Monthly Coal News Commentary: November – December 2017


India’s coal imports from North America are likely to surge as buyers are looking to boost purchases amid a domestic shortage of the fuel and a regional ban on petroleum coke, traders said. Shipping data showed that India’s coal imports from North America tripled to 2.1 mt in October from a year ago which is more than 70 percent of last month’s purchases. Other trading sources put this figure lower, at 1.47 mt. Coal imports for November 1-20 have reached 1.14 mt. Indian imports of North American coal, including supplies from Canada, stand at about 1.5 mt from November 1 to 20, data showed, already more than 70 percent of last month’s purchases. A ban on the use of petroleum coke, a dirtier but better-burning alternative to coal, is spurring expectations India will buy even more coal from the US in coming months. Cement companies account for nearly 75 percent of India’s annual petcoke demand of 27 mt according to trade data, and small industries such as lime manufacturers are also considering the use of US coal, which is almost as efficient as petcoke. The petcoke ban may deter the plan to cut India’s coal imports, which have risen for the first time in the past two months after falling in the past few years. Petcoke has been banned in some states around the Indian capital New Delhi which is battling heavy smog. Buyers are looking to boost purchases amid a domestic shortage of the fuel. But rising pollution in other Indian cities could lead to tougher restrictions such as a nationwide ban on use and imports of petcoke, with environmentalists requesting other states in the country to consider banning the use and import of the dirty fuel.

CIL is considering raising prices to meet the cost of the 20% wage hike. It last raised prices by 10% in May last year. The company said the wage bill puts an additional burden ₹ 58 billion annually, and another ₹ 95 billion needs to be spent on expansion. Further, the company has decided to sell more coal to power plants, which gets it lesser revenue than other buyers. Coal sold through spot e-auctions earns the highest while that sold to the non-power sectors earns 20% higher revenue. In the second quarter of the current financial, CIL’s profit halved to ₹ 3.68  against ₹ 6.12 billion a year ago. CIL the world’s largest coal miner, will pay its executives about ₹ 8 billion ($124.08 million) in salary rises retroactive from January this year. The pay increase, which was approved by the board, comes over a month after the company approved a rise in the salaries of its workers, costing ₹ 56 billion over five years. The company employs more than 300,000 people, about 18,000 of whom are executives.

After an average wage revision of 20 percent for around 298,000 permanent employees of CIL trade unions are now readying to pitch for a similar wage agreement for contractual workers of the miner. The company had said it has signed a wage agreement with workers’ unions, proposing a 20 percent hike in salaries for a period of five years. The 10th wage agreement effected in October would have an estimated impact of ₹ 56.67 billion per year on the world’s largest coal miner. Trade unions expect the average wage hike for the contract workers – whose number is estimated to be anywhere between two to three lakh – in the range of 15-20 percent.

Coal dispatches from state-run miner CIL to power sector improved by 18 percent to 39.9 mt  in October, data showed. The power ministry earlier this month had also stated that coal stocks at power plants were “much better” and dry fuel inventories had started building up at the plants. CIL had supplied 33.8 mt of dry fuel to power producers in October 2016. The dispatches by the world’s largest coal miner rose by 9.6 percent to 248.9 mt in the April-October period of this financial year over 227 mt in the year-ago period. The supply of coal by SCCL, a state-owned coal mining company, also registered an increase of five percent to 4.2 mt, over 4 mt in the same month of the previous financial year. The number of plants facing acute coal shortage had come down to 12-13. The coal ministry earlier had blamed power producers for low stocks of dry fuel at their plants. Karnataka had asked the Centre to ensure adequate supply of coal and early allocation of a coal block situated in Odisha to meet the severe fuel shortage being faced by power units in his state. Rajasthan Urja Vikas Nigam in September had said that power generation at thermal power stations reduced by 2,700 MW due to shortage of coal, forcing it to resort to load shedding in the state.

The government has asked CIL to focus on production enhancement, saying it cannot let the “profitability tumble” as the recent wage hike will have an estimated impact of nearly ₹ 60 billion annually. CIL had in October signed a wage agreement with workers’ unions proposing 20 percent hike in salaries for a period of five years, which will have an estimated impact of ₹ 56.67 billion per year to the world’s largest coal miner. The public sector firm had signed the agreement at 20 percent hike in salaries against workers’ demand for a 50 percent raise. In 2017-18, CIL has been pegged production target at 600 mt with an annualised growth of about 8.3 percent over the last year. In 2018-19, the envisaged coal production projection is 773.70 mt with a growth of about 28.95 percent. Making a case for CIL’s foray into metal and mineral mining, the government has said the state-owned firm being the biggest miner in the world would like to leverage the expertise for diversification. CIL had said that the modalities for diversification into new mineral mining was expected to be ready in the next few months. According to CIL, the foray into new metals and minerals will not hinder or cause any conflict with coal production targets. CIL, which accounts for over 80 percent of the domestic coal production, is eyeing 1 billion tonnes output by 2019-20.

