Lydia Powell, Observer Research Foundation

Formal and informal conversations over ambitions and commitments to combat climate change are going on in India and other important regions of the world as part of preparations for discussions in Lima in 2014 and Paris in 2015. Most of these conversations are beyond amateur observers who are not familiar with the vocabulary invented for the purpose of climate negotiations. But there is something that even they would understand very clearly and that is that the climate has not changed in the last six decades when it comes to conversations between diversely developed countries.

Nobel Laureate Gunnar Myrdal observed in his 1968 classic, ‘Asian Drama: An Inquiry into the Poverty of Nations’ that post war interest in other (underdeveloped) countries started with the rise of new independent States after the liquidation of colonial power system and the influence of communism in their ambitious plans (to develop into advanced countries).[1] Myrdal pointed out that the Western nations, driven by the ‘immense interests at stake in the neutrality of the underdeveloped States’, sponsored studies on underdeveloped nations that were expected to come to ‘opportune conclusions’ to be presented in the context of the national interest of the sponsoring country. If we replace ‘communism’ with ‘industrialisation plans’ of developing countries, we will arrive at climate discourses today. Unimaginable sums of money are underwriting studies on climate change to tell the target country (or region) how it will be ruined by climate change if it does not change its plans for energy driven development and tell the sponsoring country how preventing this from happening would be in its (sponsoring country’s) national interest. The ‘opportune conclusion’ here is that if developing countries reduce carbon emissions (‘turn away from communism’) then developed countries do not have to compromise on their own national interests (‘will not have too many enemies to fight with’).

Csanad Toth, who was Vice President of the Inter-American Foundation and a Visiting Fellow at the Overseas Development Council observers in an insightful article written in 1978 that States were seen as ‘red’ or ‘dead’ (primarily by the United States) and with ‘naive and idealist arrogance’ that Toth says was typical of that age, despatched ‘development gorillas’ all over the world to fight the ‘war against poverty’ and ‘population growth’ thought to be the cause of poverty on the basis of ‘strategies’ and ‘tactics’ that were designed for the purpose.[2] According to Toth, development was a military exercise and people in the developed world were ‘targets’. Toth also describes how the humiliating defeat in Vietnam changed the war like vision on development to one of negative problem solving. People were not targets anymore but objects with needs defined by their deficiencies and not their potential. Toth describes how a ‘Malthusian spectre of the apocalypse’ was presented using inadequacies in the educational attainment, nutritional intake, health status and housing conditions. If we come to the present, we can see that nothing much has changed except that the development gorilla has been replaced by the climate gorilla fighting a war on emissions (or fossil fuel use). People are not victims of poverty but villains who burn coal (even if it was used to light up a single bulb for the first time or just to keep warm). On the whole, the same Malthusian crisis narrative underpins climate related reports sponsored by western think tanks and development assistance agencies.

The most surprising consistency between then (developing the under-developed) and now (combating climate change) is that the material resources committed to develop or clean up under-developed countries remains insignificant compared to the grand visions of development and climate safety that the rich world supposedly desires for the under-developed world. Even at the height of the cold war development spending by the United States (for combating communism) was less than 5% of its military spending.[3] According to a UN exhibit in a study by the International Peace Bureau, global military spending was more than 12 times official development assistance in 2010.[4] According to the UN most rich countries have failed to meet their target of 0.7% of Gross National Income (GNI) for overseas development assistance barring a few Nordic countries. According to a study by the University of Zurich, share of mitigation projects (alternative energy) in total aid projects of OECD nations peaked at just over 0.02% after the oil crises in the early 1980s and is currently at less than 0.015%.[5] What this piece of data says is that problems in oil supply were considered to be bigger threats than climate change. The argument being made here is not that rich countries should part with more money but to ask if they actually believe in the ideas that they promote. The reports that they produce says that climate change is impending Armageddon and that it can only be addressed by spending huge sums of money on new forms of energy, efficiency technologies and so on. Logically if they believe what they are saying should they not be spending a little bit more? Or are these reports intended to induce poor countries to change their priorities and spend on things that they would have otherwise not considered a priority.

At the time when development was the weapon of choice and population growth was the enemy studies that showed a link between population growth and development were used to inject a sense of objectivity into the discourse. Today a similar sense of objectivity is introduced by what is often referred to as the scientific consensus over the science of climate change. Two issues can be raised here. First neither the conversation over development nor the conversation over climate change is about science.  It is about politics or what we could call social science (who gets what and at whose cost and who gets to decide who gets what) and as Myrdal pointed out there is no such thing as value free social science.[6] The value laden climate discourse has always been a contest between forces of instrumentality and the forces seeking intrinsic values such as fairness and equity. Developed countries represent the instrumentality dimension that explain voluminous reports on Green House Gas (GHG) build up in the atmosphere and plans for global surveillance on emission of GHGs. As observed by Damodaran, the problem is that this type of instrumentalism denies freedom which affects intrinsic human values such as equity and fairness considered to be basic human rights.[7] Instrumentalism which makes science and technology more real is social construction (embedded in social and cultural factors) and this is why it is possible for developed countries to argue that instrumental positions should negate concerns for equity and fairness. Myrdal observed that there are no exclusively economic problems (in poor countries) that could be dealt with economic solutions like markets, wages, prices, employment, savings, investment etc; there are just ‘problems’. If we can borrow his insightful words, there are no exclusive climate problems in the poor world that could be dealt with solutions like low carbon technologies, carbon markets, national mandates and missions, there are just ‘problems’. What instrumentalism does is to turn this poor man’s problem into just a speck of dust that must be wiped out from the rich man’s solution.

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 14

[1]MYRDAL, Gunnar, 1968. Asian drama: An inquiry into the Poverty of Nations. Pantheon: New York

[2] TOTH, Csanad, 1978, The Story of Aid, Worldview, April 1978, pp 42-46

[3] TOTH, Csanad, 1978, The Story of Aid, Worldview, April 1978, pp 42-46

[4] ARCHER, Colin & WILLI, Anette, 2012., 2012. Opportunity Costs: Milita file:///C:/Users/Lydia/Downloads/1111_5190_Opportunity%20Costs.pdfry Spending and the UN’s Development Agenda, International Peace Bureau, Zurich, available at

[5] MICHAELOWA, Axel & MICHAELOWA, Katharina, 2011. Development Aid in the Energy Sector. Presentation at a Conference on Energy Security in Bangalore, India on 28 November 2011

[6] MYRDAL, Gunnar, 1969. Objectivity in Social Science Research. Pantheon: New York

[7] A, Damodharan, 2010. India, Climate Change & the Global Commons. Oxford: New Delhi

Monthly Coal News Commentary: February – March 2019

India

CIL is aiming to meet the 610 mt production and off-take target as per the pact it signed with the coal ministry, despite a production momentum dip in the initial months of the current fiscal. After the high production growth rate of 15 percent in the April-June quarter of FY19, the dry fuel miner had attempted to meet an internal aspirational target of 652 mt for the year but things did not work out as per CIL’s plans. CIL said the MoU target for production and off-take is 610 mt. Based on the trend, production could be around 590 mt, an analyst tracking CIL said. Coal stock at the pitheads of the miner was at 34.76 mt at the end of February. MCL and South Eastern Coalfields Ltd, which were facing agitations, saw an uptrend in production in February, by 17 and 6 percent respectively over the corresponding month of the previous year. The two subsidiaries account for about half of CIL’s total production. But strikes and disruptions in some of the mines there impacted production. CIL’s total production as on February stood at 528 mt, up 6.6 percent in the first 11 months of the current fiscal. Off-take was at 548 mt during the period. Total coal off-take to power sector in the 11 months till February 2019 was 440.8 mt, against 411.5 mt during the same period of the previous year, registering a growth of 7.1 percent.

Coal stock at power stations have risen to roughly 15 days’ operation and the number of plants with precarious inventory has dropped 86 percent to just four from 29 on 31 October  last year when the coal and railway ministries scrambled additional supplies to meet a sudden spike in demand and prepare for summer load. The comfortable fuel stocks at generation units ahead of summer leaves no room for discoms to make excuses for load-shedding and will boost the power ministry’s bid to push its ‘zero blackout’ plan at conference of state power ministers. Available government data shows aggregate coal stock at power plants rising to more than 23 mt on 19 February, indicating an increase of 49 percent from 15.7 mt on 28 February 2018 in spite of a healthy rise in electricity demand. The number of ‘critical’ and ‘super critical plants too has fallen to just two each, indicating a drop of over 84 percent from 25 in the same duration. According to the Central Electricity Authority, which monitors about 114 coal-fired plants, fuel stocks for less than seven and four days are tagged as ‘critical’ and ‘super critical’ for power stations away from mines. For pithead plants, the stipulation is set at five and three days’ stocks. Available data indicate fuel supply by CIL the mainstay of coal-fired power plants, increased by over 7 percent to more than 407 mt in the April-January period against the same period of 2017-18. Despatch of railway rakes to power stations too has risen by 13 percent to 252 in the same period. The record coal supply has helped power plants to replenish dwindling stockpile even after pumping up generation as electricity demand spiked 14 percent during the October festive season and continues to grow apace at 5-6 percent. The coal ministry expect the supply situation to improve further due to re-opening of the Dhanbad-Chandrapura rail line, a key coal evacuation route, in Jharkhand.

Coal imports increased by 5.1 percent to 189.9 mt in the April-January period of the ongoing fiscal, the report by mjunction services showed. Coal imports were at 180.61 mt in the April-January period of the previous fiscal, the report showed. But January month saw a decline in coal import to 17.25 mt from 19.59 mt in the same month of the previous fiscal. In non-coking coal, the coal stock scenario at thermal power plants showed a steady improvement and this helped to curb volumes. Of the total imports during January 2019, non-coking coal shipments were 12.35 mt and coking coal at 3.53 mt.  The government has set a target of 1 bt of coal production by 2019-20 for the mining major, but is considering relaxing the timeline. CIL has announced a production target of 652 mt in 2018-19.

CIL subsidiary — MCL — is likely to miss its production target for the 2018-19 fiscal, as ongoing protests at some of its key mines continue to hamper output. Protests by villagers seeking employment, among other demands, have led to loss of production hours in the current fiscal, mainly impacting the Kaniha mine in Talcher coalfields and Hingula open cast mine. MCL has already revised its aspirational targets to 162.50 mt of coal production and 169 mt of offtake for the fiscal ending 31 March. Even last fiscal’s production of 143 mt might not be equaled.

CIL’s e-auction prices rose about 53 percent in the December quarter, when the company offered half the quantity it did a year ago after diverting supplies to power plants. It offered 14.65 mt of coal during the quarter against 30.8 mt a year earlier. As a result, average prices rose to ₹2,847/tonne from ₹1,859/tonne. CIL increased supplies to power, its priority sector, at the cost of other customers. The government had asked CIL’s subsidiaries to increase supplies to the power sector.

Illegal coal business is on the rise in Bokaro causing a huge loss to state exchequer. Two trucks loaded with illegal coal were seized during a raid at an illegal coal depot at Bodiya Basti under Bermo Thermal police station. 30 tonne of coal which were stolen and stocked by the coal thieves from the abandoned coal mines of CCL. Thousands of tonnes of coals, which are excavated illegally from forest lands, abandoned CCL mines of rural areas of Bokaro and Dhanbad, are being smuggled to West Bengal through the Chandankyari area of the district. The coal mafias of both Jharkhand and West Bengal run this illegal trade jointly.

The Centre has cancelled the sixth and seventh rounds of coal mines auction under which it was planning to put on sale 19 blocks. However, the government did not specify the reasons for the cancellation. Under the sixth round, the government had earlier announced the auction of 13 blocks for the regulated sectors, including iron and steel, cement and aluminium. The mines were Brahampuri, Bundu, Gondkari, Gondulpara, Jaganathpur A, JaganathpurB, Khappa and Extn, Bhaskarpara, Marki Mangli IV, Sondiha, Chitarpur, Jamkhani and Gare Palma IV/1. While in the seventh tranche the coal ministry had said it would auction six coking coal blocks for iron and steel sector. The blocks were Brahmadiha, Choritand Tilaiya, Jogeshwar and Khas Jogeshwar, Rabodh, Rohne and Urtan North. The successful allottees of the 19 coal blocks will be allowed to sell up to 25 percent of the actual production in open market at prices fixed by CIL. The government had last month allowed sale of 25 percent of coal production from captive mines in the open market, a move aimed at increasing competitiveness and making future auction of blocks attractive. The allottee of a coal mine for specified end use or own consumption was not permitted to sell coal in open market earlier.

Auctions for commercial coal mining may not take place soon as the country is entering the election mode. The statement comes amid resistance from the trade unions operating in the coal sector against commercial coal mining. Last year, the Indian National Trade Union Congress-affiliated Indian National Mine Workers Federation threatened to observe a strike at CIL to protest against commercial mining by private companies. In a major reform in the coal sector since its nationalisation in 1973, the government last year allowed private companies to mine the fossil fuel for commercial use, ending the monopoly of state-owned CIL. The reform is expected to bring efficiency in the coal sector by moving from an era of monopoly to competition. The CCEA had in February 2018 approved the methodology for auction of coal mines/ blocks for sale of coal under the Coal Mines (Special Provisions) Act, 2015, and the Mines and Minerals (Development and Regulation) Act, 1957. The opening up of commercial coal mining for the private sector is the most-ambitious coal sector reform since the nationalisation of the sector in 1973.

CIL has decided to reopen a number of mines that were closed earlier due to safety or viability issues. It is an endeavor to generate local employment and increase production of higher grade of coal. Subsidiaries such as CCL — which had closed three mines — and Bharat Coking Coal — that has many such mines — are collating data and assessing feasibility. CIL said surplus manpower can also be deployed at such mines. Central Coalfields reopened the Rajhara coal mine in Jharkhand, where operations had been suspended since 2010 due to safety concerns. Rajhara was initially an underground mine but after nationalisation it was converted into an opencast mine to recover good quality reserves of coal which otherwise would have been lost. Expected grade of coal from the mine is G9 which is priced at ₹1465/tonne for the power sector. Existing reserves in the mine is estimated at 5 mt. With a capacity to extract 300,000 tonnes of coal per year, the life of the mine is pegged at 18 years.

With the private sector not allowed to do merchant mining of coal, the MDO model is likely to dominate the Indian coal sector once all the mines allocated become operational in 5-6 years. Over 40 mines with an annual capacity to produce more than 500 mt of coal have been allocated to state and central governments besides public sector units through competitive bidding. Currently, coal for merchant mining is not allowed to the private sector and the only available route for them to enter the sector is through the mine developer-cum-operator route. CIL produced over 550 mt of coal last year but the MDO model is fast catching up with CIL that is struggling to meet rising demand from power producers and other industries. Steel producer SAIL, power generator NTPC Ltd, CIL subsidiaries, besides state governments of West Bengal, Odisha, Rajasthan, Telangana, Madhya Pradesh, Andhra Pradesh and Gujarat have adopted the MDO model instead of venturing into mining on their own in the past decade. India meets close to 80 percent of its electricity needs through coal-fired power plants. It is heavily dependent on imports to meet its needs despite having the fifth largest recoverable coal reserves in the world. For a country, which imported over 156 mt coal between April-November 2018, MDO model can reduce import dependency and meet India’s surging energy needs and save foreign exchange. MDO, with its technical expertise, enables faster operationalisation of the coal blocks. Since all capital investment on equipment and infrastructure are borne by the MDO, it is responsible for delivering coal of declared quality and quantity at a mining fee arrived at through competitive bidding or reverse auction. MDO attracts stringent penalties for any delay in development of coal block or shortfall in quantity or deviation in quality, they said adding that MDO hedges the owner from the project and financial risk.

Union cabinet approved sale of 25 percent of coal production from captive mines in open market with payment of additional premium on such sale. The cabinet committee on economic affairs has approved the methodology for allowing allocation of coal mines for specified end use or own consumption to sell 25 percent of actual production in open market with premium of 15 percent on such sale under the (Coal Mines Special Provisions) Act, 2015 and the Mines and Minerals (Development and Regulation) Act 1957. The decision is aimed at increasing competitiveness and to make the future tranches of auction/allotment attractive and commercially viable leading to higher revenues for the government. The move will address the issue of lack of response from bidders during earlier tranches of auction and allotments.

