Power Delhi Distribution, Hero Future Energy, Greenko Group, Amplus Solar and Jakson Group for their solar projects in India to be completed by 2023. ISA is a treaty-based alliance of 121 prospective solar rich member nations and aims at accelerating development and deployment of solar energy globally.

Husk Power Systems said that it has raised $20 million to scale its renewable mini-grid business both in Asia and Africa. Husk Power designs, builds, owns and operates one of the world’s lowest-cost hybrid power plants and distribution network in India and Tanzania. It provides power to rural communities and businesses, entirely from renewable energy sources.

The IFC, the World Bank’s private investment arm, is set to invest $440 million (₹ 28 billion) in the 750 MW Rewa Ultra Mega Solar Park in Madhya Pradesh, paving the way for the financial closure of this project that has for the first time brought solar tariff in India on a par with thermal power. The investment by IFC will be in the form of debt to three companies that are setting up the units, each of 250 MW, Mahindra Renewables, Acme, and Actis. The deal for a $140 million (₹ 9 billion) funding with Actis has been signed, while the one with Acme for $150 million is due to be signed soon. The third one, with Mahindra, for the remaining $150 million is awaiting final approval. The solar park is being developed by Rewa Ultra Mega Solar, a joint venture between Madhya Pradesh Urja Vikas Nigam, a state government agency, and the Solar Energy Corp of India. It is scheduled to be commissioned in December 2018 and is part of meeting India’s renewable energy target of 175 GW by 2022.

In order to kick-start fund mobilisation under the ISA, the central government will set up a $350 million solar development fund. Nine companies and banks have agreed to develop and finance various solar projects, which include a $1-billion partnership corpus of NTPC Ltd and CLP India to the ISA. The firms are: Vyonarc Development, Greenko Solar, Gensol Group and SOLARIG from Spain, Shakti Pump, Refex Energy, Amplus Solar, TATA Power, Jackson Solar, and Zodiac Energy. CLP India and NTPC announced forging a partnership deal with the ISA and committed to making a voluntary contribution of $1 million each to the ISA fund corpus.

ONGC has embarked on an ambitious project on innovation towards making an “Efficient Electric Chulha (Stove)”. ONGC launched a nationwide campaign to seek innovative solutions for the development of Solar Chulha. An overwhelming response with more than 1500 entries was received by ONGC in the duration of the campaign. The top three entries will receive awards of ₹ 1,000,000 ₹ 500,000 and ₹ 300,000 respectively. On successful demonstration and testing performance of the units, about 1000 units may be initially procured by ONGC for demonstration in different regions. ONGC may also provide financial support for fabrication of 1000 units, from the start up fund set up by ONGC to popularize the product amongst the masses. ONGC is working towards finding an efficient household cooking solution to ensure last-mile delivery of clean energy.

In an initiative to promote clean energy, BSES, one of Delhi’s two electricity discoms, launched the country’s first solar rooftop consumer aggregation programme for residential buildings to provide the installations at a single point for the entire apartment complex. The sister discom BRPL’s “Solar City Initiative”, designed to maximise rooftop solar power use in south and west Delhi, was launched at an event. In the first phase of the programme, around 150 residential societies will be targeted in the Dwarka area. Listing the benefits for consumers, the discom said a 1 kW solar PV rooftop system is expected to generate 4-5 kWh of electricity per day, which corresponds to an average monthly saving on bills of about ₹ 750 for a period of 25 years for single-point delivery consumers. Besides, the scheme would help BRPL in meeting its renewable purchase obligation, as well as minimise overloading issues in congested areas during the peak summer months. BSES also announced that a portal has been launched as part of the initiative for online processing of rooftop solar applications, as well as a dedicated solar helpline for faster resolution of customer queries.

GAIL (India) Ltd said it has commissioned the country’s second largest rooftop solar power plant. The firm has installed a 5.76 MWp solar plant at its petrochemical complex at Pata in Uttar Pradesh, the company said. The plant over the roofs of warehouses covers a total area of 65,000 square meters. Tata Power Solar had in December 2015 commissioned a 12 MW solar rooftop project in Amritsar, which produces more than 150 lakh units of power annually and offset over 19,000 tonne of carbon emissions every year. India is plans to have 40 GW of rooftop PV by 2022. This is part of its target of have 175 GW of non-hydro renewables capacity by 2022 (made up of 60 GW onshore wind, 60 GW utility-scale solar, 10 GW bio-energy, 5 GW small hydro and 40 GW rooftop solar). It currently has 60 GW of renewable energy capacity. Captive solar power initiative of GAIL will reduce carbon emissions by 6,300 tonnes per annum and help India achieve climate goals.   With most of the fossil fuel companies either producing or consuming solar power it is not clear if fossil fuels are underwriting renewable energy costs.

Adani Group has been named in the top 15 global utility solar power developers that includes likes of First Solar, Total, SunEdison and Engie. Adani, ranked 12th, is the only Indian company on the list put out by Greentech Media, a Wood Mackenzie business. Top of the list is First Solar with an operational capacity of 4,619 MW and in-development capacity of 4,802 MW. Adani has 788 MW of operational capacity and another 1,270 MW under development. Adani Renewables is targeting 10 GW of installed renewable power by 2022. The company currently has 12 MW of operational wind assets, as well as 788 MW of solar PV.

Solar power tariff fall seems to have bottomed out and may not drop beyond an all-time low of ₹ 2.44/kWh in absence of well-structured bids and rising solar panel prices on demand pressure. The solar power tariff fell to an all-time low of ₹ 2.44/kWh in May 2017 during an auction for 500 MW capacities at Bhadla (IV) in Rajasthan. It had the viability gap funding component, as per the Ministry of New and Renewable Energy data. According to data, the solar tariff rose to ₹ 3.47/kWh for 1,500 MW capacities in Tamil Nadu under a state scheme in July and then dropped again to ₹ 2.66 /kWh in an auction for 500 MW capacities in Gujarat. In an auction of state-run power giant NTPC for 250 MW capacity, the tariff was ₹ 3.14/kWh. But it dropped again with viability gap funding to ₹ 2.47/kWh and ₹ 2.48 /kWh for 500 MW Bhadla-III and 250 MW Bhadla-IV auctions in December 2017. Many experts are also of the view that solar tariff has bottomed out and may not fall further. During 2017, solar power tariff hovered around ₹ 2.4/kWh level only in auctions for capacities, where viability gap funding component was there.