Making a case for CIL’s foray into metal and mineral mining, the government has said the state-owned firm being the biggest miner in the world would like to leverage the expertise for diversification. CIL had said that the modalities for diversification into new mineral mining was expected to be ready in the next few months. According to CIL, the foray into new metals and minerals will not hinder or cause any conflict with coal production targets. CIL, which accounts for over 80 percent of the domestic coal production, is eyeing 1 billion tonnes output by 2019-20.

BHEL announced commissioning of a 54 MW coal-fired captive power project in Indonesia. The 3×18 MW power project located at Sangatta, East Kalimantan, Indonesia has been set up by BHEL for PT Citra Kusuma Perdana for their coal-mining operations, BHEL said. BHEL has executed several projects in the region including projects in Malaysia, Taiwan, Thailand and Vietnam. In Indonesia, the company has earlier successfully executed a 2×30 MW boiler project for PT Makmur Sejahtera Wisesa and 2×11 MW and 1×15 MW captive power projects for PT Indo Bharat Rayon.

The GSPCB has moved court seeking criminal prosecution against MPT and SWPL for handling excess coal. GSPCB said that the board pleaded before the first class judicial magistrate in Vasco that MPT and SWPL should be prosecuted for violating the conditions of the consent to operate issued to it under the Air and Water (Prevention and Control of Pollution) Act. The MPT, which is located at Vasco, has been accused of handling excess coal at berth Nos. 10 and 11 for 2014-2015 and 2015-2016 in violation of the consent orders issued by the GSPCB. The SWPL, the GSPCB said, handled excess coal at Berth Nos. 5A and 6A at MPT for 2012-13, 2014-2015 and 2015-2016.

The underground coal fire in Ramgarh which is threatening to damage NH-33 and Koderma-Barkakana rail route in Kuju, may have been caused by illegal coal miners, said CCL, a subsidiary of CIL. Though authorities of the CCL recently got the nod from the state forest and environment department to start digging on a 5-acre plot of forest land to prevent the fire from doing further damage, the root cause of the problem remains unaddressed.

Indian energy giant Adani’s controversy-hit Carmichael coal mine project in Australia may not receive a A$900 million (900 million Australian dollars) after the Labour party- led Queensland government said it will exercise its veto to not support the financial assistance. The A$16.5 billion Carmichael coal mine project, one of the world’s largest, will start construction after being given the green light by the federal and Queensland state governments. The Adani group had applied for NAIF loan worth A$900 million for building a train line to connect its mine to the coast. Queensland Premier Annastacia Palaszczuk announced that her Labor party would veto the NAIF loan if it retains the power in the state. Palaszczuk said her government will exercise its ‘veto’ to not support the NAIF loan to remove doubt about any perception of conflict.

Power ministry is not mulling any amendment in laws for passing on the cost of retrofitting coal based-power plant to consumers. Power producers can always go to their respective regulators or electricity regulatory commissions to seek approval for increasing power tariff to recover any such expenditure citing new norms issued by environment ministry in December 2015. The generators have no option but to go for retrofitting of their plants. The cost of retrofitting a power plant ranges from ₹ 10-12 million/ MW while that for new coal-based plant would be around ₹ 50 million/MW. As many as 295 coal-based power plants have got more time of two to four years to meet strict new environment norms which were to be implemented by December 2017.

Scurrying for solutions to fight the toxic air pollution, the government has said it plans to transport coal in covered rail wagons and trucks across the country. Ferrying of coal in uncovered vehicles and rail wagons is said to be one of the key reasons behind high pollution levels along the transportation route from coal mine or importing sea port to user plants like power generation houses. For the third straight year, in the month of November, thick toxic smog enveloped the national capital region (NCR), leading to what has been called a health emergency. Coal-fired power plants are said to be one of the sources of pollution. India generates about 65 percent of its electricity using coal as fuel. It is abundantly available in the country and is cheaper than alternate fuel sources like natural gas and liquid hydrocarbons. Power plants follow stringent standards but newer equipment like Flue-gas desulphurisation (FGD), which removes sulphur dioxide, will take time to be installed. But, to begin with, transporting coal in covered wagons and trucks is being done.