The CCL, the largest coal producer of Jharkhand, is trying to curb coal pilferage and theft through deployment of latest technology in its mines. CCL said every year hundreds of tonnes of coal are lost due to pilferage leading to revenue loss for the company.

The loading of coal at New Mangalore Port has helped the Palakkad division of Southern Railway to record growth in freight loading during the current financial year. The total freight loading in Palakkad division stood at 5.039 mt during April-January of 2018-19 as against the target of 4.762 mt recording a growth of 5.8 percent against the target. The Palakkad division of Southern Railway said the coal loading from New Mangalore Port had helped the division to register improvement in freight loading. The Palakkad division transported 3.645 mt of coal during the period.

Odisha demanded that the Centre immediately take steps to hike coal royalty from 14 percent to 20 percent, and complete sand stowing in closed mines of the state to check soil subsidence. The final recommendation of the study group on coal royalty revision submitted on 5 February 2018 is still under consideration of the central government. Odisha produces about one-fifth of the total coal production in the country. The Mines and Minerals (Development and Regulation) Act permits revision of royalty on coal every three years, but it has remained unchanged during the last six years. However, the rate of clean energy cess levied on coal by the central government has been raised from ₹50 per tonne to ₹400 per tonne during this period. Odhisha demanded a compensation amount of ₹ 82.97 bn towards the cost of about 180 mt of coal extracted in excess of the permissible limits under environment clearance. In two underground mines, closed respectively since 1998 and 2006, the MCL has just completed sand stowing work of 538,000 cubic metre against the total requirement of over 915,000 cubic metre.

Recognized as one the leading mining nations in the world Polish government has prepared ‘West Bengal Project’ that was discussed recently during Bengal Global Business Summit. Poland was partner country of the summit for a third time in a row. Poland looks for collaboration with both PSUs and the biggest private players. During a recent meeting with senior executives of the WBPDCL, Polish companies restated their readiness to provide their Indian counterparts with innovative technologies and solutions for the development of the coal mining sector in India, with particular regard to the Deocha Pachami coal block. The meeting followed the signing of an MoU between the Ministry of Energy of the Republic of Poland and the Ministry of Coal of the Republic of India to increase cooperation in the mining sector. During the meeting, Polish companies expressed their willingness to offer assistance in all aspects of the development of the Deocha Pachami coal block, from the initial exploration of coal reserves, to the development of underground coal mining operations and coal production and extraction. The Deocha Pachami coal block, has estimated coal reserves of over 2 bt – being the largest coal block in Asia, and was recently awarded to the WBPDCL by the union government. As India endeavors to fulfill its ambitious targets to increase domestic coal production to 1 bt annually, Poland stands committed to provide its global expertise and know-how to assist their Indian counterparts in meeting this goal. Poland and India have a long history of collaboration in coal mining. One of the first underground coal mines in India, situated in Moonidih in the present day state of Jharkhand, was developed and operationalized with assistance of Polish mining sector companies in the 1960s.

An action plan has been prepared by Ranchi-based Central Mine Planning and Design Institute for resumption of coal mining in Meghalaya in line with the directions of the NGT. The state government has also framed guidelines for coal mining. The state government had launched a crackdown on illegal coal mining despite a ban imposed by the NGT in 2014 after a major disaster in East Jaintia Hills district when 15 diggers got trapped in a rat-hole mine. The CMPDI has started exploration activity in 1 square kilometre coal block of Khliehriat-Sutnga for preparation of Geological Report and Feasibility study. The government has framed guidelines for coal mining and an action plan has been prepared by the CMPDI to start coal mining in line with the direction of NGT.

The Supreme Court refused to allow miners to transport extracted coal lying at various sites in Meghalaya. Various Interlocutory Applications have been filed for transportation of the coal already mined.  The bench had earlier issued notice to the Meghalaya government, the Centre and others seeking their response on various issues connected with coal mining in the state. The court had said the incident, in which 15 miners got trapped in a rat-hole mine in East Jaintia Hills district, shows that illegal mining continues unabated despite the ban and the state may not be supporting it but has failed to contain illegal mining. The top court was hearing pleas filed by several coal miners seeking permission to transport extracted coal which was lying unattended at various places in the state.

Revival of complaints about coal pollution has given the employees and management of MPT a sense of deja-vu, with port dependents apprehensive that coal handling operations could take the same trajectory as iron ore. With its revenue sources drying up, MPT is counting on the source apportionment study by IIT Bombay to put the complaints about coal pollution to rest. For many years, iron ore was the mainstay of MPT’s operations with over 40 mt being exported in 2010-11 before mining came to a grinding halt in the state. In that year, just seven tonnes of coal was handled by MPT. Currently, South West Port Ltd (JSW) is permitted to handle 400,000 tonnes of coal per month, with similar restrictions being placed on Adani Mormugao Port Terminal Pvt Ltd. IIT Bombay is expected to submit the study by February-end and MPT is counting on the report to give coal handling operations a clean chit. MPT held a stakeholders meeting a week earlier to discuss the issue with stakeholders. However closure of coal-handling operations could put over 1,600 jobs under threat.

NGT’s ‘oversight committee’ has set a 60-day deadline to power companies in Singrauli to completely stop using public roads for transportation of coal. When power generation companies said that there was no option than transporting coal by road, the panel made it clear that there cannot be any relaxation this matter. This panel was constituted by NGT on 28 August 2018, to monitor implementation of its directions. Flyash and dust caused by road transportation of coal continues to be a major problem in the region.

India is keen to collaborate with the US department of energy to source technology for coal gasification to tap into the country’s large reserves, improve its fuel efficiency and reduce dependence on imports. The move was triggered after recent attempts by the government and private players to set up their own coal gasification plants failed. A high-level meeting chaired by NITI Aayog member was held recently with officials from US department of energy. The meeting was called because the government is keen on global partnerships to achieve coal gasification at lower costs and integrate technology for smarter handling of the fuel in an economically viable way. The discussions are in preliminary stage and the challenge for India is the high ash content in indigenous coal.

Rest of the World

China’s coal imports in February fell sharply from January after utilities curbed buying, citing uncertainty over Beijing’s policies on shipments arriving from overseas, while the week-long Lunar New Year holiday also reduced demand. Coal arrivals in February plunged to 17.6 mt, down from 33.50 mt in January, data from the General Administration of Customs showed. The imports fell 15.6 percent from a year ago. The import scrutiny occurred at the same time that rising domestic production before the Lunar New Year caused coal inventories to build at utilities. Coal inventories at China’s six largest coastal power plants rose to 41 days of daily consumption by the middle of February, compared to only 25 days of daily consumption in the first week of March, according to data from the port of Qinghuangdao, a key import terminal for coal.

China’s state planner, the NDRC, said it has approved an open-pit coal mine project in Inner Mongolia region worth 1.46 bn yuan ($218 mn) The mine’s total capacity would be 6 mt a year, the NDRC said. China’s coal consumption is set to rise slightly to 3.89 bt in 2019 from 3.87 bt last year. NDRC said it had approved a new coal mine project in Inner Mongolia region with total investment at 3.37 bn yuan ($499.19 mn). The coal mine project will have an annual capacity of 8 mt.

China has made no changes to its coal import policies nor its inspections of foreign coal cargoes this year. Chinese customs authorities had stepped up environment and safety checks on foreign cargoes. But Chinese coal traders have stopped ordering Australian coal as clearing times through China’s customs have doubled to at least 40 days, according to major buyers in China and international coal merchants, resulting in a sharp fall in Australian prices. Customs clearance typically takes five to 20 days. Now it can be as much as 45 days. The delays have been a large contributor to slump in Australian coal prices. Refinitiv ship tracking data showed coal shipments departing from Australia’s Newcastle port to China fell 30 percent last month compared with December to 18.19 mt.

Customs at China’s northern port of Dalian has banned imports of Australian coal and will cap overall coal imports from all sources to the end of 2019 at 12 mt Dalian Port Group said. The indefinite ban on imports from top supplier Australia, effective since the start of February, comes as major ports elsewhere in China prolong clearing times for Australian coal to at least 40 days. Coal is Australia’s biggest export earner and the Australian dollar tumbled on the news, falling more than 1 percent to as low at $0.7086. Coal imports from Russia and Indonesia will not be affected. Australia’s exports of coal to China in the fourth quarter of 2018 were higher in volume and value than in the same period in 2017. The Dalian ports handled about 14 mt of coal last year, half of which was from Australia. Beijing has been trying to restrict imports of coal more generally to support domestic prices. Dalian had cleared about 6 mt of coal in January that had been delayed since late 2018 as China slowed customs clearance to curb imports. Dalian handles both thermal and coking coal imports but the clamp down is expected to have a bigger impact on coking coal, used in steel making, than thermal coal, used to generate electricity. China bought 28.26 mt of coking coal from Australia in 2018, accounting for 43.5 percent of the country’s total imports of the fuel, customs data showed.

The Indonesian government has set the coal benchmark price (HBA) for March at $90.57/tonne, marking a seventh consecutive month of price fall. February’s benchmark price, which the government uses to calculate a miner’s royalties, was $91.80/tonne. The decline in March benchmark was due to low demand in China. The HBA is a monthly average of the Argus-Indonesia Coal Index (ICI-1), the Platts Kalimantan 5,900 assessment, the Newcastle Export Index and the globalCOAL Newcastle index from the previous month.

The EU energy watchdog urged Bosnia to re-examine a decision to guarantee a Chinese loan to power utility EPBiH for the building of a new unit at the Tuzla coal-fired plant, saying it violates EU energy subsidy rules. The Energy Community, a body established by the EU to extend the bloc’s energy policy to would-be members, said it is committed to supporting a clear and final decision in line with Energy Community law, which would also restore legal certainty for the project. Western Balkan countries are increasingly turning to China for funding as the EU, World Bank and other lenders cut back on financing coal-based projects. Environmentalists have also urged EU policy makers to take a tougher stance on air pollution from the region’s coal power plants, blaming the fumes for 3,900 deaths across Europe and health costs of up to €11.5 bn a year.

Japanese trading house Sojitz Corp said it would sell its 30 percent stake in the BAU thermal coal mine in South Sumatra, Indonesia, to an existing partner for an undisclosed sum. The deal reflects the company’s effort to rebalance its coal assets, shifting away from thermal coal investment and focusing more on coking coal, amid growing global concerns for environment and long-term business sustainability. Sojitz will continue to serve as the BAU’s exclusive sales agent in Japan and continue to provide a stable supply of coal to Japanese market, it said.

The Dutch government has told Vattenfall to close Hemweg 8, its 650 MW coal-fired power plant, by the end of 2019, the Swedish firm said. Last year, the country legislated to shut all power generating plants using coal by the end of 2029, with two of the five having to close by the end of 2024 unless they switch fuels.

More than 90 percent of US coal-fired power plants that are required to monitor groundwater near their coal ash dumps show unsafe levels of toxic metals, according to a study released by environmental groups. The groups, led by the Environmental Integrity Project and Earthjustice, said their findings show the potential harm to drinking water from coal ash and indicate that stronger regulations are needed. Data made public by power companies showed 241 of the 265 plants, or 91 percent, that were subject to the monitoring requirement showed unsafe levels of one or more coal ash components in nearby groundwater compared to EPA standards, according to the analysis by the groups. The environmental groups reviewed data reported from 4,600 groundwater monitoring wells near coal ash dumps of two-thirds of the coal-fired power plants in the US. Coal ash, which is the residue produced from burning coal in coal-fired plants, is stored at hundreds of power plants throughout the country. In response, the Obama administration in 2015 established minimum national standards for the disposal of coal ash, including a requirement that companies monitor groundwater and publish their data. Amid strong pressure from utility and coal companies, the EPA under President Donald Trump last July revised the 2015 rule to suspend groundwater monitoring requirements at coal ash sites if it is determined there is no potential for pollutants to move into certain aquifers. The rule also extended the life of some coal ash ponds from early 2019 to late 2020.

Greece’s PPC said it wants to relaunch a tender for three coal-fired plants and then conclude it in May. Under its post bailout surveillance by its lenders, Greece has agreed to sell the plants to open up the market after an EU court ruled that PPC has abused its dominance in the coal market. The sale, which is overseen by the European Commission, failed to attract any satisfactory bids.

The Finnish parliament approved a government proposal to ban the use of coal to produce energy from 1 May 2029. As a result of the decision, coal plants owned by Fortum and other energy firms will have to halt operations, though a programme will be implemented to compensate some of the costs. In the first nine months of 2018, coal represented eight percent of Finland’s total energy consumption, according to Statistics Finland data. After that date, coal can only be used in an emergency. In 2017, Finland was among the co-founders of the Powering Past Coal alliance, and the country’s Ministry of Economic Affairs and Employment said at the time it aimed to phase out coal from energy production by 2030.

Colombia’s coal production and exports are likely to remain steady this year, companies said, amid predictions international prices for the fuel will fall in 2019. The Andean nation is the world’s fifth-largest exporter of coal. Overall Colombia production figures for last year are expected to be released sometime. Annual output in 2017 was down 1.2 percent from the year before, to 89.4 mt. Analyst Fitch Solutions reduced its Colombian coal production growth forecast from 4.5 percent to 0 percent in January. Thermal coal prices will fall to an average of $85/tonne in 2019, from $101.4/tonne last year, Fitch Solutions said in a note.

CIL: Coal India Ltd, FY: Financial Year, mt: million tonnes, mn: million, bn: billion, MoU: Memorandum of Understanding, discoms: distribution companies, bt: billion tonnes, MCL: Mahanadi Coalfields Ltd, CCL: Central Coalfields Ltd, CCEA: Cabinet Committee on Economic Affairs, MDO: mine developer and operator, WBPDCL: West Bengal Power Development Corp Ltd, NGT: National Green Tribunal, CMPDI: Central Mine Planning and Design Institute, MPT: Mormugao Port Trust, IIT: Indian Institute of Technology, US: United States, NDRC: National Development and Reform Commission, EU: European Union, BAU: Bara Alam Utama, MW: megawatt, EPA: Environmental Protection Agency, PPC: Public Power Corp

Courtesy: Energy News Monitor | Volume XV; Issue 41

Monthly Gas News Commentary: February – March 2019

India

AG&P plans to invest Rs100 bn in its city gas business in India over eight years. AG&P plans to haul LNG via tankers from import terminals to planned satellite terminals in its licence areas to quickly launch CNG services without waiting for pipelines to be built. GAIL (India) Ltd operates a satellite LNG station in Bhubaneswar to serve customers in the absence of a pipeline. The Philippines company plans to launch a few CNG stations by the end of this year and piped gas services by next year-end. AG&P is confident of meeting its target of connecting 12 mn households, building 1,500 CNG stations and laying 17,000 inch-km of steel pipeline over eight years, allaying apprehension that the company had been over-ambitious in its bids for licences.

In the last bid round, it had managed to bag just 5 out of the 86 GAs put on offer. In the previous 9^th round which was awarded just a few months back, Adani Gas had won city gas licences for 13 cities on its own and nine in a joint venture with IOC. IOC had won licences for seven cities on its own. Bharat Gas Resources Ltd had walked away with 11 cities while Torrent Gas had made 10 winning bids. Sholagasco Pvt Ltd bid for 9 out of the 50 GAs put on offer in the 10th round while Gujarat Gas bid for seven and Petronet LNG Ltd put in bids for five areas. PNGRB had at the close of bidding on 5 February stated about 225 bids were received for licence to retail CNG to automobiles and piped natural gas to households in 50 GAs offered in the 10^th CGD bidding round. It had not revealed the names of the bidders then. Eight out of the 50 GAs received single bids, with IOC being the only applicant for six areas in Bihar and Jharkhand while other two single bidders were Bharat Gas Resources Ltd and GAIL Gas Ltd for one area each. In the 10^th round, bidders were asked to quote the number of CNG stations to be set up and the number of domestic cooking gas connections to be given in the first eight years of operation. Also, they had to quote the length of pipeline to be laid in the GA and the tariff proposed for city gas and CNG according to PNGRB.