Solar developers have moved the power regulators of Haryana and Uttarakhand to smoothen out anomalies which are impeding the growth of solar capacity in these two states. In one petition, the DISPA has noted that the regulator, the HERC has yet to implement a key recommendation of the Haryana Solar Policy announced in March 2016. In another, it has appealed to the UERC to remove the limit of 500 kW it has imposed on the size of rooftop solar plants. Haryana’s solar policy clearly states that both ground-mounted and rooftop solar projects should be exempted from “all electricity taxes and cess, electricity duty, wheeling charges, cross subsidy charges, transmission and distribution charges and surcharges”. However, HERC has not yet passed any order making these concessions effective. The petition before the UERC argues that the 500 kW limit for rooftop solar plants is entirely arbitrary. Its origins lie in the guidelines issued by the MNRE in June 2014, which imposed “a limit of 500 kW in respect of installed solar capacity for projects under net metering arrangement”. DISPA had also moved the Gujarat Electricity Regulatory Commission to provide net metering and other incentives for putting up solar rooftop plants not only to house owners, but also to solar developers so that they can lease roofs from house owners. House owners were often reluctant to set up solar rooftop projects as they were unaware of the technicalities or could not afford the initial upfront costs. That petition is still pending.

In an attempt to provide electricity to houses in remote and inaccessible areas of the state where electrification is not possible due to difficult geographical terrain, the UPPCL will soon be providing off-grid electricity by setting up solar power plants. According to the UPPCL, the task to identify the areas that are inaccessible and have not yet been brought under the corporation’s power grid has been handed over to Non-conventional Energy Development Agency. Small solar grids will be set up in the identified remote areas, which will cover one or more villages as per the requirement of load. Every house will be connected with it.

Encouraged by the successful implementation of solar projects in states like Karnataka and Gujarat, the UP is planning to invite bids for 100 MW of solar power projects by March. The bids are for projects on open access basis to be set up in the Bundelkhand region. Leading players like Adani Group, Tata Power Solar, ReNew Power and Hero Future Energies are likely to be interested in the projects to be offered in UP, suggested an industry player. The state government has separately invited tenders for the selection of consultancy firms for establishment of a project management unit to assist UP New and Renewable Energy Development Agency in implementation of the state’s Solar Power Policy 2017. The last date for submission of e-tenders is January 14 and the online technical e-tender opening date is January 15. The financial tender opening date for qualified bidders is January 30. The UP Solar Power Policy 2017 targets implementation of 10,700 MW of grid-connected solar power projects by the end of 2022. Of the total capacity, 4,300 MW is targeted to be achieved through deployment of grid connected rooftop projects, and 6,400 MW through ground mounted utility scale power projects.

India said it can reach a capacity of 17,000 MW in renewable energy by the year 2022. As per the share of renewable energy in the total electric power generation capacity, the addition was 52.2 percent.  This is an order of magnitude smaller than the target announced when the current government came to power.

Haryana wants solar-based micro irrigation schemes be implemented in all districts. At present, the scheme is being implemented on a pilot basis in 14 canal outlets in 13 districts with an outlay of ₹ 246.5 million.

The New Year has brought a fresh ray of hope in India’s nuclear energy sector, with Westinghouse, the bankrupt energy company being sold to a Canadian investment major, Brookfield Business Partners. Westinghouse is supposed to build six of its AP-1000 nuclear reactors in India, a project that had been delayed after the company filed for bankruptcy earlier in 2017. The $4.6 billion acquisition is expected to get the beleaguered US-Japanese company out of hot water. Toshiba, the owner of Westinghouse had been looking to sell the nuclear business after it filed for bankruptcy. Westinghouse had, in its discussions with the Indian government, assured that it would continue to work on the six reactors which are expected to come up in Kovvada, Andhra Pradesh. The company is expected to build six reactors in India — private sector and government entities are currently exploring whether a greater amount of indigenous components can be used to build these reactors, bringing down their costs as well as giving a fillip to Indian nuclear industry. This might even help Westinghouse avert the potential liabilities of the Indian nuclear liability law, which has been singularly responsible for being a drag on the Indian nuclear industry. The government devised an insurance pool and new rules which make it easier for domestic players, but an air of uncertainty continues to hang over foreign players.

Rest of the World

Taiwan has joined South Korea in demanding compensation for steep US tariffs on solar panels, opening a 30-day window for negotiations, a World Trade Organization filing showed. US President Donald Trump signed into law a 30 percent tariff on imported solar panels, billed as a way to protect American jobs but which the solar industry said would lead to layoffs and raise consumer prices. It was among the first unilateral trade restrictions imposed by the administration as part of a broader protectionist agenda that has alarmed Asian trading partners producing cheaper goods. Taiwan, with no fossil fuel resources but a booming tech sector, says it ranks as the world’s second largest solar cell manufacturing base after China, putting it at the heart of an industry caught up in a global trade battle. The US, India and China are all racing to develop their solar industry, a huge growth area as the world moves toward environmentally friendly sources of energy, and are engaged in legal fights to keep their firms in pole position. The US has alleged that China and India are giving their solar sectors an illicit leg-up, and last week Trump resorted to “safeguard” tariffs, effectively shielding US solar manufacturers from foreign competition.

US President Donald Trump’s decision to slap tariffs on solar panel imports is a blow to a booming global industry, and hit stocks in European and Asian solar groups on fears their business might suffer. Although the move was intended to help American manufacturers, some in the sector said it would slow US investment in solar power and cost thousands of US jobs. Trump approved a 30 percent tariff on solar cell and module imports, dropping to 15 percent within four years. Up to 2.5 GW of unassembled solar cells can be imported tariff-free in each year. The US has the world’s fourth-largest solar capacity after China, Japan and Germany. Globally, solar capacity soared to almost 400 GW last year from under 10 GW in 2007, according to the International Renewable Energy Administration. The US-based Solar Energy Industries Association said the decision could cause the loss of around 23,000 US jobs this year, and result in the delay or cancellation of billions of dollars in solar investments. The US government argued that its domestic manufacturers could not compete with what it said were artificially lower-priced Asian panels. The Chinese firms that are the world’s biggest makers of solar photovoltaic cells will be hit by the tariffs at their production sites across Asia.