Rest of the World

Chinese coal imports rose in November from the month before on firm demand during the winter heating season, even as Beijing encourages a shift to cleaner fuels in its battle against pollution. Shipments into the world’s top coal importer reached 22.05 mt in November, up 3.6 percent from October, but down from 26.97 mt a year ago, data from the General Administration of Customs showed. Coal prices in China have risen steadily this year, touching their highest since at least 2015 at 688.8 yuan ($104.07) a ton on December 4.

China is likely to complete its coal capacity reduction target by 2018, the NDRC, China’s top economic planner, said. China is expected to cut the total number of coal mines to 7,000 next year, from 10,800 in 2015, NDRC said. Coal supplies will be ample in 2018 with many coal mines increasing their production capacity. The domestic market will be balanced next year as China keeps importing coal and increases domestic output.

China’s biggest coal producers China Energy Investment Group and China National Coal Group (ChinaCoal) will keep their 2018 coal contract prices at the same level as 2017. After rounds of discussions between policy makers, major producers and utilities, the producers will set the price at 535 yuan ($80.72)/tonne. The new level has disappointed utilities just one week before China’s annual coal trade meeting in the northern port city of Qinhuangdao from November 21 to 23 when producers and utilities will negotiate volumes for next year. Last year, the NDRC, China’s top economic planner, asked coal producers to sell at 535 yuan per tonne to bring down rising prices. Rolling the policy over to this year will not help lower coal prices.

China has again urged coal suppliers and buyers to sign more medium- and long-term contracts, amid robust demand for the fuel during the peak winter-heating season. The NDRC said that medium- to long-term contracts should make up 75 percent of supply deals signed by government and municipal authorities as well as power firms. It said that railways, ports and shipping firms should make handling such contract business a priority. Contracts should run for at least a year. The NDRC had already ordered coal companies and utilities in April to fix 75 percent of their total coal purchases through long-term contracts. But Chinese thermal coal futures have still surged this year, recently rallying about 7 percent since early November to 655.6 yuan ($99.29)/tonne.

A Chinese company started construction of a new 350 MW unit at Serbia’s second largest coal-fired power plant, the first new electricity capacity in the Balkan country in nearly 30 years. The $613 million project is part of a wider deal between Serbia and China that includes expansion of a nearby coal mine and upgrade of existing capacity in the Kostolac coal-fired plant complex. Export-Import Bank of China will provide 80 percent of the funding for the entire project of $715 million through a 20-year loan. The Serbian government will secure the rest of the funds. China Machinery and Engineering Corp is carrying out the construction. Serbia generates two thirds of its electricity from ageing coal-fired plants and the rest from hydro power. It urgently needs to upgrade its energy infrastructure to meet rising demand.

Four cities in northeast China have secured a loan of $310 million from the ADB to revitalize their economies, the bank said, two years after mass layoffs at local coal mines triggered unrest in the region. The cities of Hegang, Jixi, Qitaihe and Shuangyashan – in northeast China’s Heilongjiang province – were the major casualties of a 2015 decision by state-owned Longmay Group to slash coal production, close depleted mines and lay off as many as 100,000 local workers, part of nationwide efforts to tackle overcapacity and shore up prices in the sector. The ADB loan to the four cities will be used in a project worth a total $1 billion that is designed to support the development of small- to medium-sized enterprises and help tackle environmental damage caused by decades of coal mining, the bank said.

Nippon Steel & Sumitomo Metal Corp, Japan’s biggest steelmaker, expects coking coal to stay above $200 a ton through the January-March quarter amid lower supplies from Australia, which may drag on its earnings. Australian premium coking coal futures in Singapore have surged nearly 30 percent from a November low of $174 to above $220 a ton in the first few days of December.

Greece has finalised a deal with its official creditors on the coal-fired plants the country will sell to comply with an EU court ruling. The issue was at the top of the agenda of talks between Greece and its EU and International creditors, who are reviewing the country’s bailout progress on energy and labor market reforms, on fiscal targets and privatisations.

EU state aid regulators opened an investigation into Spain’s environmental incentives for coal power plants, concerned that the scheme may give the facilities an unfair advantage. Fourteen coal power plants have received more than €440 million ($525 million) for installing new sulphur oxide filters since the scheme was introduced in 2007, with the payments due to continue until 2020. The European Commission said such incentives to reduce harmful sulphur oxide emissions may not have been justified as coal power plants were already required by EU environmental laws to do so.