IOC has emerged as the biggest bidder for city gas licences in the 10th bid round that also saw Adani Group, HPCL and Indraprastha Gas Ltd as the other prominent bidders, according to the PNGRG. IOC is looking to diversify into natural gas distribution business big time, bid for licences to retail CNG to automobiles and piped natural gas to households in 35 out of the 50 cities put on offer for the 10^th round and another seven in partnership with Adani Gas. Adani Gas bid for 19 cities on its own and seven in partnership with IOC, the PNGRB said after opening of bids between 7 and 9 February. HPCL, a subsidiary of ONGC emerged as the third largest bidder, putting in bids for 24 towns and cities while Gujarat-based Torrent Gas applied for 20 areas. Indraprastha Gas Ltd, which retails CNG and piped cooking gas in the national capital, put in bids for 15 areas while Bharat Gas Resources Ltd, a subsidiary of state-owned BPCL bid for 14 cities. GAIL, which is country’s biggest gas marketer and transporting company, put in bids for just 10 areas through its subsidiary GAIL Gas Ltd.

Oil regulator PNGRB has rejected Adani Gas Ltd’s application for authorisation to retail CNG to automobiles and piped natural gas to households in Jaipur and Udaipur, saying the company was not in compliance with regulations for a licence. PNGRB gave detailed reasons for rejecting Adani Gas Ltd’s claim of having ‘deemed authorisation’ to operate CGD network in the two cities before the regulator came into existence. Adani Gas had, in response to a November 2005 invitation of Rajasthan government, bid for setting up the CGD network in Udaipur and Jaipur. The state government on 20 March 2006 gave a no objection certificate, subject to certain conditions, to the company for retailing CNG and piped natural gas in Udaipur and Jaipur. Adani Gas in the same month deposited the commitment fee of Rs20 mn. PNGRB said Adani Gas meets the minimum eligibility criteria but did not comply with the requirement of making committed investments and physical progress in rollout of CGD network in both the cities. Also, it had not tied up gas for supply through the CGD networks.

A Rs90 bn gas-grid project has been approved to transport natural gas among northeastern states and West Bengal. ONGC said the North East Gas Grid is a joint venture of five oil and natural gas companies – GAIL, IOC, OIL, NRL and ONGC. Huge onshore gas reserves have been found in Assam, Gujarat, Andhra Pradesh, Tamil Nadu and Tripura, which is also the number one gas producing state for ONGC. Use of Tripura’s gas reserve would also improve revenue and income of the state, he said. ONGC has been working in Tripura for the past five decades. It has drilled 225 wells and found gas in 116. A 726 MW power plant in southern Tripura is already using local reserves.

India is looking to expedite discovery efforts to establish the country’s shale O&G potential and has asked companies to submit a plan. In late 2013, India gave rights to ONGC to explore for shale O&G reserves. However, after years of exploratory reserves, it has failed to find significant resources. In January, India’s O&G regulator DGH held a meeting with representatives from various private and government companies to urge them to pursue shale resources in the O&G blocks already held by them. All CBM developers were invited to the meeting in January. Currently CBM gas is produced by three companies in India – Reliance Industries Ltd, Essar O&G Exploration and Production Ltd and Great Eastern Energy Corp Ltd. CBM is a kind of natural gas which is found in coal deposits. ONGC has CBM blocks. Currently the most promising region of shale deposits is around the eastern part of India called as Damodar Valley basin, where the first exploration for shale is expected to start.

To better prospects for upstream players, the government is likely to raise the price of domestically produced natural gas by over 10 percent to over $3.72 per mmBtu with effect from 1 April. The price of gas produced from difficult fields will rise to about $9 per mmBtu from current $7.67 per mmBtu. The increase in price will boost earnings of producers but will also lead to a rise in price of CNG, which uses natural gas as input. It would also lead to higher cost of natural gas piped to households for cooking purposes as well as of feedstock cost for manufacturing of fertilisers and petrochemicals. India imports half of its gas which costs more than double the domestic rate. Natural gas prices were last hiked on 1 October 2018, by 10 percent when rates moved up to $3.36 per mmBtu from $3.06. The increase will translate into a higher cap price based on alternate fuels for undeveloped gas finds in difficult areas like deep sea, which are unviable to develop as per the existing pricing formula. The price for such fields from 1 April would be about $9 per mmBtu for six month beginning 1 April as compared to $7.67 currently. All of its gas, as well as that of OIL and private sector RIL’s KG-D6 block, are sold at the formula approved in October 2014. This formula, however, does not cover gas from fields like Panna/Mukta and Tapti in western offshore and Ravva in the Bay of Bengal.

The government plan to offer PSUs special incentives for natural gas discoveries in difficult and unviable areas will help raise India’s natural gas production as it will unlock output in a dozen fields of ONGC and OIL. India currently produces about 90 mmscmd of natural gas and has ambitious plans to double output by 2022 to reduce its reliance on imports and replace some of the polluting liquid fuels to cut emissions. ONGC and OIL have a dozen discoveries, which are unviable at current government mandated gas price. ONGC and OIL have not been able to develop the discoveries or bring them to production as the current gas price of $3.36 per mmBtu is way lower than the cost of production. ONGC has about 35 bcm of recoverable reserves in discoveries in the shallow sea off Andhra Pradesh on the east and off Gujarat and Mumbai on the west coast blocks. The three blocks in KG basin, Gulf of Kutch and Mumbai offshore can produce about 10 mmscmd of gas and an equivalent amount can be produced from its onshore discoveries in blocks like Bantumili, Mandapeta and Bhuvanagiri. About 5 mmscmd of production can be added by making some investment in existing fields like Mumbai High South, Neelam and B-127 Cluster in the Arabian Sea. OIL has an onland discovery in the KG basin in Andhra Pradesh with over 3 bcm of recoverable reserves, but needs a higher price to bring it to production. ONGC and OIL want a price of over $6 per mmBtu to help them produce the gas without suffering any losses. The government had in October 2014, evolved a new pricing formula using rates prevalent in gas surplus nations like US, Canada and Russia to determine price in a net importing country. Prices using this formula are calculated semi-annually. While the government has allowed a higher rate of $7.67 per mmBtu for gas fields in difficult areas like the deep sea, ONGC’s KG basin block KG-OSN-2004/1, which has about 15 bcm of recoverable reserves, is in shallow waters and does not qualify as a ‘difficult field’. Similar is the fate of Mumbai basin block MB-OSN-2005/1 on the western side. The block GK-28/42 in Gulf of Kutch is a nomination block which does not qualify for higher rates. The onland discoveries of ONGC and OIL, too, do not qualify for the higher rates. While ONGC’s KG block can produce a peak output of 5 mmscmd, the same from GK-28/42 is expected to be around 2.5 mmscmd. Peak output from MB-OSN-2005/1 is expected to a little less than 3 mmscmd. The cost of production of natural gas in the prolific KG basin is between $4.99 to $7.30 per mmBtu.

Though ONGC is digging appraisal wells at the DDW field it acquired from GSPC, it is still to submit the FDP and has sought time till December 2019 from the empowered committee of secretaries. ONGC was initially supposed to submit the FDP by February 2018. ONGC completed the acquisition of GSPC’s 80 percent in DDW in August 2017. According to the DGH-approved FDP submitted by GSPC, commercial production was to start by 2011. However, trial gas production started in 2014 and commercial production in April 2016. ONGC has got assurance from the Gujarat government that the PSU (Public Sector Undertaking) will get at least $6 per mmBtu for the gas from the DDW block in the first year of production. The price will see staggered increments every year to reach $6.9 per mmBtu in the fifth year and remain at that level during the remaining life of the asset. In case, the government-determined gas prices are higher than that offered by the Gujarat government, ONGC will realise the higher price from the market. For the October 2018-March 2019, the price for gas discoveries deepwater, ultra deepwater and high-pressure-high-temperature areas has been fixed at $7.67 per mmBtu. ONGC and its joint venture partners have struck long-term agreements to sell 9.5 mtpa of LNG from their Mozambique Rovuma Offshore Area 1 project, and will take a final investment decision for the project in the first half of 2019, the state-run explorer said. Indian companies together own 30 percent participating interest in the Mozambique project, with ONGC owning 16 percent, OIL 4 percent and BPCL 10 percent. Anadarko is the operator of the project with 26.5 percent participating interest. ONGC and other project developers have entered into agreement with Tokyo Gas and Centrica LNG Company for sale of 2.6 mtpa from the start of production until the early 2040s.

Petronet LNG Ltd may invest in Tellurian Inc’s proposed Driftwood LNG liquefaction and export facility near Lake Charles, La., Tellurian reported. Petronet is India’s largest LNG importer, operating 20 mtpa of receiving terminal capacity with an additional 2.5 mtpa of capacity under construction at its Dahej expansion and a further 5 mtpa proposed at Gangavaram. Petronet is exploring a possible Driftwood equity investment under a memorandum of understanding that it has signed with Tellurian. The approximately 27.6 mtpa Louisiana project would also include natural gas production, gathering and processing infrastructure as well as the 154.5 km Driftwood Pipeline.

GAIL has set up a satellite LNG terminal in Bhubaneswar to supply local customers in the absence of a gas pipeline — an innovative model that may get replicated by other city gas distributors eager to quickly start supply in new licence areas where gas pipelines are yet to reach. City gas licences have proliferated lately in the country: the downstream regulator offered 86 licences last year, and the process to award another 50 is under way. Just a year ago, licences were limited to 92 geographical areas that covered just a fifth of country’s population. After the current round of licensing is complete in a month or so, 70% of the country’s population will have been covered. But taking gas to people can take much longer than distributing licences. GAIL, which has a licence to supply gas to Bhubaneswar, decided last year not to wait for the gas pipeline, which is expected to connect the city next year. It started using gas cascades to supply natural gas to homes, shops and vehicles. This involved bringing in gas cascades from Andhra Pradesh to serve local demand, which is about 3,800 kilogram a day. GAIL switched its supply method. It started operating a satellite LNG storage and regasification terminal in Bhubaneswar, which can cater to 3,000 CNG vehicles and 1,000 homes. This is the first such operation in the country but satellite LNG terminals are quite popular in several countries to supply gas to areas where laying gas pipelines are difficult or economically unviable.

GAIL has terminated a contract given to IL&FS for laying pipeline in Bokaro-Durgapur section due to poor project progress. The company said that the Bokaro-Durgapur section (124 km) is now re-tendered and awarded to three different contractors to expedite construction efforts. Besides, GAIL also informed that the project consultant, Engineers India Ltd, was replaced by Metallurgical & Engineering Consultants (India) Ltd for overseeing the project activities in this crucial stretch.

In a swift move to safeguard project schedule of the Pradhan Mantri Urja Ganga natural gas pipeline to eastern India states, GAIL as the owner and operator of the project under execution has offloaded the pipe laying contract from IL&FS due to poor project progress driven on account of acute financial crisis, GAIL said.

India’s plan to increase the share of natural gas to 15 percent of the country’s total energy mix by 2030, from 6 percent currently, seems “increasingly ambitious”, research and consultancy firm WoodMac said. Wood Mackenzie, said that CGD will be a major driver of natural gas demand in the country and will account for 15 percent of the overall gas market, up from 7 percent currently. WoodMac projects the CGD sector to attract over $1.3 bn in investments in the coming decade. WoodMac said that re-gasification infrastructure remains a concern as Jaigarh floating storage regasification unit and Mundra and Ennore regasification terminals were not commissioned as expected in 2018, reducing expectations of demand in the later part of the year. The research and consultancy firm has projected India’s LNG demand to increase to 25 mtpa in 2019, an 8.7 percent increase over 2018. On the natural gas supply front WoodMac said that domestic gas production failed to grow in 2018 and growth is expected to remain moderate through to 2020. KG basin is expected to witness frenzied construction and installation activities in next two years. ONGC and RIL awarded major contracts for their deep-water fields in the KG basin through 2018. This includes ONGC’s KG-98/2 cluster-2 fields and RIL’s R-series and Satellite fields in the KG-D6 block. WoodMac said a majority of gas produced in the country is priced below $4 per thousand cubic feet and a move towards market-driven pricing for production of natural gas would lead to monetisation of 1.5 trillion cubic feet of shallow-water gas immediately.

Rest of the World

Global LNG trade will rise 11 percent to 354 mt this year as new facilities increase supplies to Europe and Asia, Royal Dutch Shell said in an annual LNG report. Shell, the largest buyer and seller of LNG in the world, said trade rose by 27 mt last year, with Chinese demand growth accounting for 16 mt of those volumes. Shell’s forecasts, which see LNG demand climbing to 384 mt next year, reflect a burgeoning industry with new production facilities opening in Australia, the United States and Russia and more countries becoming importers by constructing receiving terminals. Due to the uneven progress of developing liquefaction-export facilities on the one hand and regasification-import terminals on the other, many analysts see the global market becoming oversupplied if not this year then next year. But most also see a supply crunch around the mid-2020s because, at the moment, there are not enough liquefaction facilities being planned, financed and built. Such projects are underpinned by long-term supply contracts struck years in advance by their operators. Between 2014 and 2017 buyers were signing shorter-duration contracts for smaller volumes, making financing difficult to complete. However, Shell said the duration of contracts signed last year had on average more than doubled to 13 years.

Europe is expected to be the fastest-growing market for LNG this year and will absorb the fuel despite Russia supplying record-high volumes by pipelines. The region is seen getting 20-30 mt more LNG this year, about double the increase in Asia, Royal Dutch Shell Plc said. Asia’s growth won’t be as strong as in the last two years and there will be a “resurgence” of LNG flowing into European markets, according to Shell, which controlled about 22 percent of global LNG last year. Europe needs additional imports of gas to make up for declining domestic production. It can fill the shortfall with imports from Russia, its biggest supplier, or LNG, where global supply is expected to grow almost 35 mt this year, or more than 10 percent of last year’s demand. Shell is not only a major LNG player but also a financial backer of the Nord Stream 2 pipeline that would increase Russia’s ability to ship its low-cost gas directly to Germany. As the LNG market is expected to tighten in the early 2020s before new plants start producing, Europe may struggle to attract cargoes because other regions may scramble for gas.

The EU reached a provisional deal on new rules governing import gas pipelines, casting doubt over the operating structure of Russia’s planned Nord Stream 2. The Russian pipeline already faces uncertainty after Denmark’s potential ban on its planned route through its territorial waters and sanction threats by the United States. The draft law calls for all import pipelines to meet EU rules by not being directly owned by gas suppliers, applying non-discriminatory tariffs and transparent reporting and opening at least 10 percent of capacity to third parties. EU is closing a loophole as its dependency on natural gas imports increases.

Russia’s Gazprom increased its share of the European gas market last year despite a rising challenge from imports of US LNG the company said. Gazprom’s share of the European gas market rose to a record high 36.7 percent last year from 34.7 percent in 2017, the company said. Gazprom has also faced a rise in imports of US LNG into Europe, which saw a near fivefold increase this winter. Europe accounts for around two-thirds of Gazprom’s gas sales. Gazprom’s average gas price in Europe was $245.50 per 1,000 cubic meters last year and it expects a price of $230-$250 this year. In Russia, Gazprom competes with oil producer Rosneft and private gas firm Novatek. Both have long lobbied for the right to export gas by pipeline but for now are limited to LNG sales. As for Gazprom, it plans to build a third line at its Sakhalin-2 plant in Russia’s Far East in 2023-2024.

Gazprom is looking to gain an even larger gas market share in Europe following record-high 2018 exports, expecting a decline in Europe’s gas output combined with rising demand, the company said. Last year it sold more than 200 bcm of gas to Europe, including Turkey, while its gas market share in the region rose to more than a third. EU gas production will halve by 2040, the Paris-based International Energy Agency has said. Moscow has piped gas to Europe from its fields in Siberia and northern Russia for more than 50 years. It can ill afford losing the lucrative market for Kremlin-run Gazprom, whose sales account for over 5 percent of Russia’s $1.6 trillion economy.

Gazprom will start gas supplies to China from 1 December, a month earlier than planned, the gas producer said. Deliveries of gas to China via the Power of Siberia pipeline were due to begin at the end of December 2019, but the project is only expected to reach full capacity in 2025.

Russia was ready to keep gas transit through Ukraine after 2019, despite the construction of Nord Stream 2 pipeline, which is to be built in the Baltic Sea. Russia can use Ukraine for gas transit in the future “under certain conditions.” Russia’s planned doubling of capacity on the Nord Stream pipeline across the Baltic Sea to Germany could help Moscow bypass exports via Ukraine.