SMA Solar, Germany’s largest solar group, expects the industry to take a just a small hit from import tariffs imposed by US President Donald Trump, sending its shares to an 11-week high. Trump approved a 30 percent tariff on solar cell and module imports, dropping to 15 percent within four years. Up to 2.5 GW of unassembled solar cells can be imported tariff-free in each year. Although the move was intended to help American manufacturers, some in the sector said it could slow US investment in solar power and cost thousands of US jobs. However, SMA Solar, the world’s largest maker of solar inverters, said it expected the impact to be small, forecasting industry growth in the Americas region would average about 18 percent per year until 2020, more than the 10 percent expected globally. The US government argued that its domestic manufacturers could not compete with what it said were artificially lower-priced Asian solar panels.

SunPower Corp said it was putting a $20 million US factory expansion and hundreds of new jobs on hold until and unless its solar panels receive an exclusion from federal tariffs. The decision to impose tariffs on cheap imported panels was intended to protect American manufacturing jobs, but many in the solar industry have argued that tariffs will raise costs and trigger thousands of layoffs in the installation end of the industry. SunPower’s project development arm has already lost business to rival First Solar Inc, which makes panels that are exempt from tariffs.

The world’s largest solar-thermal power plant has been given development approval by the South Australian government. Construction on the 150 MW Aurora plant, to be built by utility-scale solar power company SolarReserve, will begin in 2018 at an estimated cost of $509 million. The plant would create 650 construction jobs and 50 ongoing positions when completed. The plant will work by using a series of mirrors to concentrate sunlight on a receiver at the top of a 220-meter tower. The sunlight will then heat molten salt to 565 degrees centigrade, generating steam to drive a turbine that will produce 150 MW of electricity making it the largest single-tower solar thermal plant in the world. It will have the capacity to power 90,000 homes with eight hours of full load storage. It will join the largest lithium-ion battery, built by Tesla to complement the state’s power grid during the high-demand summer, as another major renewable energy project in South Australia.

For new projects commissioned in 2017, electricity costs from renewable power generation have continued to fall significantly compared to the fossil fuels, according to a new report from the IRENA. It estimates onshore wind is now routinely commissioned for $4 cents per kWh. The current cost spectrum for fossil fuel power generation ranges from $5-17 cents per kWh. The IRENA with more than 150 member countries says the cost of generating power from onshore wind has fallen by around a quarter since 2010, with solar photovoltaic electricity costs falling by 73 percent in that time. It also highlights that solar costs are set to fall further with another halving expected by 2020. The best onshore wind and solar photovoltaic projects could be delivering electricity for an equivalent of $3 cents per kWh, or less within the next two years. Global weighted average costs over the last 12 months for onshore wind and solar PV now stand at $6 cents and $10 cents per kWh respectively, with recent auction results suggesting future projects will significantly undercut these averages. The IRENA report also highlights that auction results are signalling that offshore wind and concentrating solar power projects commissioned between 2020-22 will cost in the range of $6-10 cents per kWh, supporting accelerated deployment globally. IRENA projects that all renewable energy technologies will compete with fossils on price by 2020.

Westinghouse Electric Co signed an agreement to deliver nuclear fuel to seven of Ukraine’s fifteen nuclear power reactors between 2021-2025, and will source some fuel components locally, Westinghouse said. Owned by Toshiba Corp, Westinghouse said the deal would help Ukraine diversify its energy supplies. The deal builds on an existing agreement to supply six reactors, which was set to expire in 2020. Kiev’s pro-Western government wants to wean Ukraine off a traditional dependence on Russia for energy supplies, including gas imports and nuclear fuel.

French nuclear and renewable energy group New Areva has signed a memorandum of commercial agreement with Chinese partner CNNC for the construction of €10 bn ($12 bn) nuclear fuel reprocessing facility in China. In 2013, Areva and CNNC had signed a letter of intent to build a used fuel treatment and recycling facility in the Asian country. Areva said that the latest agreement reaffirms its commitment with the Chinese partner to complete the contract negotiations for the Chinese commercial used fuel treatment-recycling plant project. The Chinese treatment-recycling plant, which will have a reprocessing capacity of 800 ton of spent nuclear fuel from Chinese power plants annually, is planned to be built on the model of New Areva’s two existing plants, La Hague and Melox, both located in France. A final deal on the facility is expected to provide much needed boost to the French nuclear industry, which has been struggling to gain new contracts since the Fukushima nuclear disaster in 2011.

Russian state nuclear agency Rosatom has proposed building a nuclear power station in Argentina, President Vladimir Putin said. Putin was speaking after talks with his Argentine counterpart, Mauricio Macri, in Moscow.

EDF Energy said its Hinkley C nuclear power station in Somerset, southwest England, will come online by the end of 2025 and give the developer the experience to lower the costs of subsequent nuclear plants planned in the country. Hinkley Point C will be the first nuclear plant built in Britain in decades. It is expected to provide 7 percent of Britain’s power needs while helping to replace the country’s ageing nuclear fleet and closing coal plants. The plant, being built by the British arm of France’s EDF with China General Nuclear Power Corp, has been beset by delays and higher cost estimates. It was initially expected to start producing electricity in 2017. The project has also been criticized over its guaranteed price for electricity, which is higher than market rates. EDF also plans to build two more nuclear reactors at Sizewell in eastern England.

Saudi Arabia plans to prequalify for bidding firms from two or three countries by April or May for the first nuclear reactors it wants to build. Saudi Arabia, the world’s top oil exporter, wants nuclear power to diversify its energy supply mix, enabling it to export more crude rather than burning it to generate electricity. It plans to build 17.6 GW of nuclear capacity by 2032, the equivalent of around 16 reactors, making it one of the biggest prospects for an industry struggling after the 2011 nuclear disaster in Japan. A joint venture between the Saudi government and the winning developers would be signed in 2019 after the shortlisting by end of 2018. Commissioning of the first plant, which will have two reactors with a total a capacity between 2 and 3.2 GW, is expected in 2027. Saudi Arabia has sent a request for information to international suppliers to build two reactors, the first step towards a formal tendering competition. Riyadh was currently evaluating requirements from five countries; China, Russia, South Korea, France and the US. Saudi Arabia is interested in reaching a civilian nuclear cooperation agreement with Washington, and Riyadh has invited US firms to take part in developing the kingdom’s first atomic energy program.