Japan’s METI is seeking to determine whether clauses in long-term coal contracts that bar buyers from diverting and reselling cargoes are limiting trade. Destination clauses limit where cargoes can be delivered and prevent companies from selling excess coal to third parties in other places. METI is examining whether there’s a need to shift to spot and short-term trading from long-term coal contracts, the report said, adding that it had held a meeting with several firms and plans to draft an interim report on the coal market in February.

At least 15 countries have joined an international alliance to phase out coal from power generation before 2030, delegates at UN climate talks in Bonn said. Britain, Canada, Denmark, Finland, Italy, France, the Netherlands, Portugal, Belgium, Switzerland, New Zealand, Ethiopia, Mexico and the Marshall Islands have joined the Powering Past Coal Alliance, delegates said. The alliance aims to have 50 members by the next UN climate summit in 2018 to be held in Poland’s Katowice, one of Europe’s most polluted cities. But some of the world’s biggest coal users, such as China, the United States, Germany and Russia, have not signed up. The event triggered a peaceful protest by anti-coal demonstrators and jarred with many ministers who are working on a rule book for implementing the 2015 Paris Agreement, which aims to move the world economy off fossil fuels. Since signing the Paris Agreement in 2015, which aims to wean the world off fossil fuels, several countries have made national plans to phase out coal from their power supply mix.

Indonesia coal miner Bumi Resources estimates its output will rise to around 95 mt in 2018 from between 88-90 mt this year. Bumi had not officially revised its earlier guidance of up to 94 mt this year. But with “unusually heavy rainfall” the company hopes to achieve sales of between 87 million and 88 mt of coal in 2017. Higher coal prices this year compared to a year ago would compensate for the flatter than expected output volumes.

CIL: Coal India Ltd, mt: million tonnes, SCCL: Singareni Collieries Company Ltd, MW: megawatt, GSPCB: Goa State Pollution Control Board, MPT: Mormugao Port Trust, SWPL: South West Port Ltd, CCL: Central Coal Fields Ltd, NAIF: Northern Australia Infrastructure Facility, NDRC: National Development and Reform Commission, ADB: Asian Development Bank, EU: European Union, METI: Ministry of Economy, Trade and Industry, UN: United Nations

Courtesy: Energy News Monitor | Volume XIV; Issue 28


13th Petro India: The Future of Energy: Will Availability meet Demand? (A Brief Report)

K K Roy Chowdhury, Energy & Environment Expert, Delhi

The India Energy Forum (IEF) and the Observer Research Foundation (ORF) presented the conference on the “Future of Energy” incorporating 13th Petro India in partnership with the media group Mail Today on 16th January 2015 in New Delhi. A glimpse of the important deliberations in the Conference is presented below.

Inaugural Session:

After Mr Sandeep Bomzai, Editor, Mail Today, made the welcome remarks, the inaugural address was delivered by the Hon’ble Minister of State (independent charge) for Oil & Gas, Government of India, Mr Dharmendra Pradhan. The Minister dwelt at length upon the new Government’s plans for designing the future energy basket for India with emphasis on renewable energy and energy efficiency that were also in line with the spirit of Prime Minister Narendra Modi’s vision ‘Make in India’.

On the issue of petrol and diesel prices, the Minister said that the issue of reducing petrol and diesel prices was not in the hands of the Government as the two fuels were deregulated commodities whose pricing was decided by oil companies. He said that ‘what oil companies felt appropriate would be done’.

Mr S C Tripathi, former Secretary, Petroleum, in his address reiterated his long-time proposition for addressing energy as an integrated whole, and not through divided Ministries as it has been historically. Drawing some amount of satisfaction from the fact that the new Government had reformed it into two Ministries, namely, one for, ‘Coal, Power and Renewable’, and the other for ‘Petroleum’, he however opined that coal and petroleum should be together since both are extractive in nature. Pointing at the restrictive policies India had adopted in harnessing fossil fuels such as coal, etc., he hoped that the new Government at the Centre would be rational in times to come. Mentioning that India’s developmental path had been energy-intensive, Mr Tripathi stated that if India were to follow the Chinese path with emphasis on manufacturing, then India’s energy requirements would have been more. He expected a spurt in energy demand as India embarks on the ‘make in India’ policy.

Commenting on India’s exploration policy, Mr Tripathi called for increasing the focusing on gas and oil, this being the right time to acquire assets abroad, and also to focus on trans-border pipeline and LNG projects. In view of the fact that there is no UN Agency for Energy, such acquisition strengthens the commanding position of a country, he opined. Towards India’s quest for prosperity, he suggested a move towards long-term contract for LNG, with Australia, Qatar, or Iran, or may be, other producers of LNG.