Uzbekistan is seeking a $300 mn loan from Russia’s Gazprombank as it wants to increase output at its state-run Shurtan gas and chemical complex, the president’s office said. The complex is operated by Uzbekistan’s state oil and gas company Uzbekneftegaz, a strategic partner of Russian state gas company Gazprom which is a major shareholder in Gazprombank. Gazprom has been operating energy projects in Uzbekistan since 2002. Gazprombank, Russia’s third biggest lender by assets, said that it aimed for further development of mutually beneficial relations with Uzbekistan in various areas including energy and was considering the $300 mn loan as part of cooperation with Uzbekneftegaz.

Total has agreed to buy a 10 percent stake in the Arctic LNG 2 project from Russia’s Novatek, as the French energy group looks to build up its presence in the area to service a fast-growing Asian market. The companies said Total would also have the opportunity to buy a 10-15 percent direct interest in all Novatek’s future LNG projects on the Yamal and Gydan peninsulas. Novatek said that, as well as paying for the 10 percent stake, Total would provide some financing through capital investment for Arctic LNG 2, adding it expected preliminary capex for the project to be $20-21 bn. Total said the LNG would be delivered to international markets by a fleet of ice-class LNG carriers using the Northern Sea Route and a trans-shipment terminal in Kamchatka for cargoes to Asia, and one close to Murmansk for European cargoes. A final investment decision to go ahead with the project is expected to be taken in the second half of 2019, with plans to start up the first liquefaction train in 2023, Total said.

Royal Dutch Shell aims to boost output and recoverable reserves from its Ormen Lange gas field off Norway by installing subsea compressors. Output from Shell-operated Ormen Lange, Norway’s second-largest gas field and one of the key external gas supply sources for Britain, has been gradually declining since its 2012 peak. The company postponed plans to artificially increase the field’s pressure to pump out more gas in 2014 due to high costs. Ormen Lange produced 15.7 bcm of natural gas in 2018, down from a peak of 22.2 bcm in 2012. Shell, which sold its shares in the Draugen and Gjoea fields to OKEA, planned to keep its stakes in the Ormen Lange field, Nyhamna gas processing field as well as Norway’s largest gas field Troll.

Royal Dutch Shell aims to increase LNG exports from Egypt this year as it ramps up production from a West Delta field. The company shipped 12 LNG cargoes from the Idku plant last year and is “hoping for more” this year. Shell was among companies that won new exploration rights in Egypt. It secured five of 12 concessions offered in a bidding round, according to results announced by Petroleum Minister Tarek El Molla. Idku has capacity of about 1.2 bcf per day.

Royal Dutch Shell and PetroChina are at loggerheads over gas sales pricing at their Arrow Energy joint venture, holding up development of Australia’s biggest coal seam gas resource. PetroChina, the listed arm of China National Petroleum Corp, is eager to start developing Arrow’s 140 bcm of gas in the Surat Basin in Queensland to turn around loss-making Arrow Energy, one of its key overseas assets. It is at the mercy of venture partner Shell, however, as the Anglo-Dutch oil company is also majority owner of Arrow’s biggest potential customer, QCLNG, a LNG plant on an island off Queensland state. Shell and PetroChina acquired the Surat gas resource in a $2.5 bn takeover of Arrow in 2010. They had expected to reach a final investment decision on the Surat project in 2018, with first production around 2020, after the Arrow venture signed a 27-year deal at end-2017 to supply gas from Surat to QCLNG. PetroChina, though, is unhappy with the price in the sales agreement with QCLNG and the technical plan for developing the gas. Shell still hopes to secure approval in time to deliver first gas in 2021. PetroChina’s takeover of Arrow with Shell in 2010 was its first investment in Australia’s coal seam gas sector, seen as a key acquisition at the time, but it has been a big loss-maker. QCLNG is one of three LNG export plants built in Queensland, all fed by coal seam gas. QCLNG and one of its rivals are struggling to operate at full capacity as coal seam gas wells have proven to be less productive than expected.

Germany imported 9.7 percent more gas in 2018 than the year before and raised its import bill by 23.4 percent. The volume of imports from January through to December was 126 bcm according to trade statistics office BAFA, which releases data with a time lag. German importers paid €23.7 bn ($26.70 bn) for gas in the year, mirroring a rise in oil prices. Traders of gas, power and carbon watch winter gas imports especially as possible imbalances in supply and demand can drive up prices and volumes in all three markets. Europe’s biggest economy uses gas for industry, heating homes and power generation. Germany’s gas supply is mainly imported from Russia, Norway, the Netherlands, Britain and Denmark via pipelines. Europe on the whole is increasingly absorbing volumes of LNG arriving on specialised vessels from the world market, namely the United States, a trend which has boosted storage levels and pushed down price spreads.

The Netherlands will remain a heavy user of natural gas for years to come, despite big production cuts at its Groningen field, gas trading company GasTerra said. The Dutch have been one of the major gas suppliers in Europe for decades, exploiting what once was Europe’s largest gas field in the northern region of Groningen. But the Dutch government last year said it would end production at Groningen by 2030 after a string of earthquakes directly related to gas extraction damaged thousands of houses and buildings. The Dutch still rely on natural gas for about 40 percent of their total energy needs and are not expected to end their gas dependency soon. Most of the gas will come from abroad, GasTerra said, as the Groningen production cuts turned the Netherlands into a net importer of gas for the first time since the 1950’s two years ago. Imported gas covered almost 55 percent of the total Dutch gas need in 2017, Statistics Netherlands said last year. The growing demand for foreign gas has so far been mainly met by Norway, with its exports to the Netherlands up by a third in 2017. GasTerra is the sole buyer of Groningen gas, which is extracted by a Royal Dutch Shell and Exxon Mobil joint venture. The company also trades gas in the Netherlands and beyond from smaller Dutch fields and from Norway and Russia. Groningen output has already been cut by 60 percent since its 2013 peak of 53.8 bcm per year and dropped by a fifth in the most recent year, to 20.1 bcm. Extraction is set to fall to 15.9 bcm in the year through October 2020, the government said.

Gas transmission operators of Finland, Latvia and Estonia signed an agreement to set up a single gas transmission tariff zone for the three countries from the start of 2020. The agreement unifies entry point tariffs on the external borders of the region and removes commercial interconnection points between countries. The deal is expected to lead to higher market liquidity by making it easier for shippers and traders to sell gas to the whole region. Gas between the Baltic states and Finland will be piped across the Baltic Sea by 1 January 2020, when a 7.2 mcm per day pipeline called Balticconnector is due to start up. The pipeline is being built to link the countries and help diversify the region’s gas supplies, which largely come from Russia, by creating more links with other gas projects in Europe. The agreement reached between the three operators outlines the cost structure for transmission and how related compensation and entry revenues will be distributed amongst them.

Venture Global LNG said it had received approval to export LNG from its Louisiana facility to non-free trade agreement countries. The company said the US Department of Energy’s Office of Fossil Energy had authorized it to export up to 620 bcf per year of natural gas (1.7 bcf per day) for a period of 25 years. Venture Global’s Calcasieu Pass facility, which is located in Cameron Parish, Louisiana, can produce about 10 mtpa of LNG, or about 1.3 bcf per day of natural gas.

ExxonMobil added another giant gas discovery to the east Mediterranean region after finding a gas-bearing reservoir offshore Cyprus but infrastructure bottlenecks and geopolitical disputes mean output from the field could be far off. Exxon, together with partner Qatar Petroleum, estimated in-place gas resources in the reservoir at 5 to 8 tcf of gas, similar order of magnitude to the Aphrodite and Calypso gas finds nearby, also in Cypriot waters. The region’s gas output has begun to soar thanks to older discoveries finally bearing fruit. Israel’s Leviathan field, found in 2010 with around 22 tcf, will fully come online in November, though the 2015 Zohr discovery offshore Egypt with up to 30 tcf is already producing. Exxon’s Vice-President of Exploration for Europe, Russia and the Caspian, Tristan Aspray, said the company will now analyze data from drilling the reservoir, known as Glaucus-1. Exxon owns a 60 percent of the block, Block 10, with QP holding the rest. Industry consultants Wood Mackenzie said they estimated recoverable resources of Exxon’s field to be 4.55 tcf. That compares to its 6.4 tcf estimate for Calypso, found by Italy’s ENI and France’s Total last year. The new discoveries have prompted Egypt, which has the ability to liquefy and regasify gas for LNG trade, to try to establish itself as a regional hub. It also provided a degree of energy security to Israel.

Chevron USA Inc, a subsidiary of Chevron Corp, has signed a SPA with South Korean oil refiner GS Caltex Corporation. The long-term agreement, which is for delivery of LNG to South Korea from Chevron’s global supply portfolio, will start in October of this year. Chevron has an existing LNG sales and purchase agreement with GS Caltex executed in 2009. This SPA involves LNG supplied from Chevron’s Gorgon project delivered to GS Caltex for up to 20 years.

US independent energy producer Anadarko has notched up another long-term commitment to buy LNG from its proposed Mozambique terminal, moving closer to approving the multi-bn dollar project. Anadarko and Exxon Mobil are expected to sanction two separate but neighbouring LNG projects in Mozambique this year after finding giant offshore gas deposits, turning the African nation into a major global gas exporter. The company said it had struck a sales and purchase agreement with India’s Bharat Petroleum Corp Ltd for 1 mtpa for 15 years.

The US is trying to get Hungary to diversify away from Russian energy by encouraging ExxonMobil to proceed with long-stalled plans to develop the Domino-1 gas field in the Black Sea. Production from Domino-1 which is controlled by Exxon and Romania’s Petrom, a subsidiary of Austrian firm OMV is likely to start. Discovered off Romania in 2012 with estimated gas reserves of 1.5-3 tcf, the companies have since sought greater clarity from Romanian authorities before developing the field. Hungary could import the gas via a pipeline Romania is building from the Black Sea through an interconnector between the two countries, which will be capable of handling reverse flows. Last year Hungary agreed to buy 4 bcm of natural gas from Russia in 2020.

The discovery of a major new natural gas field in Indonesia may push back the day the country’s gas consumption outpaces its production and reduce its reliance on imported LNG. A consortium led by Spain’s Repsol found new gas resources at the Sakakemang block in South Sumatra in Indonesia estimated to contain at least 2 tcf the company said. Repsol claims the find is among the 10 largest made in the world over the past year. If the new find at the group’s Kali Berau Dalam-2 well shows good results, Indonesia may be able to push back the current estimate for when it has a natural gas deficit, or when consumption is greater than domestic supply, from 2025. To protect against the looming deficit, Indonesia’s state-owned energy company Pertamina recently signed a long-term contract with Anadarko Petroleum Corp to buy 1 mt per year of LNG for 20 years from Mozambique. Anadarko is expected to make a final investment decision this year on the project, which is expected to be operational by 2024.

Indonesia plans to sell 10 cargoes of LNG to spot market in the first half of 2019. There will be 1 cargo in April and 2 cargoes in May from Bontang LNG plant, 4 cargoes in June from Tangguh LNG plant, and 3 cargoes in March, May, and June from Donggi Senoro LNG Plant. Indonesia has 40 excess cargoes of LNG until 2025.

Australia’s gas prices are so high they could force the imminent shutdown of some manufacturing on the east coast, the nation’s competition watchdog said, urging gas producers to step up output and offer reasonable prices. The warning comes three years after the Australian Competition and Consumer Commission first flagged prices were rising amid uncertainty over domestic gas supply, due to the start-up of LNG exports from the eastern state of Queensland, cuts in exploration spending and drilling bans. While gas price offers to manufacturers have dropped to around A$10 to A$12 a GJ from as much as A$22 per GJ in 2017, they are still two to three times higher than they were before LNG exports began pulling gas out of the domestic market. Businesses and manufacturers dependent on gas for their operations have told the watchdog they are increasingly likely to move from the east coast or shut operations, Australian Competition and Consumer Commission Chairman Rod Sims said. The Australian government succeeded two years ago in pressuring the three east coast LNG exporters – led by ConocoPhillips and Origin Energy, Royal Dutch Shell and Santos Ltd – to boost local gas supply. But Sims said producers now need to “provide immediate price relief to the manufacturing sector”. States also need to do more to encourage new gas development by lifting blanket drilling bans. The high gas prices and prospects of a supply shortage have attracted five proposals to import LNG into southeastern Australia, even as Australia is poised to become the world’s top LNG exporter.

A consortium led by Repsol has found new gas resources in Indonesia estimated at least 2 tcf the Spanish oil and gas firm said, equivalent to around two years’ worth of Spanish demand. The discovery at the Sakakemang block in South Sumatra is among the 10 largest finds worldwide in the last 12 months, and the biggest in Indonesia for 18 years, Repsol said. Following its strategy to maximize the use of gas as major economies phase out carbon, Repsol plans to drill another appraisal well in the area in the coming months, it said.

Ethiopia and Djibouti have signed a deal to build a pipeline to transport Ethiopian gas to an export terminal in the Red Sea state. Ethiopia found extensive gas deposits in its eastern Ogaden Basin in the 1970s. China’s POLY-GCL Petroleum Investments has been developing the Calub and Hilala fields there since signing a production sharing deal with Ethiopia in 2013. The agreement between Djibouti and Ethiopia comes more than a year after POLY-GCL signed a memorandum of understanding with Djibouti to invest $4 bn to build the natural gas pipeline, a liquefaction plant and an export terminal to be located in Damerjog, near the country’s border with Somalia. Africa’s eastern seaboard could soon become a major global producer of liquefied natural gas, with other planned projects based on big gas finds made in Tanzania and Mozambique.

Egypt’s gas output will get a boost this year as the country’s huge Zohr field nears peak production and with $1.8 bn in investment from BP, as Egypt returns to export markets and positions itself as a regional hub. Egypt hopes to leverage its strategic location and well-developed infrastructure to become a key international trading and distribution center for gas, a potentially remarkable turnaround for a country that spent about $3 bn on annual LNG imports as recently as 2016. Egypt is hoping to tap long underutilized liquefaction plants, where gas is turned into LNG, to export supplies across the Mediterranean along with that of its neighbors, like Israel, which said it would pipe gas to Egypt later this year. Egypt imported its final natural gas shipment last September, and said it will begin exporting to Jordan this year, though the exact level of shipments and timeline is still unclear. Its domestic production level stands at about 6.6 bcf per day. Total production at BP’s West Nile Development will soar to nearly 1.4 bcf per day after the project’s third field, Raven, comes online. About 700 mcf per day will come online by April from the first two, Giza and Fayoum. The country’s top gas asset, Zohr, discovered by Eni in 2015, will near peak production of about 3 bcf per day from 2.1 bn currently by the end of 2019. Results of two exploration tenders held last year for 27 blocks would be announced during the three-day forum, and that it had seen “high turnout” from international companies.

Chinese coal miner Huainan Mining Group has won provincial approval to build a terminal along the Yangtze river to receive LNG. The terminal, which the company claims is the first one to be built along the Yangtze, will have a handling capacity of 2 mtpa and will cost about $442.71 mn to build, according to the report. The terminal, to be located at the port of Sanshan in the inland city of Wuhu in Anhui province, is slated for completion in 2022. Huainan Mining is already partnering with China National Offshore Oil Corp for a planned LNG receiving terminal at the coastal port of Yancheng in Jiangsu province.

Britain’s government has no plans to review regulations for fracking gas in the country, it said, following calls from industry to revisit the rules. Chemical giant Ineos and fracking firm Cuadrilla said current restrictions around seismic events at fracking sites could force the industry to close. Cuadrilla said its test drilling in northwest England showed a rich reservoir of high quality and recoverable gas.