At ground zero of Ukraine’s Chernobyl tragedy, workers in orange vests are busy erecting hundreds of dark-coloured panels as the country gets ready to launch its first solar plant to revive the abandoned territory. The new one-megawatt power plant is located just a hundred metres from the new “sarcophagus”, a giant metal dome sealing the remains of the 1986 Chernobyl accident, the worst nuclear disaster in the world. Ukraine, which has stopped buying natural gas from Russia in the last two years, is seeking to exploit the potential of the Chernobyl uninhabited exclusion zone that surrounds the damaged nuclear power plant and cannot be farmed. The installation of a huge dome above the ruins of the damaged reactor just over a year ago made the realisation of the solar project possible. Ukrainian authorities offered investors nearly 2,500 hectares (25 square kilometres) for potential construction of solar power plants in Chernobyl.

France will not increase carbon emissions as it reduces its reliance on nuclear energy in coming years. The centrist government has launched a year-long debate about energy policy before deciding in early 2019 on the future share of nuclear energy in France’s power production. It now stands at 75 percent. To assist discussions, grid operator RTE has prepared scenarios for cutting nuclear energy’s share from 56 percent to 11 percent by 2035, and an additional scenario on reducing nuclear reliance to 50 percent by 2025. Environment activists complain that the government has withheld scenarios cutting back nuclear capacity the most, when it held workshops this month to prepare for the public debate. France would not build more plants powered by coal or fuel oil, he said, but said the government would consider whether there was a role for gas, which has lower emissions than coal or other fossil fuels. Sustainable energy advocacy group NegaWatt said the most ambitious scenarios for reducing nuclear reliance could be achieved without boosting CO2 emissions provided there was a stronger focus on energy efficiency and if the nuclear reactors had their lifespans’ extended a little beyond 40 years. The majority of EDF’s nuclear reactors were connected to the grid between 1980 and 1990. Closing them all promptly after 40 years, their scheduled lifespan, would cut so much capacity that France would have to build new gas plants to fill the gap. EDF wants to extend the lifespan of its reactors to 50 years, but will need approval of nuclear regulator ASN for each reactor. The ASN has said it will rule on the principle of lifespan extensions in 2021.

The Trump administration announced it is doing away with a decades-old air emissions policy opposed by fossil fuel companies, a move that environmental groups say will result in more pollution. The US EPA said it was withdrawing the “once-in always-in” policy under the Clean Air Act, which dictated how major sources of hazardous air pollutants are regulated. Under the EPA’s new interpretation, such “major sources” can be reclassified as “area sources” when their emissions fall below mandated limits, subjecting them to differing standards. The EPA said the policy it has followed since 1995 relied on an incorrect interpretation of the landmark anti-pollution law.

A team of scientists at Stanford University, including a researcher of Indian origin, has shown how nanotechnology can be used to create crystalline silicon (c-Si) thin-film solar cells that are more efficient at capturing solar energy. The discovery can reduce the cost of solar energy production globally, they noted. The team used optical modelling and electrical simulations to show that a thin-film crystalline silicon solar cell with a 2D nanostructure generated three times as much photo current as an unstructured cell of the same thickness. The longer the light spends inside the solar cell – the greater its chance of getting absorbed. The discovery reveals a simple method to improve the efficiency of all silicon solar cells.

The California regulators have approved PG&E’s request to decommission the 2,256 MW Diablo Canyon nuclear power plant by 2025. With the approval from the California Public Utilities Commission, PG&E will retire the power plant, which features two nuclear reactors, upon completion of its operating licenses. The regulator has also authorized the firm to recover $241.2 mn in costs associated with retiring the plant; $211.3 mn to retain PG&E employees until the facility is retired; $11.3 mn for retraining of workers; and $18.6 mn for Diablo Canyon license renewal expenses incurred by PG&E. However, the regulator has rejected PG&E’s request for $85 mn for a Community Impact Mitigation Program in the absence of express legislative authorization.

New York City announced that it filed a multibillion dollar lawsuit against five top oil companies, citing their “contributions to global warming,” as it said it would divest fossil fuel investments from its $189 billion public pension funds over the next five years. The lawsuit, against BP Plc, Chevron Corp, ConocoPhillips, Exxon Mobil Corp and Royal Dutch Shell Plc, follows similar lawsuits filed last year by San Francisco and other California cities seeking billions of dollars in damages from rising sea levels due to climate impacts. The lawsuits are the latest legal challenges against oil companies over climate change and come as the firms are searching for new business models amid pressure by governments and consumers for cleaner energy.

Denmark just set a world record for using wind power to drive its economy. Its government now predicts that anyone betting against the technology is on the wrong side of history. Denmark is positioning itself as the flag bearer for wind power. Denmark obtained 43.4 percent of its electricity from wind last year, beating its own record. The government’s goal is to derive 50 percent of the country’s entire energy consumption from renewables by 2030. Denmark is home to the world’s biggest turbine maker, Vestas Wind Systems A/S, which just raised its outlook after getting more orders than it expected in 2017. The state also holds a controlling stake in Orsted A/S, the world’s biggest operator of offshore wind parks, which this week raised its 2017 profit forecast thanks to strong winds in northern Europe.

The US power grid regulator rejected a directive to prop up aging coal and nuclear power plants, in a setback for the Trump administration that disappointed coal miners but pleased drillers, environmentalists and renewable energy advocates. FERC said it had embarked on a new process to determine whether the grid can be strengthened. The move was a blow to the plan to reward certain nuclear and coal-fired power plants that store 90 days of fuel on site by paying for their operating costs through power price adjustments. President Donald Trump promised to aid the coal and nuclear industries, which have suffered shutdowns resulting from a glut of cheap natural gas. FERC’s new plan involves asking grid operators to submit within 60 days their concerns about the resiliency of the power system. The commission will then decide whether additional action is warranted, FERC said.

Over 30 energy sector players from around the world including India converged in Nepal to explore the country’s hydropower potentials. The aim of the expo was to assist the Nepal government in achieving its objective of generating 17,000 MW of hydroelectricity in the next seven years. Over 30 hydropower generators, producers of electrical equipments, investors, consultants and designers from Nepal, India, China, South Korea, Norway, Germany, Brazil, Italy, Sweden and Austria showcased their products and services at the three-day expo Himalayan Hydro Expo 2018. Italys CMC, Germanys VOITH; BFL, CRYSTAL, FLOVEL from India, VAPTECH – Bulgaria, MAVEL – Czech Republic, Powerchina, CSEC from China among others participated. President Bidya Devi Bhandari inaugurated the exhibition and said Nepal could not utilise its huge hydropower potential due to various reasons and that, it produced only 700 MW of hydro-electricity in the last one hundred years. The president urged private players to join hand with the government in harnessing Nepal’s immense hydro potentials.