Oil & Gas: Where Next?

This session included a panel discussion with Mr R S Butola, former CMD, IOC, MrAtul Chandra, former MD, ONGC Videsh and Mr VipulTuli, Partner, McKinsey & Co.  Adresses by GoI Secretary-Power, Mr P K Sinha, and by Dr Arup Roy Chowdhury, CMD, NTPC followed this panel discussion.

The Panel discussed various aspects of overseas oil & gas investments by India, exploration status, fiscal incentives, internationalcompetitiveness, etc. Regarding investment prospects in India, Mr Chandra informed that foreign companies like Exxon, BP and Chevron would not go to a country where the investment level is less than $ 1 billion and added that BP had come to build a gas business in India. Another aspect he pointed out is the apprehension of the foreign companies of the fact that litigation risk persists in exploratory drilling and that this is a deterrent for foreign investment.  He said that the large foreign companies had extensive knowledge of oil & gas prospects which he illustrated with investment by Cairn in Rajasthan. He said that large companies invest in Saudi Arabia and other countries in the Middle East even though profits are low there because the geological prospects were attractive. The Government’s tight control of the hydrocarbon sector through its bureaucracy made it difficult to do business in India, Mr Chandra observed. He further added that acquisition of hydrocarbon assets had been more of a fashion than the result of research.  He also observed that reforms may not be possible without privatization.

Mr Butola threw some light on India’s frontier geology which remained largely unexplored and observed that large acreages for exploration make it attractive. Emphasizing upon the need for retaining manpower in a competitive environment he also said that costs can be controlled if companies are better managed. Mr Butola further added that OPEC share of the market had declined compared to that in the 1980s and that there is a much bigger role for other players in the market. On the issue of reforms, he said that the public sector had to follow State norms and the concerned Ministry was answerable to the Parliament.

Acknowledging that fiscal incentive and the pricing regime of the sector certainly mattered, Mr Vipul Tuli referred to India being one amongst the top five consumer-driven economies and that large oil companies looked for large projects with high prospectivity.  But he observed that prospectivity was low in India as of now.  He called for organizing roadshows to attract Tier II and Tier III companies of which there were many. Commenting on the drop in oil prices, he said that the increase in production from Iraq, Nigeria and the USA and the absence of peak oil along with subdued demand were key reasons. He said that China’s growth of oil demand was expected to fall from 3.5% to 2.5% and that demand growth would be negative in Europe.  He said that USA may export to Asia or other regions as their storage was full. He observed that within OPEC, there is was a conflict between typical low-cost producer such as the GCC countries and higher cost producers that led to conflict within OPEC. He also said that there was conflict between OPEC and non-OPEC producers for market share. He felt that this period of low energy prices presented a unique opportunity for investing in long-term infrastructure and urged the oil companies to play a role.  He also mentioned that less than 50 percent of our basins were mapped and that investment must be made towards this.

On the question of India being both capital and energy deficient Mr Atul Chandra said that the abundance in manpower could be leveraged. He emphasized that the Government should play the role of a facilitator.  In this context he observed that ONGC was empowered to take decisions. Mr Butola added that deep-water exploration of oil was expensive and that his interactions with foreign companies revealed that they have interest in India. He pointed out that lack of exploration data as a problem.

On the question of ‘What difference needs to be done to get better returns’, the Panelists conveyed the following message:

  1. Mr Vipul Tuli said that the target companies must be identified based on size and that our commitment must be communicated clearly.
  2. Mr Atul Chandra agreed with the remarks made by Mr Tuli and urged for collection of more data. He expressed the need for distinguishing between Individuals and Institutions.
  • Mr Butola too agreed with fellow panellists and he emphasized the need for nurturing talent even within the public sector.


In his key note address Mr P K Sinha, Secretary, Power said that highlighted the growth of the power industry which started with an installed capacity of 1360 MW in 1947 and expanded to over 250 GW of installed capacity over six decades. He highlighted key milestones such as the passing of the Electricity Supply Act of 1948, the separation of Water and Power Ministries in the 1970s, the creation of NTPC and NHPC that followed, the setting up of the Power Grid Corporation in the 1980s, the passing of the CERC Act in the 1990s that enabled the creation of Central and State level electricity regulators and passing of the new Electricity Act in 2003 that enabled the entry of the private sector into power generation. He also highlighted some of the challenges facing the industry such as the lack of sufficient transmission capacity that could transfer surplus power available in the western region to the power deficit southern region. He pointed out that distribution remained the weakest link in the chain but expressed hope that the next wave of reforms would begin with the distribution end.  He also pointed out that renewable energy would play a greater role in power generation in the future.  Answering a question on stranded assets, the Secretary said that assets were stranded primarily because their expectations on gas supply did not materialise and that this would be addressed through the price pooling mechanism.