AG&P: Atlantic Gulf & Pacific Company of Manila Inc, LNG: liquefied natural gas, CNG: compressed natural gas, km: kilometre, GAs: geographical areas, IOC: Indian Oil Corp, PNGRB: Petroleum and Natural Gas Regulatory Board, HPCL: Hindustan Petroleum Corp Ltd, CGD: city gas distribution, OIL: Oil India Ltd, MW: megawatt, O&G : oil and gas, DGH: Directorate General of Hydrocarbons, CBM: coal-bed methane, ONGC: Oil and Natural Gas Corp, mmBtu: million metric British thermal units, RIL: Reliance Industries Ltd, PSUs: Public Sector Undertakings, mmscmd: million metric standard cubic meter per day, bcm: billion cubic meters, KG: Krishna-Godavari, US: United States, DDW: Deen Dayal West, GSPC: Gujarat State Petroleum Corp, FDP: field development plan, mtpa: million tonnes per annum, BPCL: Bharat Petroleum Corp Ltd, WoodMac: Wood Mackenzie, mt: million tonnes, EU: European Union, mn: million, bn: billion, QCLNG: Queensland Curtis LNG, mcm: million cubic meters, mcf: million cubic feet, bcf: billion cubic feet, tcf: trillion cubic feet, SPA: sale and purchase agreement, GJ: gigajoule

Courtesy: Energy News Monitor | Volume XV; Issue 40

Monthly Oil News Commentary: February 2019

India

India’s oil imports from Iran fell by 45 percent in January to 270,500 bpd oil, ship tracking data showed, below the estimated 300,000 bpd for the month as some cargoes were delayed. The US introduced sanctions aimed at crippling Iran’s oil revenue-dependent economy in November but gave a six-month waiver to eight nations, including India, which allowed them to import some Iranian oil. India is restricted to buying 1.25 mt per month some 300,000 bpd. January imports from Iran were 10.4 percent lower than December, the tanker arrival data showed. Iran was the seventh biggest oil supplier to India in January compared with sixth in December, and slipped from third position it held a year ago. In the first 10 months of this fiscal year that began in April, India’s oil imports from Iran rose by 14.5 percent to 507,000 bpd as refiners boosted purchases ahead of the US sanctions drawn by discounts offered by Tehran, the data showed. Iran was hoping to sell more than 500,000 bpd of oil to India in 2018/19 and had offered almost free shipping and an extended credit period to boost sales to the country. Indian refiners HPCL and BPCL, MRPL and IOC would lift same volume in March as they took in February. In February, IOC placed an order for 5 mn barrels, MRPL for 2 mn barrels and HPCL and BPCL for 1 mn barrels each. India’s oil imports from Iran in this fiscal year would be higher than the 452,000 bpd, or 22.6 mt it imported in the previous year, were correct. India’s total oil imports in January were about 4.6 million bpd, a decline of about 10.4 percent from a year earlier, the data showed.

India has asked one buyer of Venezuelan oil to consider paying the South American nation’s national oil company PDVSA in a way that avoids the US  financial system after Washington imposed fresh sanctions on Venezuela. The sanctions mean that if oil buyers pay PDVSA through the US banking system, the funds could be seized by US authorities. India, Venezuela’s second-biggest oil market after the US, has already restricted oil imports from Iran to win a waiver from US sanctions against Tehran over its nuclear and missiles programmes. RIL and Nayara Energy, part-owned by Russian oil major Rosneft and trader Trafigura, are the two Indian buyers of Venezuelan oil. Venezuela is open to barter payment arrangements with India as it seeks workarounds to US sanctions imposed in late January. Caracas, which buys medicines and other products from India, is looking for alternative payment methods to keep oil flowing to what is now its first destination for crude exports after its US customers froze purchases due to sanctions. India, bought more than 340,000 bpd from Venezuela last year. Venezuela wanted to expand trade in services and technology with New Delhi. Venezuela aimed to double oil supplies to India. Before sanctions, the US bought more than 500,000 bpd, making it Venezuela’s largest buyer. Last year, RIL and Nayara jointly imported 344,100 bpd of Venezuelan crude, down 13 percent from 2017, according to ship tracking data. But India last year remained Venezuela’s second largest destination for oil exports. Barter deals could help India balance its trade with Venezuela. In fiscal 2017/18, India’s imports from Venezuela were worth $5.87 bn while its exports were $79.3 mn, Indian trade ministry data showed.

Saudi Arabia is looking at making India a regional hub for supply of crude oil and will invest billions of dollars in the country to build storage facilities and strengthen refineries. Saudi Arabia, the world’s biggest oil exporter, will also invest in downstream assets in India besides helping the country boost its infrastructure in the petrochemical sector. Saudi Aramco, the world’s top oil exporter, will be part of a joint venture project to set up a refinery in Maharashtra at a cost of $44 bn. It will be the largest greenfield refinery in the world to be implemented in one phase. The country was committed to meeting India’s oil demand and ready to sell more crude oil to India. India is expected to increase import of oil from countries such as Saudi Arabia and the United Arab Emirates if the US does not extend the six-month-long waiver it granted to New Delhi and several other countries to buy oil from Iran. Saudi Arabia is also a key pillar of India’s energy security, being a source of 17 percent or more of crude oil and 32 percent of LPG requirements of India. The energy ties between the two countries are on an upswing in the last few year.

IOC has signed its first annual deal to buy US oil, paying about $1.5 bn for 60,000 barrels a day in the year to March 2020 to diversify its crude sources. IOC is the first Indian state refiner to buy US oil under an annual contract, in a deal that will also help boost trade between New Delhi and Washington. The company has previously purchased US oil from spot markets and signed a mini-term deal in August to buy 6 mn barrels of US oil between November and January. The annual contract will begin from April. IOC signed the deal with Norwegian oil company Equinor which will supply a variety of US crude grades. IOC buys about 75 percent of its oil needs through long-term deals, mostly with OPEC.

Two years after the government shifted to revenue sharing contracts for oil and gas block auctions, a high-level panel has suggested reverting back to older system of awarding areas in most basins based on exploration commitment. The six-member panel stated that “unexplored areas in Category II & III basins be bid out exclusively based on exploration work programme”. Two years back the government moved from production sharing contracts, where acreage for exploration of oil and gas was allocated to firms offering the largest work programmes (such as carrying out seismic survey and drilling of wells), to revenue sharing contracts, where the firm offering highest revenue to the government was given the blocks. The move to revenue sharing was contrary to most of the industry players being against the new regime. A high-level inter-ministerial committee made several specific recommendations, including transforming the system of bidding for exploration, changing from revenue sharing to exploration programme for Category II and III basins.

Under the new policy for oil exploration and production framework, bidders of oil and gas blocks will be encouraged to invest more on exploration and start sharing revenue with the government only at the production stage. Accordingly, auction of oil and gas blocks will give 70 percent weightage to the work programme proposed by prospective bidders and 30 percent weightage to proposed revenue share against the equal weightage given at present. The new scheme will be applied for auction of unallocated or unexplored areas of producing basins. For partially explored blocks and those where no exploration has been done, bidders will not be required to bid on the basis of revenue share or production share with the government but will be awarded blocks only on the basis of work programme or the level of investment and technology to be incorporated by them. The contractor will have full marketing and pricing freedom for crude oil and natural gas to be sold at arm’s length basis through a transparent bidding process.

The government has asked ONGC and Oil India Ltd to sell out 66 of their small oil and gas fields to private firms as it brought in a new policy to boost domestic production and cut imports. To quickly bring all sedimentary basins under oil and gas exploration, the government dumped a two-year-old model of bidding out acreage or blocks to firms offering highest share of revenue, and brought in a new system of bidding them out on the basis of work programme such as drilling of wells and shooting of seismic with the winner’s only liability being payment of statutory duties like royalty and cess. ONGC and Oil India Ltd, who are battling stagnation in output from largely ageing fields, have a total of 184 fields. The national oil companies have been asked to provide enhanced production profile for 66 of these fields, which contribute 95 percent of the 36 mt of annual oil production in the country, and given freedom to induct private and foreign partners or technology providers. They have been allowed to retain another 52 fields (49 by ONGC and 3 by OIL) where enhanced oil recovery or improved oil recovery programmes are already under implementation and they were put on production in the last four years. For the remaining 66 fields (64 belonging to ONGC and 2 to OIL), which currently contribute about 5 percent of total output, will be bid out or privatised with revenue share going to the two firms. The government has decided to award future exploration acreage based on exploration work commitment, which will replace a two-year-old method of awarding them to companies offering the highest revenue share to the government. The focus of the new policy is to raise output from the existing fields and bring newer areas under production quickly.

ONGC’s Vashishta and S1 development project has come up at Amalapuram in the Krishna-Godavari Offshore Basin. The cost of the project is about Rs57 bn. This project will contribute significantly in realising the vision of reducing oil imports by 10 percent by 2020. The project, coming up over 100 acres, will be built at an estimated cost Rs5.8 bn. The project will be commissioned by November 2020. Fully automated and state of the art, the Coastal Installation Project will ensure security of the petroleum products.

The 1.33 mt capacity Visakhapatnam Strategic Petroleum Reserve facility of the Indian Strategic Petroleum Reserve Ltd. The facility, developed at a cost of Rs11.25 bn, has the largest underground storage compartment in the country and is expected to give a boost to the nation’s energy security.

PNGRB has rejected HPCL’s objections to consultations it had initiated to break stranglehold of PSUs on lucrative pipeline supplying jet fuel or ATF to Mumbai airport, saying the refiner will get a formal opportunity to make its case against the move. In a 21 February order, the PNGRB said it had on 7 November 2016, received a request from RIL seeking declaration of two pipelines emanating from HPCL and BPCL’s refinery and terminating at Mumbai International Airport as a common carrier so that the same can be shared by any third-party on open access and non-discriminatory basis. PNGRB in its order said HPCL had given written objections in the consultation process. BPCL and HPCL built and operate two separate pipelines from their Mahul refineries in Mumbai to supply jet fuel to airlines at the Chhatrapati Shivaji International Airport at Santacruz in the city. ATF is a Rs100 bn fuel trade in Mumbai airport.  If implemented, it would allow an airline to import fuel and use the infrastructure at the refineries situated on the coast to transport it to the airport. ATF demand at Chhatrapati Shivaji International Airport is 1.4 mtpa and it is “absolutely essential” that access to the BPCL and HPCL ATF pipelines is available to other jet fuel marketing oil companies to service this demand.

The government’s push to provide clean cooking fuel to every household has turned India into the world’s second largest LPG consumer whose demand is projected to rise 34 percent by 2025. LPG consumers have grown at a compounded annual growth rate of 15 percent – from 148 mn in 2014-15 to 224 mn in 2017-18.  The petroleum ministry has provided 130 mn LPG connections in less than 5 years, which is equivalent to the number of connections in the first 60 years since Independence.  67.5 mn LPG connections have been given to poor households. The LPG plant of HPCL planned in Odhisa will be spread over 21 acres and will have the capacity of filling 4.2 mn cylinders per year. The plant is expected to be operational by September 2020. The LPG bottling plant will be the second plant of HPCL in the state and will be constructed with a capex of `910 mn. The plant in Rayagada will cater to the LPG markets in various districts in Odisha-Bolangir, Boudh, Gajapathi, Kalahandi, Kandhamal, Koraput, Malakangiri, Nabarangpur, Nuapada, Rayagada and Sonepur. Under the Pradhan Mantri Ujjwala Yojana, a total of 3,716,000 LPG connections have been given in Odisha by the oil marketing companies. Since 2014, LPG customers in the state have grown from 2,022,000 to 7,665,000 in 2019.

The government’s petroleum subsidy allocation for the next financial year must be between Rs370 bn and Rs500 bn taking into account expected levels of average crude oil prices and the exchange rate, experts said. The government had budgeted for an overall petroleum subsidy of Rs249.33 bn for financial year 2018-2019, a mere 1.93 percent increase over Revised Estimate of Rs244.60 bn allocated for 2017-2018. The oil ministry expects under-recoveries of oil firms for the current fiscal to reach Rs457.81 bn. A different estimate shows the petroleum subsidy for this fiscal may shoot up to Rs340 bn as global crude oil prices are easing in the second half of the year after the spike witnessed in the first half.  The government’s expenditure on petroleum subsidy in the first six months of the current financial year has already crossed 83 percent of the budgeted allocation of Rs249.33 bn.

Opposition from farmers has prompted India’s western state of Maharashtra to move the location for what would be the country’s biggest oil refinery. Stare-run oil companies and Saudi Aramco have teamed up to build the $44 bn refinery, which is aimed at giving India steady fuel supplies while meeting Saudi Arabia’s need to secure regular buyers for its oil. But thousands of farmers are refusing to surrender land, fearing it could damage a region famed for its Alphonso mangoes, vast cashew plantations and fishing hamlets that boast bountiful catches of seafood. After their protests, land acquisition has been stopped for the refinery at the proposed site at Nanar, a village in Ratnagiri district, some 400 kilometre south of Mumbai. The refinery will be built at a place where local population won’t oppose the project. The RRPCL, which is running the project, said the 1.2 mn bpd refinery, and an integrated petrochemical site with a capacity of 18 mtpa will help create direct and indirect employment for up to 150,000 people, with jobs that pay better than agriculture or fishing. RRPCL, a joint venture between IOC, HPCL and BPCL has said suggestions the refinery would damage the environment were baseless.

The Expert Appraisal Committee under the Environment Ministry has given “green signal” to IOC for setting up a grass root petroleum storage and distribution terminal in Telangana. The proposal involves setting up petroleum storage and distribution terminal comprising 28 tanks with combined capacity of nearly 165 mn litres with an investment outlay of Rs5.7 bn at Malkapur village, Yadadri district.

Rest of the World

US sanctions will sharply limit oil transactions between Venezuela and other countries and are similar to but slightly less extensive than those imposed on Iran last year, experts said after looking at details posted by the Treasury Department. Treasury’s notice makes more explicit that the sanctions restrict foreign entities from doing business with Venezuela using the US financial system or US brokers after April. With most oil transactions conducted in dollars, that is expected to sharply curtail off Venezuela’s efforts to seek buyers around the world. Venezuela sells oil to buyers around the world, including India and Europe, and the country has been seeking buyers elsewhere to replace the roughly 500,000 barrels a day it sells to the US. Few alternative buyers are available for the heavy Venezuelan crude oil that is currently shipped to the US, Ed Morse, global head of commodity research at Citi Group, said.

The global oil market will struggle this year to absorb fast-growing crude supply from outside OPEC even with the group’s production cuts and US sanctions on Venezuela and Iran, the IEA said in a report. The IEA left its demand growth forecast for 2019 unchanged from its last report in January at 1.4 mn bpd. The IEA raised its estimate of growth in crude supply from outside the OPEC to 1.8 mn bpd in 2019, from 1.6 mn bpd. The IEA also lowered its forecast for demand for OPEC crude, production of which the group has pledged to cut by 800,000 bpd this year as part of an agreement with Russia and other non-OPEC producers such as Oman and Kazakhstan.

Global commodities firm Trafigura has decided to stop trading oil with Venezuela due to US sanctions on the OPEC nation’s energy sector. The decision will come as a blow to Caracas as Swiss-based Trafigura has a long-standing arrangement with PDVSA to take Venezuelan crude and, in exchange, supply the Latin American country with refined products. Last year, trading company Trafigura directly took 34,000 bpd of Venezuelan crude and products, which were mostly resold to US and Chinese refineries, according to internal PDVSA trade documents. Trafigura will stop business with PDVSA after completing a small number of already-concluded trades. Due to the size of Venezuela’s oil-for-loan agreements with China and Russia and the weight of previous US sanctions, cash-strapped PDVSA has become increasingly reliant on intermediaries to export its crude and import refined products. Trafigura is due to load two cargoes of Venezuelan crude before the end of February.

Foreign partners of Venezuela’s PDVSA are facing pressure from the oil firm to publicly declare whether they will continue as minority stakeholders in Orinoco Belt projects following US sanctions. The sanctions on PDVSA, imposed in an attempt to dislodge Venezuelan President Nicolas Maduro, barred access to US financial networks and oil supplies for the PDVSA joint ventures, pressuring the nation’s already falling crude output and exports. PDVSA’s Orinoco Belt joint venture partners, mostly US or European companies, are facing difficulties getting cash-flow out of the country as a result of the sanctions, straining their ability to continue output and exports. France’s Total SA, Norway’s Equinor ASA, Russia’s Rosneft and US-based Chevron hold minority stakes in joint ventures with PDVSA that produce crude and operate oil upgraders capable of converting the country’s extra-heavy oil into exportable grades. The four crude upgraders are capable of converting up to 700,000 bpd. The oil is exported by the joint ventures and each partner receive its share of the exports.