Scientists are developing a novel technology that may economically convert fossil fuels and biomass into useful products, including electricity, without emitting carbon dioxide into the atmosphere. Engineers at The Ohio State University in the US devised a process that transforms shale gas into products such as methanol and gasoline – all while consuming carbon dioxide. The process can also be applied to coal and biomass to produce useful products, researchers wrote in the journal Energy & Environmental Science. Under certain conditions, the technology consumes all the carbon dioxide it produces plus additional carbon dioxide from an outside source, they said. The researchers have also found a way to greatly extend the lifetime of the particles that enable the chemical reaction to transform coal or other fuels to electricity and useful products over a length of time that is useful for commercial operation. The same team has discovered and patented a way with the potential to lower the capital costs in producing a fuel gas called synthesis gas, or “syngas,” by about 50 percent over the traditional technology. The technology, known as chemical looping, uses metal oxide particles in high-pressure reactors to “burn” fossil fuels and biomass without the presence of oxygen in the air. The metal oxide provides the oxygen for the reaction. Chemical looping is capable of acting as a stopgap technology that can provide clean electricity until renewable energies such as solar and wind become both widely available and affordable, the researchers said. The engineers also developed chemical looping for production of syngas, which in turn provides the building blocks for a host of other useful products including ammonia, plastics or even carbon fibres. The technology provides a potential industrial use for carbon dioxide as a raw material for producing useful, everyday products, researchers said.

WTO: World Trade Organisation, MNRE: Ministry of New and Renewable Energy, CPSUs: Central Public Sector Undertakings, EPC: Engineering, Procurement & Construction, MW: megawatt, GW: gigawatt, US: United States, DCR: Domestic Content Requirement, CIL: Coal India Ltd, DGS: Directorate General of Safeguards, UPPCL: Uttar Pradesh Power Corp Ltd, kWh: kilowatt hour, ISA: International Solar Alliance, IFC: International Finance Corp, ONGC: Oil and Natural Gas Corp, discoms: distribution companies, PV: photovoltaic, BRPL: BSES Rajdhani Power Ltd, MWp: megawatt peak, DISPA: Distributed Solar Power Association, HERC: Haryana Electricity Regulatory Commission, UERC: Uttarakhand Electricity Regulatory Commission, UP: Uttar Pradesh, CO2: carbon dioxide, IRENA: International Renewable Energy Agency, CNNC: China National Nuclear Corp, EPA: Environmental Protection Agency, PG&E: Pacific Gas and Electric Company, FERC: Federal Energy Regulatory Commission

Courtesy: Energy News Monitor | Volume XIV; Issue 35

SWOT Analysis of Overseas Coal Opportunities[1]

Ashish Gupta, Observer Research Foundation

Countries Australia Indonesia South Africa Mozambique Colombia
Reserves in Billion Tonnes (BT) 76.4 28 30 16 (extensive study required) 6.7


R/ P Ratio (years) 160 67 117 Not known 79
Coal Regions Queensland & New South

Wales (exploited).

Surat Basin & Galilee Basin

(partly exploited)

Sumatra & Kalimantan


Papua, Java, Maluku

& Sulawesi (partly


Highveld (exploited),

Witbank, Ermelo,

Waterberg, Vereeniging

South Rand, Utrechet and

Klip River are open for exploration.

Tete and Niassa are open for exploration


Cesar, Guagira,

Boyaca and

Cundinamarca are open for exploration


Coal Quality High Medium & low Medium & low Good High
Mining Status Highly mechanised Labour intensive Labour intensive Labour intensive Not known
Cost of Mining Very costly Labour is cheap Labour prices increased dramatically  by 9.6% in 2013 Labour is cheap Labour is cheap
Policy Framework Conducive Skewed towards indigenous players Conducive. Does not have any concrete energy policy in place Conducive. No local equity/ ownership required Conducive
Rail Infrastructure Heavy investment required Heavy investment required Not very good Not very good Not very good
Port Infrastructure Expanding Not a problem Expanding but heavy investment required Expanding but heavy investment required Expanding but heavy investment required
Cumulative Additions to coal terminal capacity 2015 -19 (MT[2]) 40 55 27 10 43
Planned Investment in Port  Infrastructure $ 10 billion Dudgeon Point

Coal Terminal

$ 5 million PT Bara Ria Sukses’s Jambi

Coal Terminal

$ 1.5 billion terminal at Richards

Bay by Transnet

Expansion of port of Macuse Cerrejon $ 1.3 billion infrastructure

expansion programme


Planned Investment in Rail Infrastructure $ 700 million rail track at the Port of Newcastle $ 2.4 billion for b 191 km rail line from Kutai Barat to Balikpapan in East Kalimantan $ 1 billion railway coal link project from Mpumalanga region to

Richards Bay

$ 4 billion rail link under study for

530 km from Moatize to the port of Macuse


$ 700 million railway line project from

Colombia’s new port of Puerto Brisa with Central Railway and $ 1.3 billion  infrastructure project at Rio Magdalena

Proximity to Indian Ports 18 days to-Indian west coast and 14 days to Indian east coast 12 days to-Indian west coast and 9 days to Indian east coast 12 days to-Indian west coast and 14 days to Indian east coast 10 days to-Indian west coast and 12 +1/2 days to Indian east coast Voyage distance will be long and will further increase the cost
Shipping Cost $/Tonne[3] 79 50 50 48 55
Attractiveness Import only coking coal Good Better Best Moderate

Views are those of the author                    

Author can be contacted at ashishgupta@orfonline.org

[1] Also Refer, ORF, “Dynamics of Importing Coal: Lessons for India, India, October, 2012

[2] Probable figure from IEA, “Medium term Coal Market Report”, 2014

[3]  supply cost to North West Europe

Courtesy: Energy News Monitor | Volume XI; Issue 33


Monthly Power News Commentary: December 2017 – January 2018


By March 2019, all homes in the country will be provided uninterrupted 24-hour power supply throughout the year. By December 2018, 1,694 villages, which are yet to be electrified, will have electricity connection and works in this regard has been going on. It is likely that the date set for declaring full electrification coincides with the date set for elections. A new law will be enacted to impose penalties on power distribution companies in case of failure to provide uninterrupted power after March 2019, except due to technical reasons. The government has set a target of reducing the T&D losses of power from the current 21 percent to 15 percent by January 2019. ₹ 1.75 trillion is being spent to improve the power infrastructure across the country.