Delivering the key note address for the session Mr Arup Roy Choudhry, CMD, NTPC said that power projects were stranded because plans for investment in power generation had not been coordinated with simultaneous plans for increasing coal production and plans for streamlining transport linkages. He also noted that most of India’s coal was in tribal forest land which resulted in inevitable delays in obtaining approvals. He said that the result was that coal based power generation capacity had growth rates that were three times the growth in coal production.

He clarified that stranded assets in the power sector included assets that were almost complete and those that had barely begun and that the stranded assets affected the balance sheets of banks that put money in these projects.  He pointed out that while the power plants operated by NTPC were well adapted to the type of coal available in India and also to the climatic conditions under which they operate but newer plants constructed at higher cost were not well adapted to Indian conditions. He also raised some fundamental questions over increasing economic growth through increased energy consumption. He pointed out that many in India cannot afford to pay for power generated by NTPC which had one of the lowest generation costs in India.  He expressed concern over the sad situation where households around huge well lit power plants that remained in the dark without power on account of poverty.

Mr. Anil Razdan, former Secretary Power Mr H.L. Bajaj, former Chairperson of CEA, Mr. S.K. Soonee, CEO, POSOCO, Mr M K Madan, CEO Adani Power and Mr Roy Choudhury participated in the panel discussion that followed. The panellists felt that Power for All was a good slogan as it sought to empower the people but raised some issues in implementing the programme. They agreed that the distribution end remained a challenge and affordability was a key issue. They said that unless the distribution end was made self-sustainable and viable, the goal of supplying power to all would not be achieved. One of the panellists pointed out that there was a strong expectation that power would be free even from fairly affluent households. The panellists pointed out that   increase in power tariff was not necessarily a vote losing proposition and offered examples from different parts of India.  They said that the sector was open to participation from the private sector even in the 1980s and that more than one license for distribution was allowed even at that time.

One of the panellists suggested that the Government should amend the Constitution and make access to power a fundamental right so that the State had the responsibility to provide power.  Another panellist challenged the notion of scarcity of power and pointed out that just as famines did not occur because of a problem in the supply of food, power shortages did not occur because of a shortage in the supply of power but rather because of problems in other linkages necessary such as transmission and distribution lines and the ability to pay for power.

There was general agreement that as distribution was a State subject, the budgetary provision was not enough for upgrading the distribution network and that short election cycles inhibited long term projects to improve the distribution segment.  The neglect of the hydro power segment on account of its long gestation period was also highlighted.  There was agreement that things were moving in the right direction as power deficit has been reduced to about 3 percent from about 10-12 percent. The question of inadequate capacity for transmission was discussed in depth and the issue of availability based tariff and peaking tariff was raised.  The panellists agreed that demand was being suppressed by illiquid distribution companies and that this could be behind lower figures for power deficit.  The success story of power trading and price discovery through short term trade was acknowledged by all the participants.

The panel discussion was followed by a theme address by Mr Sunjoy Joshi, Director, Observer Research Foundation.  He said that India which imported 50 percent of its energy needs could not be isolated from global movements and that global coal prices collapsed when the United States shifted to gas for power generation because energy markets were integrated. He highlighted that the strongest Government in the world was weaker than the weakest market and that the shift in prices across the world of energy commodities would cause a tectonic shift in moving wealth across the world.  He observed that the PPP model had failed to deliver in India as the model was not implemented well. He concluded that the low oil price regime presented an opportunity for reform and that the moment must seized before it closes.


Mr. Suresh Prabhu, Union Minister for Railways who delivered the valedictory address in the concluding session began with observations on the uncertainty in global energy markets and the resulting change in prospects for different types of energy sources. He said that though India was a marginal player in the energy markets currently it would be the largest consumer of energy on an incremental basis by 2030. He concluded his brief address by requesting suggestions on how the Railways can reduce the cost of energy.