Russian oil producer Rosneft said it saw different possible scenarios for the global oil output deal between OPEC and non-OPEC allies in the future and that it was unclear what chances the deal had of being extended. Rosneft will expect something in return from the Russian government if the company has to keep limiting output US oil prices inched up, buoyed by expectations of tightening global supply amid US sanctions on Venezuela and production cuts led by OPEC. Analysts said that US sanctions on Venezuela had focused market attention on tighter global supplies. The sanctions will sharply limit oil transactions between Venezuela and other countries and are similar to but slightly less extensive than those imposed on Iran last year, experts said. Oil supply from the OPEC fell in January by the largest amount in two years, a survey found, as Saudi Arabia and its Gulf allies over-delivered on the group’s supply-cutting pact while Iran, Libya and Venezuela registered involuntary declines. Russia has been in full compliance with its pledge to gradually cut its oil production.

Russia is complying fully with its pledge to cut oil production gradually. Russian oil production decreased by 47,000 bpd in January from October, the baseline for the global deal aimed at reducing oil supply. The pace of Russia’s output cuts has drawn criticism from Saudi Arabia, de facto leader of the OPEC. Russia cut its output in January by around 35,000 bpd from October to 11.38 mn bpd. The energy ministry has not revealed its calculations in barrels. Russian oil production reached 11.41 mn bpd in October 2018. OPEC and other global oil producers agreed in December to cut their combined output by 1.2 mn bpd in order to support oil prices and try to balance the market. Of that, Russia pledged to cut its production by around 230,000 bpd in the first quarter.

Saudi Arabia, the world’s top oil exporter, cut its crude output in January by about 400,000 bpd, OPEC said, as the kingdom follows through on its pledge to reduce production to prevent a supply glut. Riyadh told OPEC that the kingdom pumped 10.24 mn bpd in January, OPEC. That’s down from 10.643 mn bpd in December, representing a cut that was 70,000 bpd deeper than targeted under the OPEC-led pact to balance the market and support prices. The OPEC, Russia and other non-OPEC producers – an alliance known as OPEC+ – agreed in December to reduce supply by 1.2 mn bpd from 1 January. The agreement stipulated that Saudi Arabia should cut output to 10.311 mn bpd. Saudi Arabia will exceed the required reduction to demonstrate its commitment. Saudi Arabia would export 7.1 mn bpd in February, down from 7.2 mn bpd in January.

Saudi Arabia is set to boost crude exports to China in 2019 as demand there grows and after Saudi Aramco shifted strategy to boost its market share in the world’s second biggest oil consumer. Saudi crude exports to China are expected to rise to about 1.5 bpd in the first quarter, from about 1 mn bpd in 2018. Saudi Arabia, the world’s biggest oil exporter, has been surpassed by Russia in the past three years as the top crude supplier to China after a new pipeline boosted supplies and private refiners, known as “teapots”, sought more Russian oil. But Aramco has been adopting a more aggressive marketing strategy and has moved more swiftly to seal long-term supply deals in a bid to become China’s top supplier again, industry sources say. Saudi Arabia has said it plans to produce around 9.8 mn bpd of oil in March, more than 500,000 bpd below its pledged production level under the deal to cut supplies. US has warned OPEC not to tighten the oil market too much and risk another spike in prices that could harm the global economy . Top oil exporter Saudi Arabia would need oil priced at $80-$85 a barrel to balance its budget this year IMF said. Riyadh’s breakeven oil price depends on several factors, including the level of oil production, how much of Saudi oil revenues are transferred to the budget, and how non-oil revenues perform this year.

Mexico’s Pemex produced 1.62 mn barrels of crude per day in January, less than any month in almost three decades, underscoring the challenges facing a government that vows to pump far more in a few years. The company’s crude output for the month was the lowest since at least 1990, when Pemex’s publicly available records begin. The firm’s crude oil output has declined for 14 consecutive years since hitting a peak of 3.4 mn bpd in 2004, as Mexico’s most prolific fields have dried up and new ones to replace them have not been discovered. Pemex’s crude production averaged 1.81 mn bpd in 2018. The company’s crude oil exports also fell in January to total 1.07 mn bpd, down nearly 10 percent from 2018 average shipments of 1.18 mn bpd.

Oil and gas companies working in Norway have lowered their investment forecasts for 2019 to 172.7 bn crowns ($20.1 bn) from 175.3 bn crowns seen in November, a survey by the country’s statistics agency (SSB) showed. In 2020 investments are expected to fall to 158.5 bn crowns, according to initial forecasts, though the forecasts could be revised upwards in the months to come, it said. Equinor is Norway’s largest oil company, competing with the likes of Aker BP, Lundin Petroleum, Total or Shell. The Norwegian central bank expects investment in the oil sector, the Nordic country’s most important industry, to grow by 3 percent in 2020. Norway’s oil and gas investments have rebounded from a sharp fall as rising crude prices lift industry activity. Norway’s Equinor SA said it plans to explore for oil in deep waters off the coast of South Australia in late 2020 and released a draft environmental assessment for the project to head off community protests. Equinor, formerly known as Statoil, took full control of two permits in the Great Australian Bight, a body of water off the southern Australian coast, in 2017, where BP had scrapped plans to explore for oil.

Saudi Arabia is expected to reach an agreement this year to resume oil output from the Neutral Zone it shares with Kuwait. Resuming production from the Neutral Zone’s oilfields could add up to 500,000 bpd each to the oil output of Saudi Arabia and Kuwait.

TransCanada Corp restarted a section of the Keystone oil pipeline, following a leak in Missouri. TransCanada had shut an arm of Keystone from Steele City, Nebraska to Patoka, Illinois on 6 February after leaking 43 barrels of crude oil. The shutdown restricted the flow on the 590,000 bpd Keystone pipeline system, a critical artery taking Canadian crude from northern Alberta to refineries in the US Midwest.

Uganda expects to begin producing oil in 2022 indicating a slight delay from the east African country’s revised target of 2021. Uganda discovered crude reserves more than 10 years ago but production has been repeatedly delayed by disagreements with field operators over taxes and development strategy. In April last year Uganda signed a deal with a consortium, including a subsidiary of General Electric, to build and operate a 60,000 bpd refinery that will cost between $3 bn and $4 bn. The refinery is expected to be operational by 2023. Uganda, which imports refined fuel, would announce its next exploration licensing round in May. A crude export pipeline, which passes through Uganda’s neighbour Tanzania, with a capacity to transport 260,000 bpd oil will be built by 2022.

Vitol, the world’s top oil trader, plans to access LPG from the giant Kashagan field in Kazakhstan and may finance the construction of a processing and export facility. LPG is mainly a by-product of oil development at the field and at the moment there is no infrastructure for refining, storage and transportation of LPG from Kashagan. The trader has approached North Caspian Operating Company, the field operator, and Kashagan’s shareholders with a proposal to build the LPG processing and export facility near Karabatan railway station in the Atyraus region, but no immediate reaction followed. The plant is set to be commissioned in 2021, according to the Kazakh government’s schedule. The new facility may help Vitol boost its presence in the Kazakh LPG export sector. Vitol plans to deliver propane and butane to the global market via Russia’s Black Sea terminal in Taman, where Vitol has a transhipment contract. Kashagan, one of the biggest oil discoveries in recent history, started commercial output in late 2016 after years of delays and currently produces about 350,000 barrels of crude per day.

Yemen hopes to scale up its oil production to 110,000 bpd in 2019, with exports touching about 75,000 bpd. The war-torn Arabian Peninsula country produced an average 50,000 bpd oil in 2018 compared with an average of around 127,000 bpd in 2014.

South Sudan will return to producing more than 350,000 bpd by the middle of 2020, up from current levels of just over 140,000 bpd currently. Production is expected to rise to 270,000 bpd by the end of 2019. The country lost many of its oilfields to a civil war that broke out two years after its independence. South Sudan has signed a preliminary agreement with Russia’s Zarubezhneft for exploring some of the blocks.

Brazil’s oil regulator said that is has started an investigation into an oil spill at an offshore platform owned by Petroleo Brasileiro SA (Petrobras). About 188 cubic meters of oil leaked from the offshore P-58 platform, which is located in the Campos basin, some 80 kilometres of the coast of Espírito Santo state.

bpd: barrels per day, US: United States, mn: million, bn: billion, mt: million tonnes, HPCL: Hindustan Petroleum Corp Ltd, BPCL: Bharat Petroleum Corp Ltd, MRPL: Mangalore Refinery and Petrochemicals Ltd, IOC: Indian Oil Corp, RIL: Reliance Industries Ltd, LPG: liquefied petroleum gas, OPEC: Organization of the Petroleum Exporting Countries, PNGRB: Petroleum and Natural Gas Regulatory Board, PSUs: Public Sector Undertakings, ATF: aviation turbine fuel, mtpa: million tonnes per annum, RRPCL: Ratnagiri Refinery & Petrochemicals Ltd, IEA: International Energy Agency

Courtesy: Energy News Monitor | Volume XV; Issue 39

Ashish Gupta, Observer Research Foundation

On 23^rd September, 2014 there was coal summit in the capital where the chairperson expressed concern over the judgement on coal blocks allocation. The chairperson is likely to be really worried now. The Supreme Court at a single stroke cancelled all the licences of the allottees leaving only four blocks intact. There is joy for one private company whose stock prices are soaring but sorrow for others. Some banks such as Andhra bank, Allahabad Bank and UCO bank which lent money to these companies are also worried. Whatever course of action is adopted by the new government, the coal conundrum will continue to churn.

The new government has made it clear that they will not be opening the coal sector. Therefore the analysts who are pushing for privatisation must adopt a pragmatic approach. But the private sector could continue to play an important role in the coal sector though in limited capacity.

Auction is a process that the government is looking at with revenue sharing model for captive blocks allottees. In this model, there will be no upfront payment but the amount will be paid in due course without hampering the financial viability of the allottees. This approach is good for captive blocks that were in operation or on the verge of completion. These allottees have suffered huge financial damage and such a mechanism would also act as a cushion for financial institutions. These companies must also be asked to pay a penalty. For other captive blocks, the government must resort to auction mechanism.

In the past, there have been voices against auctioning on the premise that revenue maximisation is not the only goal of the government. Auction is not seen as preferable for the small and medium sized companies.  But auction may become a reality and all have to accept it. The coal sector is not meant for small and medium sized companies given the expertise and huge investment required for coal mining. They do not have such capability and therefore they could be excluded from participation. However they could be invited for small captive blocks.

With regard to private participation in the coal sector, various models have been propagated in many reports such Joint venture with Coal India, Mine Developer and Operator etc. These models are already in place but the important question is whether it has served any purpose. Such arrangements are good companies who would like to be seen as contractors. But for big companies it makes no sense as they want to be seen as commercial miner not as contractor of Coal India. The case of Thiess and Leighton, Australia and ESPA, Spain is a reflection of failure for such models. Also companies like Rio Tinto are not going to invest in the coal sector because of social and political uncertainties. Giving complete freedom to these companies by extending commercial miner status would be wise. Participation of such commercial coal companies is necessary for reform. Lastly, given the changing dynamics, outdated laws covering the coal sector need to be amended so that there will be a level playing field for all the stakeholders!

Views are those of the author                    

Author can be contacted at ashishgupta@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 15

Monthly Non-Fossil Fuels News Commentary: January – February 2019

India

The Union petroleum ministry has decided to encourage conversion of Used Cooking Oil to biodiesel and tied up with a private firm, Muenzer Bharat. A pilot plant for the conversion has been set up in Nerul MIDC. The firm will target restaurants, starred hotels and bulk sellers of vadapav and chips in Mumbai, Navi Mumbai and Thane in the first phase and provide drums to collect the used oil waste daily. It will prevent the re-entry of used oil in the food chain and also stop its dumping in rivers and sewers. The biodiesel manufacturing facility has been set up under the ‘National Used Cooking Oil Collection Mission for India’. It will convert the used oil into 100 percent water-based biodiesel-which can be used for gensets or blended with diesel to make it environment-friendly. Bad quality cooking oil is one of the main causes for cardiac infarction-a leading cause of deaths in India. Biodiesel can be blended with diesel, to be used in diesel cars, trucks, buses, off-road equipment, and oil furnaces across the country.

The ‘energy from waste’ biodiesel plant in Navi Mumbai will convert used cooking oil into biodiesel, an innovative model of converting #Waste2Wealth and is further expected to add to India’s energy security and help create alternate sources of energy. The Muenzer plant apart from meeting requirements of Bio-diesel will also be a big step in creating awareness, supply chain infrastructure and setting an example for other potential players.

The Punjab government signed an MoU with a Delhi-based company for a ₹ 6.3 bn project which will produce biofuel from rice husk. The technology for the project will be provided by the US giant Honeywell. The company, Virgo Corp, will use the technology to produce biofuel from rice husk to set up a rapid thermal processing plant, which will provide over 150 direct and 500 indirect jobs. The project would pave way for potential future collaborations in terms of investments, technology transfer between Punjab and the US. The project would go a long way in containing environmental pollution due to stubble burning, besides supplementing the income of farmers by helping turn the unmanageable agro-waste into raw material for producing biofuel.

In the late 2000s, hydroelectric power was billed as a sustainable, renewable alternative to coal and gas based electricity for India. The government drew up ambitious plans for setting up hydel plants and the private sector was keen to get in on the action. In 2008, growth in India’s installed hydel capacity outpaced the rise in India’s total power capacity. But it has been a different story since. Hydropower has slowly faded from the discourse on the future of India’s energy security, as solar and wind projects garner much of the attention. India’s installed hydro capacity at the end of 2018 was around 45,400 MW, an annual growth of just 1 percent, the lowest since 2009. What’s more, between 2008 and 2018, hydel power’s share of India’s total installed electricity capacity has halved from 25 percent to 13 percent. Beset by land acquisition troubles, uncertainty over final costs as well as estimated time for completion, and low tariffs, the hydel sector is unlikely to have a turnaround in the near future. While hydropower is renewable, its social and environmental impact — from displacement of thousands of people and adverse effects on biodiversity as a result of dams, to methane emissions from the rotting vegetation in their reservoirs — means that big hydel projects are no longer hyphenated with solar, wind and biomass energy. In 2015, the Indian government stopped categorising hydel projects larger than 25 MW as renewable. India has 4,500 MW of hydel projects with a capacity of less than 25 MW each. The government has estimated the country’s hydropower potential (more than 25 MW) at over 1,45,000 MW.

The Indian government has proposed the construction of Lower Arun Hydropower Project in Nepal with a capacity of 400 MW. The Nepal government would make a proper decision whether or not to award the construction of Lower Arun to India after seeing the progress in Arun III hydro project. The project investment is estimated to be over ₹ 100 bn. Nepal Energy Ministry has estimated that the project would be of around 1000 MW capacity if it is designed in a way to export power to India. India has put forth the proposal to build the Lower Arun project by keeping all conditions stipulated in Arun III.

BHEL said it has bagged two orders worth ₹ 970 mn from NPCIL to manufacture and supply primary side heat exchangers. The heat exchangers will be manufactured at BHEL’s Bhopal plant, BHEL said. The company has been a pioneer in the design and development of primary side products such as nuclear steam generators for NPCIL, and has, so far, supplied 40 steam generators for various nuclear power installations in the country.

The government has released ₹ 35.84 bn as CFA for implementing renewable energy schemes by the MNRE in financial year 2018-19 so far. A total of 74.79 GW of renewable energy capacity had been installed in the country at the end of December 2018 including 25.21 GW from solar, 35.14 GW from wind, 9.92 GW from biomass, and 4.52 GW from small hydro power. Installed capacity of solar rooftop systems stands at 1,279 MW in the country. The current rooftop solar programme, approved by the government in December 2015, aims at setting up 2,100 MW capacity in residential, institutional, social, and the government sectors through CFA by end of 2019-20. The government has set a target to install 40,000 MW of rooftop solar power capacity by 2022.

Based on implemented policies, India’s greenhouse gas emissions were expected to increase to a level of 4,469 to 4,570 MtCO2e by 2030, excluding forestry. This emission pathway was not compatible with a 2 degrees Celsius scenario. According to the India Cooling Action Plan draft, there is a plan to cut cooling demand by 20 to 25 percent by 2037, thus curbing a source of huge growth in electricity demand. The total renewable energy installations in India reached 75 GW by September 2018, representing 21 percent of total installed capacity and generating a record high of 11.9 percent of all electricity in the September 2018 quarter.