All 39,073 villages of Bihar were said to be electrified. Every household in the state would have a free power connection by the end of the next calendar year. The efforts in this regard were a part of the seven resolves (“saat nischay”) of good governance. The turnaround in the power situation was achieved through a number of reforms, as a part of which “the state electricity board underwent a major revamp and a number of government-run power companies were set up”. Bihar will pitch for increase in budget allocation of centrally-sponsored schemes, uniform power purchase tariff for all states and commencement of financial year from January 1 among several other provisions for being included in the upcoming Union budget for the fiscal 2018-19.  Bihar had also pitched for uniform tariff rates across the country on the lines of railway fares.

The government is working on amendments to the Electricity Act to levy hefty penalties on power distribution companies for load shedding and make provisions for direct subsidy transfers by states to power consumers. The Union power ministry is aiming to introduce the Electricity Act amendment bill in the budget session of parliament. At present, the Act fixes universal service obligation on distribution licensees to provide electricity to all applicants and the penalty for non-compliance can extend to up to ` 1,000 per day of default. The amendments are proposed in the Act to explicitly fix 24×7 power supply obligation on electricity distribution licensees. The bill will also provide for subsidy transfers from state governments for power consumption directly to the consumers, on the lines of cooking gas cylinders. Industry experts said a DBT (Direct Benefit Transfer) like structure in power distribution sector would help revive the discoms. But the scheme may face challenges in implementation as net electricity metering is not prevalent in rural areas. The roadmap for one of the most awaited reforms in the power sector by enabling electricity consumers to choose their supplier is also likely to be provided in the bill. However, the bill may not impose timelines for implementation of the proposal as that has been opposed by states. The states may, however, be asked to notify their plans for implementation of the reform for electricity connection portability in the next 3-5 years. The proposal, to separate electricity supply and network maintenance services and introduce multiple licensees for a single area by amending the Electricity Act 2003, has been in works for last many years. The UPA government had in 2014 introduced a bill to this effect in the Lok Sabha. The proposal is similar to mobile number portability where consumers can switch to a telecom operator of their choice. Currently, power distribution utilities are responsible for operating and maintaining distribution system in their licensed areas.

The ₹ 6,000 billion, 24×7 power supply promised to the agriculture sector from January 1 in Telangana is a pioneering move with far-reaching consequences politically and financially, with potential to rejuvenate the rural economy. From a deficit of about 2,000 MW when the State was formed in June 2014, to be in a position to supply 24×7 power to all industries, and now round-the-clock free power to farmers from the Rabi season, is a creditable achievement. However, the impact of free power on the State’s finances, and the health of the discoms, needs to be closely watched. The State utilities have invested ₹ 12,316 billion to strengthen the transmission and distribution system for 24×7 power supply. The discoms will have to contend with additional agricultural demand of 9,765 million units in FY18. Two discoms have made projections that in FY19, the revenue demand will be ₹ 35,774 billion, against a revenue generation of ₹ 26,003 billion, leaving a gap of ₹ 9,771 billion. To bridge the revenue gap, the government will have to significantly increase the budgetary support to keep the discoms financially healthy.

As many as 13,254 houses were given electricity connections in Western UP in a single day under ‘Saubhagya’ scheme. The districts where the connections were given include Meerut, Baghpat, Ghaziabad, Bulandshahr, Hapur, Gautam Budh Nagar, Saharanpur, Muzaffarnagar, Shamli, Moradabad, Sambhal, Amroha, Rampur and Bijnor. Out of the total houses, 2,372 belonged to BPL families. The connections were given for free during 464 mega camps set up across West UP. Pradhan Mantri Sahaj Bijli Har Ghar Yojana ‘Saubhagya’– an ₹ 163 billion scheme of the central government– aims to provide power connections to over 40 million families in rural and urban areas by December 2018. As many as 464 mega camps were set up in 14 districts of West UP, and a report of the number of electricity connections was made public. Paschimanchal Vidyut Vitaran Nigam Ltd (PVVNL) managing director Ashutosh Niranjan had conducted inspection of the mega camps. While the BPL customers will not have to pay for the electricity connections, ₹ 50 per month will be taken from APL customers in 10 easy instalments.

Asserting that the flagship schemes have been launched to achieve round-the-clock power supply for all by 2019, the Jammu and Kashmir (J&K) government said it was actively pursuing with the Centre the transfer of power projects to the state. Among the reasons forcing power cuts in peak winters and summer seasons in Kashmir and Jammu, respectively, against registered 3,101 MW load, the demand should not exceed 1,551 MW, but it is around 2,950 MW (un-restricted) that reflecting that there exists huge unregistered load. Use of unauthorised load creates system constraints by way of overloading the system at transmission, sub-transmission and at distribution levels, thereby causing further distress cuts in addition to the scheduled cuts. Schemes launched to overcome chronic problems at various levels, are Re-structured Accelerated Developmental Programme sanctioned at a cost of ₹ 1.51 billion under part-A and ₹ 16.65 billion under part-B. It is aimed at strengthening, upgrading and renovating sub-transmission and distribution network, adoption of IT application for meter reader, billing and energy accounting, in 30 identified towns of the state, including 17 of Kashmir division, 11 of Jammu division and 2 of Ladakh region. Energy mapping and energy auditing is subservient to 100 percent metering at all voltage levels. With meagre resources, Jammu and Kashmir Power Development Department has been able to bring down the T&D losses from 61.58 percent in 2011-12 to 52.87 percent in 2016-17. The launch of various centrally sponsored flagship schemes which are primarily reform centric, it is projected that the present high T&D losses shall be appreciably reduced post execution of these schemes.

Government’s UDAY scheme has helped debt laden discoms of 24 states to reduce losses to ₹ 369 billion in 2016-17 from ₹515.9 billion in the previous fiscal. The UDAY was launched for the operational and financial turnaround of state-owned power discoms. The scheme aims to reduce interest burden, cost of power and power losses in distribution sector, besides improving operational efficiency of discoms. The participating states have achieved an improvement of one percent in Aggregate Technical & Commercial (AT&C or distribution) losses and ₹ 0.17/kWh Unit in the gap between Average Cost of Supply and Average Revenue Realised in 2016- 17.