Mr. Anil Razdan, former Secretary, Power, Mr. Alok Perti, Former Secretary, Coal, Dr. M. P. Narayanan, Former CMD-CIL, Mr. Nitin Zamre, MD, ICF International participated in the panel discussion on coal. Mr Perti said that raising production of the coal by and the prospect of movement towards underground mining were key issues in the short term. He observed that the potential existed for increasing coal production to 1 billion tonnes per year but he expressed doubts over transport capacity and the consuming industries to absorb such a dramatic increase in production.

Mr. Narayanan commented that there was demand for 1 billion tonnes of coal and that he was optimistic over the industry’s ability to absorb the increase in production. He said that the Board of CIL was not sufficiently empowered and that a shift to under-ground mining would require serious thought on technologies that would be required. Mr. Nitin Zamre also expressed doubts over the demand for 1 billion tonnes of coal and the evacuation infrastructure that would be required to meet the spurt in production. He said that unless there was pressure on companies to perform or perish, their performance would not improve.

There was agreement that the coal mining sector must be thrown open to competition. The question of productivity of coal was discussed and the burdens of State owned companies were brought out. There was general agreement among the panellists for improving productivity and for washing coal to reduce the cost of transport. The need for rationalising the location of power plants and the location of coal washeries was discussed and the session concluded with agreement over the need to focus on better governance of the coal sector.

Views are those of the author                     

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 35


Monthly Gas News Commentary: November 2017


The country’s biggest private sector oil producer, Cairn India, part of the Vedanta group, is set to considerably increase its gas production to three million standard cubic metres a day (105.9 million standard cubic feet) by June 2019. Production from its RDG field is expected to increase to 100 mscfd by then. The firm’s production capacity for the September quarter of FY18 stood at of 33.8 mscfd. Activity on tenders for partnership with leading service providers for integrated delivery of RDG Phase-II is underway. This is expected to increase gas production and condensate production to over 5,000 boepd by the first half of 2019. As on September-end, gas sales, after captive consumption, stood at 18 mscfd. The company would also be undertaking drilling in its Krishna-Godavari block in the first quarter of 2018. The average gross production of Cairn India during the September quarter was 180,955 boepd. Gross production from the Rajasthan block averaged 153,238 boepd. The current investment will cater to five blocks- the RDG project, the EOR programme at Aishwariya fields, the EOR programme at Bhagyam and Barmer Hill, and the Aishwariya Barmer Hill. The company’s production sharing contract for Barmer expires in 2020 but higher cess in the extended regime could impact plans.

ONGC officers association has sought Prime Minister’s intervention to stall oil ministry’s plan to sell the company’s producing O&G fields, saying the move has highly damaging implications for the country. The Association of Scientific & Technical Officers cited examples of falling production at the western offshore Panna/Mukta fields that were privatised in the 1990s, and Reliance Industries’ flagging KG-D6 fields to state that ONGC has done well with its ageing fields. Most O&G fields of ONGC have been in production for 30 years and output has naturally shown a dip from the peak level but still accounts for the bulk of domestic output. The Oil ministry has identified 15 producing oil and gas fields of ONGC and Oil India Ltd for handing over to private firms on the premise of raising output. The fields have in-place reserve of 791.2 mt of crude oil, and 333.46 bcm of gas have been identified. Production trajectory at Panna-Mukta field, which was taken away from ONGC and privatised, has been on a continuous decline. Also, Ratna-R Series fields which were given to Essar Oil could not be brought to production in two decades and have now been reverted to ONGC. If stagnant or flagging production is a criterion for identifying underperforming fields of ONGC, the same yardstick must be extended to all domestic fields. The production drop at KG-D6 to 5-6 mmscmd has also had a collateral damage to stranded gas-based plants and other struggling industries. ONGC’s view is that even when prices have tipped it is a misnomer that ONGC got everything on a platter by getting the blocks on the nomination. ONGC is investing heavily in new technology and processes to improve recovery from the ageing fields.