The interim budget has allocated ₹ 30 bn for development of solar power projects next financial year (2019-20) including both grid-interactive and off-grid and decentralized categories. This is a mere 1 percent increase over the likely expenditure of ₹ 29.69 bn for solar projects this fiscal. Under grid-interactive schemes, the budgeted allocation for solar is seen rising 15 percent to ₹ 24.79 bn in 2019-20 as compared to the current fiscal’s Revised Estimate of ₹ 21.57 bn, a review of budget documents tabled in Parliament show. The allocation for solar projects under off-grid and decentralized renewable power is seen declining 35 percent to ₹ 5.25 bn for the next financial year from ₹ 8.12 bn based on the revised estimate for 2018-19. Overall, the budget has allocated ₹ 49.60 bn for both grid-interactive and off-grid or decentralized renewable power for 2019-20. This is a marginal 1 percent increase over the allocation of ₹ 49 bn based on the Revised Estimate for current fiscal. Apart from solar, the budget has allocated a bulk of the funds under two other heads — wind power and green energy corridors. Both of them fall in the grid-interactive category.

India will add 11.4 GW of solar capacity annually for the next few years on the back of strong government push to achieve its targets, S&P Global Platts Analytics said in a report. According to the report, the upcoming 2019 general elections would be an important event for the sector, and as a result, little progress on the policy front was expected in the near term. Under the Jawaharlal Nehru National Solar Mission, launched as part of India’s National Action Plan on Climate Change in 2010, a target of 20 GW capacity by 2022 was set up, but was subsequently increased to 100 GW, of which 60 GW was of utility-scale. Highlighting the Central Electricity Authority of India’s data, the report said that India’s solar capacity reached 25.8 GW at the end of 2018 — with at least 13.8 GW under construction currently and 22.8 GW tendered under various schemes and state-level allocations.

The government is planning to re-launch 5 GW of manufacturing-linked solar tender out of the initial 10 GW that had received a single bid. With this, the earlier sole bid received from Azure Power will be cancelled and fresh bidding will start. With an aim to boost local manufacturing of solar equipment, the manufacturing-linked tender was first floated by SECI in May last year. However, due to low interest from the industry the bid submission was postponed six times. Azure Power has bid for 2,000 MW power capacity linked with 600 MW solar equipment manufacturing capacity while most of the other large industry players stayed away from the tender.

The government’s ambitious plan to set up a 7,500 MW solar power project at an estimated investment of ₹ 450 bn in Jammu & Kashmir’s Ladakh region has whetted the appetite of some 50 topline companies, even as tariff emerged as the key concern. Prospective investors, including major manufacturers, raised a host of issues with the top brass of SECI, the implementing agency under the renewable energy ministry, at a pre-bid meeting. These ranged from the natural challenges to the bid structure. The project is proposed to be set up at two locations. Hanle-Khaldo area in Nyoma block of Leh district will house a 5,000 MW unit, while Kargil district will get a 2,500 MW unit at Suru in Zanskar.

Tariffs in Maharashtra’s latest solar auction for 1,000 MW, held, remained almost unchanged from the last one conducted eight months ago, with mostly domestic developers participating. Shiv Solar and Acme Solar won 50 MW and 300 MW respectively at the lowest winning tariff of ₹ 2.74/kWh, while ReNew Power and Avaada Energy won 300 MW and 350 MW at ₹ 2.75/kWh. The tariff is distinctly lower than that at the last solar auction held in the country, by Gujarat in December, at which the winning price was ₹ 2.84/kWh. Unhappy with the tariff, which was higher than Gujarat Urja Vikas Nigam Ltd officials expected, they promptly cancelled the auction. A unique feature of the latest Maharashtra solar auction is that projects can be set up anywhere in the country, not necessarily in the state itself, and the power transmitted to Maharashtra.

The Andhra Pradesh government has set a target of generating 5,000 MW of solar power by 2023, and has offered several incentives to the private sector to meet this target. The new solar power policy said the power distribution companies in the state would be procuring 2000 MW of solar power in the next five years. The policy announced by the Andhra Pradesh government is among the most investment-friendly of such policies by other state governments. Among the other highlights of the policy, companies investing in solar power projects in the state would be entitled to state government incentives for 10 years. The government has also committed itself to obtaining revenue land for the solar power projects. For solar parks, land lease will be prioritised by the government and will be exempted from administrative approval charges. The new policy does not clearly spell out liability charges, project completion timeline, performance obligation, security deposit, completion time lines, renewable purchase obligations for ground mounted projects towards obligated entities.

The Goa government has notified the Solar Energy Policy to promote unconventional electricity generation in the coastal state. The policy, which was notified, came into force with immediate effect. As per the policy, the consumer and the producer of solar power will be entitled to avail benefit in the form of 50 percent subsidy from the state government. The policy also provides for penalty equal to five percent of the value of energy committed every day, if power producer fails to complete and commission the project within the given deadline. Under the policy, the government will provide 50 percent subsidy, including 30 percent share from the Centre, for the capital cost or the benchmark cost provided by the MNRE or cost arrived through tendering process by the GEDA.

The Tamil Nadu government has announced its Solar Energy Policy 2019 with the objective of achieving an installed capacity of 9,000 MW by 2023. Its earlier policy, which was unveiled in 2012, had set a target of 3,000 MW of installed capacity by 2015. But the State managed to achieve a little over 2,000 MW as of March 31, 2018. This capacity was about 10 percent of the country’s installed capacity in the solar sector. The new policy comes at a time when Tamil Nadu has lost its leadership position in rooftop solar capacity. With an installed capacity of 473 MW (as on 30 September 2018) in rooftop solar segment, Maharashtra has emerged the leader in this segment, pushing Tamil Nadu to the second position with an installed capacity of 312 MW, according to Bridge to India, a solar energy consulting firm. The policy hopes to create a framework that will help accelerate development of solar installations in the State, promoting both utility category and consumer category solar energy generation through various enabling mechanisms. About 40 percent of the target (9,000 MW) will be earmarked for consumer category solar energy systems, the policy document said. Tamil Nadu has been a pioneer in harnessing energy from renewable energy sources and it has highest installed capacity of more than 11,000 MW in the renewable energy sector with wind energy, where it leads the country, accounting for more than 8,200 MW. The State has huge potential for solar energy with around 300 clear sunny days in a year.

The UT administration has sought status report on the solar city project from the CREST, the nodal agency for installation of solar plants in Chandigarh. CREST is making efforts to achieve the target of 69 MW set by the ministry of new and renewable energy, which is to be achieved by 2022. UT administration had already approved the detailed project report of installation of 800 kW solar power plants worth ₹ 45 mn at the parking area of the new lake at Sector 42. Out of 800 kW, 90 kW solar energy would be reserved for charging e-vehicles. CREST also planned to install a 3 MW solar plant on the N-choe, a seasonal rivulet that passes through Garden of Springs, Sector 53, at the southern end of Chandigarh. It would be first of its kind solar plant on the N-choe. To encourage residents for installation of solar plants, the Chandigarh administration has already started transferring subsidy for installing solar plants on their rooftops, to residents, online. Earlier, the administration used to give cheques to residents. CREST provides 30 percent subsidy to residents for installing solar panels.

GERC has permitted GUVNL to procure 2.7 MW solar power generated by salt pan workers of SEWA during off-season period in salt pan work. As many as 3,000 salt pan workers in the Kutch desert use solar-powered pumps to draw saline water for salt production. These salt pan workers use solar panels- with an aggregate capacity to produce 2.7 MW power- for six months (October to April) for salt production at a remote location. The panels remain idle in warehouses during the remaining off-season period of six months. SEWA had requested Gujarat government to devise a suitable mechanism for purchase of power generated from these solar panels during the off-season period to optimally utilise the panels for socio-economic upliftment of salt pan workers. Subsequently, Grassroot Trading Network for Women, a SEWA entity, also received a go-ahead from the government to set up a solar power project of the same capacity. GUVNL approached GERC for the latter’s approval to procure solar power from salt pan workers during off-season period. The state regulator recently approved GUVNL’s petition as a special case considering the socio-economic upliftment of salt pan workers.

The Gujarat government has cancelled the solar auction for 700 MW it held in December on the grounds that the winning tariffs reached were too high. The decision was conveyed to the winning developers at a meeting. Foreign players had won the entire 700 MW, with Softbank-backed SB Energy getting 250 MW at ₹ 2.84/kWh, and Finland’s Fortum as well as France’s Engie getting 250 MW and 200 MW respectively at the same price of ₹ 2.89 /kWh. The previous auction for 500 MW held by GUVNL in September 2018 had seen the lowest tariff at ₹ 2.44/kWh, and officials were unhappy over the sharp rise in just three months. Developers attributed the rise mainly to the high charges levied at the Raghanesda Solar Park in the state, where the projects have to be located, unlike the ones won in September, which could be put up anywhere in the state. They had welcomed the rise in tariff, claiming tariffs were finally becoming realistic after their sharp fall in the past three years. The Gujarat government was likely to reduce the charges at the solar park, after which GUVNL would hold a fresh auction. It has already announced another auction for 500 MW to be held in end-January. This is the second auction GUVNL has cancelled due to perceived high tariffs. Earlier, it also cancelled a 500 MW auction held in March last year, at which the lowest price reached was ₹ 2.98/kWh.

Kerala will provide around 1.3-1.5 bn units of electricity to the consumers from 500 MW rooftop solar PV projects and 500 MW from floating and terrestrial solar PV projects. Kerala households have already registered for 200 MW of rooftop solar PV capacity. Agency for Non-Conventional Energy and Rural Technology, Kerala, explains that the Urja Kerala Mission by the State government is in the process of generating 1000 MW, of which 500 MW will be from solar panels installed on roof tops of houses.

Around 3,150 residents of Sushant Lok 2 Extension and Sushant Lok 3 can’t avail the grid-connected solar rooftop scheme because they are not direct DHBVN consumers. Launched in 2014, the scheme makes it mandatory for residents living in an area of up to 500 square yards or more to install solar power plant on their rooftop. Residents can use the power generated while exporting the surplus units to the discom, which in return will provide a rebate to them. The solar panels, when purchased from empanelled vendors of Haryana Renewable Energy Department, come with generous subsidies. But according to Haryana Electricity Regulatory Commission guidelines, only direct consumers of DHBVN can avail it. Sushant Lok 2 Extension and Sushant Lok 3 get power from a single point connection which the discom extends to the developer who then divides it into as many connections as number of consumers in the township. The scheme was supposed to encourage consumers to opt for alternative power sources. Gurugram has potential for generating solar power of 200 MW but only 27 MW is currently being generated.

Surat has become the first city in the country where water supply management by Surat Municipal Corp is being carried out using solar energy. Out of the total 6 MW of solar power plants, 4 MW is dedicated for water supply management. 5 MW of solar power plants are already installed and a 1 MW solar power plant will be commissioned on 30 January. Out of the 6 MW solar power plants, 4 MW is dedicated for Sarthana waterworks, Katargam waterworks, Rander waterworks, Varachha waterworks, Udhana water distribution station, Magob water distribution station and Simada water distribution station. The total solar energy generation out of 4 MW solar power plants meant for water supply is about 5.3 million units per annum.

To incentivise production of solar power the cabinet has approved amendments to the Goa State Solar Policy 2017 where small and large prosumers (consumers and producers of solar power) will receive 50 percent subsidy instead of the earlier proposed interest-free loan that was be recovered in instalments. The subsidy will be of two parts — a 30 percent central share and 20 percent state share. The central share will be credited to the prosumer as per the guidelines of the MNRE while the state subsidy will be released upon completing of six months of the solar power being injected into the grid. The subsidy will be 50 percent of the capital cost or the benchmark cost provided by MNRE or cost arrived at through tendering process by the GEDA, whichever is lower. As per the Solar Policy 2017, prosumers were to be provided grant of 50 percent of the capital cost as an interest-free loan, which was to be recovered by way of instalments after six months from the time the power flows into the grid. The state government through the electricity department has entered into agreement with the SECI for 25 years to purchase 25 MW solar power and with the NTPC Vidyut Vyapar Nigam Ltd for purchase of 6 MW solar power to meet the partial Solar Renewable Purchase Obligation.

India’s wind energy sector is likely to benefit in the form of fresh investments as the trade tariff tussle between the US and China intensifies, according to a research report by global research and consultancy firm Wood Mackenzie. The research highlights the logistics challenges on the horizon for blades and towers as component sizes become longer and taller, respectively. Wood Mackenzie Power & Renewables expects the industry to circumvent these obstacles with new transportation methods and on-site/closer-to-site manufacturing. As such, the increase in project average megawatt size across global markets will favour this trend due to economies of scale, it said.

North America headquartered EDF Renewables announced its Indian arm has signed a long-term agreement to develop 300 MW of wind project in partnership with the UK-based SITAC Group. This agreement was the outcome of a competitive tender process launched by the Indian government under the fifth tender process of SECI. The award was granted in September 2018. EDF Renewables has a gross installed renewable energy capacity of 12.7 GW globally. Its development is mainly focused on wind and solar photovoltaic power and the company operates mainly in Europe and North America but is currently moving into emerging markets like Brazil, China, India, South Africa and the Middle East.

Hindustan Aeronautics Ltd said it has opened a wind energy plant in Karnataka’s northwestern Bagalkot district to power its facilities in Bengaluru. The 8.4 MW wind energy power plant is near Ilkal town in Bagalkot district, about 480 km northwest of Bengaluru. The ₹ 590 mn plant comprises four wind turbines, set up along with Pune-based wind turbine supplier Suzlon Energy Ltd. The plant has the potential to generate about 26 mn units of energy per annum with an estimated annual savings of ₹ 180 mn to the company in its power consumption.

Three technology mission centres at IIT Madras will be launched to address various issues around solar energy and water treatment. The first is the DST-IIT Madras Solar Energy Harnessing Centre. Scientists from IIT Madras, IIT Guwahati, Anna University, ICT-Mumbai, BHEL and KGDS Renewable Energy Private Ltd will be engaged in the activities of the centre. Second in line is the DST-IIT Madras Water Innovation Centre for sustainable treatment, reuse and management which has been established with the aim to undertake synchronized research and training programmes on various issues related to wastewater management, water treatment, sensor development, stormwater management and distribution and collection systems. The third one would be the test bed on solar thermal desalination solutions which are being established by IIT Madras and KGDS as solution providers in Naripaaiyur, Ramanathapuram district, Tamil Nadu with the aim to deliver customized technological solutions to address prevalent water challenges in the arid coastal villages located on the shores of the Bay of Bengal.

Samsung’s R&D centre in Bengaluru has switched to solar power for its campus which houses over 3000 R&D employees, the company said. The campus will draw 88 percent of its power requirement from a solar farm in Kalburgi district in Karnataka, around 500 km away from Bengaluru. In December 2018, Samsung’s Bengaluru R&D Institute, which is the company’s largest R&D centre outside Korea, adopted the green energy solution through a method called ‘energy wheeling’. The solar farm by Bagmane Green Power LLP based in Kalburgi would power the R&D centre through energy wheeling. The farm adds the required power to the state electricity grid and the centre in turn, receives an equal amount of power from the local electricity grid. This method makes it more energy efficient.

Rest of the World

China’s renewable power capacity rose 12 percent in 2018 compared to a year earlier, with the country still rolling out new projects despite transmission capacity concerns and a growing subsidy payment backlog. China has been aggressively promoting renewable power as part of an “energy revolution” aimed at easing its dependence on coal, a major source of pollution and climate-warming greenhouse gas emissions. Total capacity – including hydro and biomass as well as solar and wind – rose to 728 GW by end-2018, the NEA said. China hooked up another 20.59 GW of new wind power capacity to its grid in 2018, the NEA said. New solar capacity reached 44.3 GW, slightly higher than a figure given by an industry association earlier this month, but still down compared to 2017 following a decision to slash subsidies. China also completed another 8.54 GW of hydropower capacity, mostly in the nation’s southwest, bringing total hydropower to 352 GW by the year’s end. China has tried to change the “rhythm” of renewable power construction to give grid operators time to raise transmission capacity and ensure clean electricity generation is not wasted. China’s “energy revolution” has also involved the installation of new emissions control technology at its coal-fired power plants, still the dominant form of energy in China.