Electricity tariffs across India are expected to rise by 62 to 93 paise ($0.0098-$0.0146) per kWh during the first year of upgrades to coal-fired power plants. The estimate of tariff increases of up to nearly 20 percent on average power fees comes amid rising levels of smog in the capital and other major cities, which has put pressure on the government and generators to tackle a growing public health crisis. Power tariffs are a politically sensitive issue in India, where more than three quarters of the electricity is generated by coal-fired power plants. The average power tariff in India is around ₹ 5/kWh. India, which is looking to facilitate loans to power producers through state-run financial institutions to fund one-time costs, aims to make all coal-fired power plants comply with emission-cutting norms by 2022. CEA (Central Electrical Authority) has prepared a phase-in plan for implementing new environmental norms to ensure minimum disruption while plants are shut down for retrofitting. Thermal power companies account for 80 percent of all industrial emissions of lung-damaging particulate matter, sulphur and nitrous oxides in India.

The government may consider increasing import duty on certain items related to power, capital goods and chemicals sectors in the forthcoming Budget with an aim to boost domestic manufacturing. The move would also help promote the government’s ambitious ‘Make in India’ initiative. Imports of cheap power equipment have been affecting domestic manufacturers as well as created issues for independent power producers in view of poor quality and after sales service. The Indian Electrical and Electronics Manufacturers’ Association in its pre-Budget recommendations have asked the government to remove concessional basic customs duty on imports of certain items in the power sector. It has also said that various finished products of electrical industry attracts a basic customs duty, ranging from 7.5 percent to 10 percent. However, the same finished products are imported at a concessional basic customs duty of 5 percent.

Power discoms in state have approached GERC seeking a hike in FPPPA base price or fuel surcharge. However, none have sought any increase in basic electricity tariffs for fiscal 2018-19. A power company is allowed to offset increase or decrease in fuel cost by way of FPPPA, also known as fuel surcharge. The four distribution companies — UGVCL, MGVCL, DGVCL and PGVCL — have proposed raising basic FPPPA by 6 paise per unit from ₹ 1.43/kWh to ₹ 1.49/kWh for the fiscal 2018-19. Gujarat Urja Vikas Nigam Ltd (GUVNL) affiliated discoms have filed petitions with the GERC for determination of power tariff for the next fiscal. The final quantum of FPPPA increase, however, will be fixed by GERC after hearing all the stakeholders. While private sector company Torrent Power Ltd supplies electricity to Ahmedabad, Gandhinagar and Surat, the state discoms cater to the rest of Gujarat.

Even as it gears up to woo investors in the state, mounting dues towards thermal power plants, including private ones, have come to stare in the face of UP government. UPPCL owes around ₹ 35 billion to some of the major power plants such as NTPC Ltd, NHPC, Lalitpur power plant and Rosa power plant. The situation could turn serious as Lalitpur Power Generation Company has issued a letter to UPPCL saying it does not have enough funds to buy coal and keep its units functioning. The company said that outstanding dues by December-end had crossed ₹12 billion. The company said the situation was “worsening” day by day. According to UP State Load Dispatch Centre, the 1,980 MW Lalitpur power plant has already shut one of its super-critical units of 660 MW citing “shortage of coal”. The situation is equally bad for NTPC. Records show that UPPCL is yet to pay over ₹ 14 billion to the company which supplies 3,182 MW of power per day to the state.

A month ahead of the investors meet in UP, the state government offered yet another sop to industries by giving them the option to take power from the power discom of their choice. The power will be wheeled to the industrial units under the ‘open access system’ for which the state government will set up a help desk at the UP State Load Dispatch Centre (UPSLDC). The permission to take power from a source other than the existing distribution company will be granted by the UP power transmission corporation limited and the respective discom. Industries have been seeking power under the open access system but could not do so since the process for getting clearances was tedious. The open access policy, experts said, could prove to be a boon to the industries in UP which has a power crunch.

City residents should brace for higher tariff with electricity department submitting a proposal for enhancement in the existing rates. The department has submitted a tariff petition to JERC for enhancement in the tariff up to 20% for the next financial year in different slabs. In the domestic category, the electricity department has proposed a hike from ₹ 2.55 to ₹ 2.75 in the slab of 0-150 units. It has proposed increase from ₹ 4.80 to ₹ 5.80 in the slab of 151-400 units and ₹ 5 to ₹ 6 in slab above 400 units. In the commercial category, increase from ₹ 5 to ₹ 6.20 in the slab from 0-150, ₹ 5.25 to ₹ 6.45 in the slab of 151-400 and ₹ 5.45 to ₹ 6.75 in slab above 400 units has been proposed. The commission will take a decision on considering the proposed hike after interacting with the residents of the city. In the past five years, the commission has revised power tariff only twice – 2012-13 and 2015-16— and turned down the petition on three occasions on the ground that the department had failed to submit certain audited accounts. The electricity department caters to 2.15 lakh consumers of nine categories. The majority of power is consumed by domestic consumers followed by commercial category. Despite being repeatedly pulled by the JERC, the department has again failed to file the petition within stipulated time period. For the ongoing financial year, the department had filed tariff petition on January 19, while in 2016 the petition was filed on February 29.

Electricity consumers in Ahmedabad, Gandhinagar and Surat may have to cough up more as TPL has sought permission to increase power rates. The company claims that it needs higher rates to recover its past under-recoveries. The company has not actually demanded a hike in base tariffs — these are revised annually to cover future costs — it has instead proposed a rise in the form of regulatory charge from April 1, 2018. TPL has sought an increase of 25 paise per unit for Ahmedabad area which includes Gandhinagar. For Surat, the regulatory charge proposed to be levied is 20 paise. The private sector company has filed its petitions with GERC for determination of tariff for 2018-19. However, the final quantum of the hike to be passed on to the consumers will be decided by the state power regulatory body, which has sought suggestions and objections from all stakeholders by February 9. In its tariff petitions, Torren Power has stated that its past under recoveries, including carrying cost, works out to be ₹ 39 billion for Ahmedabad, and ₹ 67.79 billion for Surat supply area. The proposed increase, if approved, will translate into an estimated burden of ₹ 4.8 billion on the consumers. Torrent Power has stated in its petitions that it had last increased tariffs in the year 2015-16.

The power ministry is mulling using supercritical power plants to meet new emission norms instead of retrofitting the old polluting units, which could increase their tariff by up to 93 paise per unit. The government has estimated a capital expenditure of ₹ 8.8 million to ₹ 12.8 million/MW for retrofitting the old plant to meet new emission norms. The capital expenditure on retrofitting old plants to comply with new norms will be up to ₹ 12.8 million/MW.

Finally taking cognisance of large number of complaints of inflated power bills issued to farmers, MSEDCL has decided to hold bill correction camps at 11 kilovolt feeder level. MSEDCL said that farmers who have problems with their bills should go to MSEDCL offices with the last bill and receipt. MSEDCL circular issued in this regard states that if a farmer has participated in Mukhya Mantri Krishi Sanjivani Yojana by paying ₹ 3,000 or ₹ 5,000 and has applied for bill correction then his supply should not be disconnected till the deadline for paying the first instalment. However, if any farmer has not participated in the amnesty scheme then connection of such farmer should disconnected as per rules. The circular also states that if a farmer has paid the first instalment under the amnesty scheme then he would get an extension of three months for paying the remaining instalments.

Canadian asset manager Brookfield and the Kotak Mahindra group have jointly bid for 2,200 MW of power assets belonging to Jaypee Power Ventures, a unit of Jaiprakash Associates. The consortium submitted its bid to the committee of creditors and top executives gave a detailed presentation on operational and financial details for the mix of both thermal and hydel assets in north and east India, they said. A deal, if concluded, will close at an equity value of ₹ 35-40 billion, they said. The power assets are currently part of the SDR process intended to salvage the debt-laden company. Brookfield will own 90% of the assets, according to the proposal. Brookfield’s local partner Kotak will hold the remaining 10%. Lenders to Jaiprakash Power Ventures have been looking to sell assets under the SDR scheme since March. Brookfield had held independent talks to purchase the 4,000 MW of assets. Lenders subsequently split these into two — 2,200 MW and 1,800 MW of assets — and sought bids separately for them.

The year 2017 draws to a close with improved performance of the power sector in November on key growth indicators including generation, electricity supply, coal availability and short-term prices even as capacity addition remained low. Power generation, excluding that from the renewable resources, increased 1.7 percent year-on-year to 95 billion units in November. The increase was driven by higher generation across all the sectors including thermal, hydro and nuclear. During the month, all India energy requirement rose 5.4 percent to 93 billion units as compared to the same month last year. India’s power generation from the renewable sources improved by 4.4 percent year-on-year to 6.6 billion units in October 2017 on account of improved generation from the solar sector due to its higher installed capacity and marginal improvement in PLF. Wind power generation, however, continued to decline in October 2017 due to lower PLFs. The share of renewables in the total energy generation improved marginally to 6 percent in October 2017 from 5.9 percent in the same month last year.

Rest of the World

China’s power consumption rose 6.6 percent in 2017 from the year before to 6.31 trillion kWh, according to the NEA data. The nation’s industrial power consumption climbed 5.5 percent to 4.36 trillion kWh in 2017, the NEA said. China’s total installed generation capacity reached 1,777.03 GW by the end of 2017. The world’s No.2 economy consumed a total of 574.6 billion kWh of electricity in December, up 7.4 percent from the year before, according to the NEA data.

Norwegian utility company Statkraft said it has reduced its power trading operations in Turkey due to declining market liquidity and an unpredictable outlook. Statkraft now trades only electricity it generates itself at its two hydropower plants in Turkey. Statkraft sold an unfinished hydropower plant in Turkey last year to local group Limak, after fighting between Turkish security forces and Kurdish PKK militants in 2016 forced it to stop the plant’s construction. The Cakıt and Kargi hydropower plants have a combined capacity of 122 MW and are part of the feed-in regime in Turkey, not exposed to the Turkish forward market.

Nigeria’s electricity grid has been shut down by a fire on a gas pipeline, the power ministry said, as the country’s power infrastructure continues to struggle. Gas supply to several power stations was cut off because of the fire on the Escravos Lagos Pipeline System near Okada in the southern state of Edo, the ministry said. The outage went unnoticed in parts of Nigeria, where blackouts are common and many businesses and households are forced to rely on their own power generators or, for the less wealthy, not have any electricity. The country’s dilapidated power grid is often blamed for hobbling growth in Africa’s largest economy. Most of Nigeria’s power generation is from thermal power stations that use gas, according to the power ministry. In the city of Bauchi in northeast Nigeria, the grid outage went unnoticed because people have already had weeks of power cuts.

Morupule B Power Station, a coal-fired power station built by the China National Electric Engineering Corp, has been credited to spurring electricity production in Botswana, Statistics Botswana said. Statistics Botswana said the volume of electricity generated in the third quarter of 2017 stood at 893,831 MWh, an increase of 32.4 percent from 675,047 MWh in the second quarter. Morupule B Power Station, located some 270 km north of the capital Gaborone, accounts for 90 percent of the country’s domestic power generation. The generation of electricity in Botswana started in 1985 with a coal-fired thermal power station at Morupule operating at a capacity of 132 MWh. Prior to that, most of Botswana’s electricity was imported from South Africa’s power utility, Eskom. In 2008, South Africa’s electricity demand started to exceed its supply, resulting in the South African government restricting power exports. The volume of imported electricity decreased by 62.6 percent from 333,355 MWh during the third quarter of 2016 to 124,612 MWh during 2017 third quarter.

Israel is set to open its power generation sector to more competition after workers at IEC agreed a preliminary deal that also aims to help the state-owned utility cut its huge debts. A stand-off between the government, IEC and its workers has long been viewed as a constraint on Israel’s economy. The utility has said it never received enough money, with prices capped by the government, while IEC’s powerful workers’ union has blocked previous attempts to introduce competition. That stands to change, with the union giving its preliminary consent to a reform. A final agreement will be negotiated over the next 45 days. Under the outline agreement, IEC will remain a monopoly in distribution, but supply will be gradually opened up to competition. Areas such as system management and planning will be taken away and sold to a different government-owned company. The government had managed to open the power production market on a small scale in recent years and about a quarter already comes from private operators.

T&D: transmission and distribution, discoms: distribution companies, FY: Financial Year, UP: Uttar Pradesh, BPL: Below Poverty Line, APL: Above Poverty Line, MW: megawatt, GW: gigawatt, UDAY: Ujwal Discom Assurance Yojana, kWh: kilowatt hour, MWh: megawatt hour, GERC: Gujarat Electricity Regulatory Commission, FPPPA: fuel price and power purchase adjustment, UPPCL: UP Power Corp Ltd, JERC: Joint Electricity Regulatory Commission, TPL: Torrent Power Ltd, MSEDCL: Maharashtra State Electricity Distribution Company Ltd, SDR: strategic debt restructuring, km: kilometre, PLF: plant load factor, NEA: National Energy Administration, IEC: Israel Electric Corp

Courtesy: Energy News Monitor | Volume XIV; Issue 34