China plans to take renewable energy and solar power to a whole new level by planning to build the first ever solar power station up in space. China’s Academy of Space Technology has revealed plans to build a solar power plant in space that would orbit the Earth at 36,000km and capture solar energy and beam it back to Earth. Since its photovoltaic array would be floating high above any terrestrial weather, the plant would be able to harness solar power even when it is cloudy on Earth. A space solar power station held the promise of providing ‘an inexhaustible source of clean energy for humans’. The construction of an early experimental space solar power plant has already begun with plans to launch a test facility before 2025, and if the launch and the energy-transmitting beam work as planned, the Chinese scientists have plans to test and launch even bigger and more powerful facilities through 2050.

Global demand for renewable power will soar at an unprecedented pace over the coming decades, BP said in a benchmark report, while China’s energy growth is seen sharply decelerating as its economic expansion slows. China’s energy demand rose by 5.9 percent over the past 20 years, but is set to grow by only 1 percent by 2040 as its economy shifts from energy-intensive industries to services and as Beijing introduces stricter rules on air pollution. Renewables are expected to be the fastest-growing energy source with an annual gain of 7.1 percent, accounting for half the growth in global energy. Compared with the level in last year’s report, BP raised by 9 percent its 2040 forecast of demand for renewable power such as solar and wind. Renewables and natural gas, the least-polluting fossil fuel, will account for 85 percent of the growth in energy demand. Solar power will increase by a factor of 10 by 2040 and wind by a factor of five under BP’s basic scenario. While the share of oil in world energy demand rose from 1 percent to 10 over 45 years in the early 20th century, renewables are set to reach the same share over 25 years.

Brazil aims to complete its third nuclear plant by 2026 with the help of private investment, Mines and Energy Minister Bento Albuquerque said, in a bid to jump-start the decades-old, corruption-tainted project. He was in favor of resuming construction of the Angra 3 nuclear plant, which has been halted since 2015, and that the estimated 15 bn reais ($3.95 bn) cost of completing the project would be money well spent. While nuclear technology should remain in the hands of the government, Albuquerque told reporters, the ministry is working with the government’s public-private infrastructure partnerships secretariat to come up with a model for allowing private enterprises to participate in the construction.

Spain aims to close all seven of its nuclear plants between 2025 and 2035 as part of plans to generate all the country’s electricity from renewable sources by 2050. Energy Minister Teresa Ribera announced the move, just as the Socialist government gears up to call an early national election in anticipation of losing a budget vote. Overhauling Spain’s energy system, which generated 40 percent of its mainland electricity from renewable sources in 2018, will require investment of €235 bn ($266 bn) between 2021 and 2030, Prime Minister Pedro Sanchez said. Ribera said the government would present a draft plan to combat climate change, which had been due to be sent to the EU for approval by the end of last year, to parliament on 22 February. Under a draft bill prepared last year, the government aims to ban sales of petrol, diesel and hybrid cars from 2040 and encourage the installation of at least 3,000 MW a year of renewable capacity such as wind farms and solar plants. Spain’s nuclear plants, which started operating between 1983 and 1988, are owned by Iberdrola, Italian-owned Endesa, Naturgy and Portugal’s EDP.

Britain’s Drax has started capturing carbon dioxide at its wood-burning power plant in North Yorkshire, a world first in technology it hopes could lead to carbon negative power plants in the future. Energy companies are seeking ways to reduce CO₂ emissions while also providing constant supplies of electricity when renewable power sources, such as wind and solar are limited by the weather. The pilot bioenergy carbon capture and storage project is expected to capture a ton of carbon dioxide a day and Drax will seek to find ways to store and use the CO₂ captured. Drax said the project was the first in the world to capture carbon emissions from a biomass plant. Climate scientists said the technology is likely to be needed to help meet the international Paris climate agreement to try to limit a rise in global temperatures to 1.5 degrees Celsius.

The European Commission said it had concluded that US soybeans can be used in biofuels in the EU, part of the bloc’s push to improve strained trade relations with the US. The Commission said the recognition of US soybeans for use in biofuels was valid until 1 July 2021, but could extend beyond that date as long as they met sustainability criteria set in new EU rules in the 2021-2030 period. Currently, the US exports soybeans to the EU for animal feed but the soybean oil byproduct has to be shipped back because Europe does not allow it to be used for fuel. The new rule would change that.

European companies bought a record amount of wind power capacity last year, as energy-hungry businesses like aluminum producers and IT giants look for greener ways to drive their machinery and data centers. As wind power becomes competitive on price with conventional energy in many countries, big companies have rushed to secure renewable energy to manage costs and reduce their carbon emissions, while boosting their image with customers. New wind deals through so-called corporate PPAs were signed in Europe last year for 1.5 GW of capacity, up from 1.3 GW in 2017, according to new data from industry body WindEurope. Wind power PPAs signed by companies in Europe have now reached a total capacity of 5 GW, almost the same as Denmark’s total wind energy capacity, WindEurope said. In 2018, the biggest buyers of wind power in Europe were aluminum producers Norsk Hydro and Alcoa, which both signed big deals to buy power from farms in Norway and Sweden.

The French government and utility EDF will study the possibility of converting the 1.2 GW Cordemais coal power generators to burn biomass due to its importance in guaranteeing security of supply, the energy ministry said. President Emmanuel Macron’s government plans to phase out electricity production from France’s remaining coal-fired power plants by 2022 as part of measures to curb carbon emissions and global warming. The government plans to reduce France’s dependence on nuclear power which accounts for over 75 percent of French electricity needs, while boosting the development of greener energies. French power grid operator RTE, has warned that the plan to shut down some coal and nuclear generators, could leave France, a net exporter of electricity in Europe, largely dependent on neighbours during peak demand periods, particularly in winter. Anxious to guarantee French electricity supply, the ministry and state-controlled utility EDF are studying a project to convert the power station to biomass, the energy ministry said. The ministry said the study would look at the environmental impact and economic viability, while additional analysis would be carried out by grid operator RTE on the security of supply particularly in western France.

French energy major Total is partnering with Denmark’s Orsted and renewable energy producer Elicio to submit a joint bid for the 600 MW capacity Dunkirk offshore wind project in France, the company said. The bid is the oil and gas major’s first serious foray into offshore wind in decades as it expands its presence in the renewable energy value chain. Until recently, Total’s major investments in renewables have been chiefly in the solar segment, with its $1.3 bn (£1.01 bn) acquisition of SunPower and purchase of a 23 percent stake in solar and wind energy producer Total Eren. Meanwhile European peers such as Equinor and Shell have been increasing investments in offshore wind developments. The company plans to invest $1.5-$2 bn annually in low-carbon electricity with a target of around 10 GW of installed capacity by 2022. Orsted manages more than a quarter of the world’s installed wind capacity, while Elicio is particularly active in wind power in France and Belgium.

Equinor and KNOC will explore opportunities to develop commercial floating offshore wind farms in South Korea, the Norwegian company said. South Korea aims to reduce its dependence on nuclear and coal power, targeting an increase in the share of renewable energy to 20 percent by 2030, compared with 7.6 percent in 2017, the country said last year. Equinor said this translates to a target of 49 GW of new generation capacity. KNOC plans to develop a 200 MW floating offshore wind project 58 km off the coast of Ulsan City, the company said. Equinor has built and is operating the world’s first commercial floating offshore wind farm – Hywind – off Scotland, where its five turbines have total capacity of 30 MW. Floating turbines are considered the next step in conquering wind resources in deep coastal waters where fixed turbines cannot be built, such as Japanese waters or off the coast of California. Equinor said it has submitted a bid to build an offshore wind park off New York using fixed-base turbines.

Boosting renewables to 65 percent of Germany’s power mix by 2030 could cost €20 bn more than previously planned, which will mean higher consumer energy bills, TSOs — EnBW’s TransnetBW, 50Hertz, TenneT, and Amprion said. Last year, Germany raised its target for the contribution of renewables to 65 percent by 2030 from 50 percent in a bid to reduce CO₂ emissions by 55 percent over 1990 levels. It is set to miss a 2020 target aimed at cutting emissions by 40 percent. About two fifths of power needs in Europe’s largest economy are now met by renewables, but this needs to rise as it seeks to close nuclear plants by 2022 and coal power stations by 2038. As a result, power grids need to be extended to reach renewable energy sites. This will include new transmission lines to connect the industrial south with northern wind power farms.

Germany should shut down all of its coal-fired power plants by 2038 at the latest, a government-appointed commission said, proposing at least €40 bn ($45.7 bn) in aid to regions affected by the phase-out. The roadmap proposals, a hard-won compromise reached after more than 20 hours of talks, must be implemented by the German government and 16 regional states. They embody Germany’s strategy to shift to renewables, which made up more than 40 percent of the energy mix last year — beating coal for the first time — and follow a 2011 decision to halt nuclear power. Chancellor Angela Merkel’s cabinet welcomed the plan hammered out by the commission that included 28 voting members from industry, academia, environmental groups and unions, plus three non-voting members from the ruling parties. In a first step, plant operators including RWE, Uniper, EnBW and Vattenfall will be asked to shut down about 12.7 GW of capacity by 2022, equivalent to about 24 large power station units. Under the proposed plans, coal power capacity in Germany would more than halve to 17 GW by 2030. If implemented, the proposals would be the second major intervention in Germany’s energy market within a decade. The German government decided in the wake of Japan’s Fukishima disaster in 2011 to stop producing nuclear power by 2022. While the 2038 date to exit coal was in line with expectations, the report said the phase out could be completed by 2035 — a decision that would be taken in 2032.

Albania wants to make the environment a key measure of its energy policy and study whether its small hydro power plant strategy is worth pursuing. The investigation into 182 licenses issued to build 440 hydro plants stems from a plan to build a small plant on a river in southeastern Albania, which protesters said would endanger a waterfall key to tourism in a poor area. Since mid-2000 when a shortage of electricity supply caused long power cuts, successive Albanian governments have signed contracts to build, mostly small, hydropower plants, but so far only 96 plants are fully operational. The damage these small hydro power plants caused could outweigh any economic gain. The review will ascertain if contractors have built the plants as specified and to deadline, and whether they have complied with environmental requirements.

Algeria plans to issue several tenders for renewable energy projects this year as it seeks to meet growing demand for electricity and save gas for export. The OPEC oil producing member hopes to build solar plants to produce 22,000 MW, or 27 percent of its electricity needs, by 2030, up from about 350 MW now. Algeria will soon invite bids from national and foreign firms to set up a solar plant with a capacity of 150 MW, the energy ministry said. Turning to solar power is part of a drive to guarantee cheap retail energy prices. The authorities are keen to avoid social unrest, and face sporadic protests in some areas over a lack of electricity and gas supplies. Algeria is currently using gas to generate 98 percent of its power output of 19,000 MW. Increasing or maintaining the level of gas and oil exports is a top priority for the country as the two energy products make up 60 percent of the budget and 94 percent of total sales abroad.

The number of jobs in the US solar industry dropped by 3.2 percent in 2018, a second year of losses, as the Trump administration’s tariffs on foreign panels and state-level policy changes hit demand for installations, according to an industry report. The job losses reflect how changing trade and environmental policies can alter the trajectory of an industry that was among the fastest-growing segments of the US energy industry. The number of solar energy workers fell by 8,000 to 242,000 in 2018, according to the Solar Jobs Census, released annually by the non-profit research firm The Solar Foundation, following a loss of 10,000 jobs in 2017. But jobs are expected to rise next year, the report said. Policies of US states are also critical to solar growth, and changes in incentives and rates for projects in large markets led to job losses there, according to the report. In California, utility procurement slowed because power companies have fulfilled near-term renewable energy procurement requirements. The state’s commercial market slowed due to a shift to rates that are less favorable to solar. In Massachusetts, the commercial market stalled ahead of the introduction of a new incentive scheme at the end of the year. The Solar Foundation said it expects a rebound in jobs of 7 percent next year, however, due to recent declines in solar panel prices that have made them more affordable. China last year slashed subsidies for solar installations, unleashing a flood of low-cost Chinese-made panels onto the international market and pushing prices below what they were before the tariffs were imposed. Installation will receive the biggest bump, more than 9 percent, the report said, while manufacturing will rise 4 percent, the report said.

South African miner Harmony Gold is in talks to build a 30 MW solar power plant in the Free State province to supply power to some of its operations to try to reduce power costs and dependence on struggling utility Eskom. Eskom, which produces over 90 percent of South Africa’s electricity, is saddled with more than $30 bn in debt and has had to impose some of the country’s worst power cuts in years over the past few days. Eskom’s troubles are a big headache for heavy energy users in South Africa, particularly gold mining companies. Harmony said it was in talks with the state energy regulator over a licence to build a solar power plant in Welkom in the Free State province. The company, which uses around 280 MW of power at its South African operations, plans to use the solar plant to help to supply its longer life assets including its Tshepong operations in the Free State. Harmony said it had also taken action to reduce consumption during peak periods and improved efficiency of pumping operations.

The government of Bosnia’s autonomous Serb Republic awarded 50-year rights to power utility ERS to build and operate two hydropower plants with combined capacity of 95 MW on the Drina river bordering Serbia. The projects are expected to cost €200 mn (174 mn pounds) and are aimed at diversifying Bosnia’s energy sources. State-controlled ERS operates two coal-fired power plants with combined capacity of 600 MW and three large and several small hydropower plants with total capacity of 617 MW. ERS had earlier agreed to build the two new plants with Serbian counterpart EPS. Unlike its Balkan neighbours, which rely on imports to cover part of their demand, Bosnia is able to export power thanks partly to its hydropower capacity, which provides 40 percent of its electricity. The rest of Bosnia’s electricity comes from coal-fired plants.

Colombia has received bids from more than two dozen companies that want to participate in the country’s first-ever tender of renewable energy projects. The tender is part of the Andean nation’s efforts to expand and diversify its electrical energy provision. Some 70 percent of Colombia’s electricity is generated with hydropower. Bidding for 22 different solar, wind and biomass projects will take place on 26 February. Twenty-seven local and multinational companies are set to participate, the Minister said. The projects are expected to begin electricity production in 2021. The government wants to have the capacity to generate 1,500 MW of electricity from renewable sources within four years, up from the current capacity of 50 MW. Besides hydropower, some 20 percent of the country’s electricity currently comes from gas and liquid fuel, some 8 percent from coal and just 2 percent from renewables.

Google said it has signed a long-term agreement to buy the output of a 10 MW solar array, which is part of a larger solar farm, in Tainan City in Taiwan. This will be the company’s first purchase of renewable energy in Asia, the company said. The project will be located 100 km south of the company’s Changhua County data centre and connected to the same regional power grid, it said. Big companies have rushed to secure cheap renewable energy to manage costs and reduce their carbon footprint through corporate power purchase agreements which allow firms such as Google, owned by Alphabet Inc, Facebook and Microsoft to buy directly from energy generators.

MoU: Memorandum of Understanding, MW: megawatt, GW: gigawatt, US: United States, BHEL: Bharat Heavy Electricals Ltd, NPCIL: Nuclear Power Corp of India Ltd, mn: million, bn: billion, CFA: Central Financial Assistance, MNRE: Ministry of New and Renewable Energy, MtCO2e: metric tonnes of carbon dioxide equivalent, SECI: Solar Energy Corp of India, kWh: kilowatt hour, UT: Union Territory, CREST: Chandigarh Renewal Energy, Science and Technology Promotion Society, kW: kilowatt, GERC: Gujarat Electricity Regulatory Commission, GUVNL: Gujarat Urja Vikas Nigam Ltd, SEWA: Self Employed Women Association, PV: photovoltaic, DHBVN: Dakshin Haryana Bijli Vitran Nigam, discom: distribution company, GEDA: Goa Energy Development Agency, UK: United Kingdom, km: kilometre, IIT: Indian Institute of Technology, NEA: National Energy Administration, CO2: carbon dioxide, EU: European Union, PPAs: power purchase agreements, KNOC: Korea National Oil Corp, TSOs: transmission system operators, OPEC: Organization of the Petroleum Exporting Countries

Courtesy: Energy News Monitor | Volume XV; Issue 38