ONGC has sought more than doubling of natural gas prices to help bring significant discoveries in KG basin and Gulf of Kutch to production. Gas discoveries in shallow sea off Andhra Pradesh on the east, and off Gujarat on the west are economically unviable to produce at the current government-mandated price of $2.89/mmBtu. The company wants a price of over $6/mmBtu to help it produce the gas without suffering any losses. In the absence of a viable gas price, it will have to mothball the $1.5 billion projects, the company said. The government in October 2014 had evolved a new pricing formula using rates prevalent in gas surplus nations like the United States, Canada and Russia to determine rates in a net importing country. While prices have halved to $2.89/mmBtu since the formula was implemented, the government has allowed a higher rate of $6.3/mmBtu for gas fields in difficult areas like deepsea. The company said the KG basin block KG- OWN-2004/1 is in shallow water and does not qualify as a ‘difficult field’. On the western side, the block GK-28 in Gulf of Kutch is a nomination block which does not qualify for higher rates, the company said. While the KG block will produce a peak output of 5.35 mmcsmd the same from Gulf of Kutch block will be around 3 mmscmd. It would take a minimum three years to bring the gas finds to production. The combined output is about 14 percent of the ONGC’s current output of 60 mmscmd. ONGC also has a couple of smaller fields with a total expected peak production of 1.1 mmscmd, which cannot viably produce at the current domestic gas prices. For more than a year now, ONGC has been petitioning the oil ministry for setting a floor price of at least $4.2/mmBtu for domestically produced natural gas. The new formula provides for revising rates every six months — on April 1 and October 1, based on one-year average gas price in the surplus nations with a lag of one quarter. When the formula was implemented, rates went up from $4.2 to $5.05/mmBtu but fell to $4.66/ mmBtu in April 2015 and to $3.82 in October that year. In 2016, the prices further dipped to $3.06/mmBtu in April and to $2.50/mmBtu in October. In April this year, they fell further to $2.48/mmBtu but have from October 2017 risen to $2.89/mmBtu. The cost of production of natural gas in the prolific Krishna Godavari basin is between $4.99 to $7.30/mmBtu. The same for other basins is in the range of $3.80 to $6.59/mmBtu.

ONGC has sought higher gas prices from the government for a block it plans to develop in the KG basin, warning that it will otherwise have to mothball the $600 million-project, the company said. ONGC has recently written to the government asking for a special pricing dispensation for the block, KG-OSN-2004/1, which doesn’t qualify as a ‘difficult field’ under the government policy unveiled last year. India offers higher gas prices to fields located in difficult terrains such as deep water or high pressure, high-temperature areas. Price available to gas from difficult fields is $6.30/mmBtu as against $2.89/mmBtu for ordinary domestic fields. In the absence of higher gas prices, ONGC will not be able to develop the KG project as well as a few other projects, including one in the Kutch region. These projects together can produce about 10 mmscmd of natural gas. ONGC’s KG block has four fields in deep and ultra-shallow waters. Its field is 300 meters deep, less than the 400 meters depth that qualifies as deep water under the government policy. The expected peak production of 5.35 mmscmd of natural gas by 2020 from the KG project will likely get delayed if the company doesn’t begin investing immediately, the executive said. Without higher gas prices, another 4 mmscmd of gas production planned by ONGC will also get delayed, he added. The company is hoping to ready in three months the field development plan for Kutch-GK-28/42 block, which is expected to produce 3 mmscmd at its peak. ONGC has a couple of smaller fields with a total expected peak production of 1.1 mmscmd, which can’t viably produce at the current domestic gas prices. The field development plan for these are not yet ready. India’s domestic gas prices are calculated by a formula that tracks international rates. Prices are revised every six months. Accepting ONGC’s demand can trigger similar demand from other gas producers. Therefore, the government may have to bring about a change in the existing pricing policy so that it applies to all companies. Cabinet’s approval is required for effecting any policy change.

ONGC plans to nearly double natural gas production in four years as it invests billions of dollars to produce from newer discoveries. India’s biggest oil and gas producer is investing ₹ 920 billion in 35 major projects which include 14 to bring new finds to production and six to improve recovery from the ageing fields. ONGC is investing over $5 billion in developing oil and gas discoveries in the Krishna Godavari basin block KG-DWN-98/2, which sits next to Reliance Industries’ flagging KG-D6 fields. Also, natural gas pricing is a challenge as the current rate of $2.89/mmBtu is way below $4.5 needed to cover for cost and provide a reasonable return. As on October 1, 2016, ONGC had 577 hydrocarbon discoveries. Most of them were either in production or action had been initiated to monetise them. The roadmap for increasing output addresses monetisation plan of all the discoveries of ONGC, barring about 42 finds which are isolated/far from existing infrastructure, or have very low volumes or are located in difficult areas. ONGC’s output from the currently producing fields is projected to fall from 18.5 mt in the current fiscal to 12.66 mt in 2021-22. This is to be supplemented by about 5.3 mt expected from fields where investment approval has already been given and another 8.45 mt from the fields that are under conceptualisation or investment approval is under process. For natural gas, the output is projected to drop from 19.73 bcm from current fields to 11.9 bcm in 2021-22. The situation is rescued by fields that are under development or conceptualisation that will give 29.65 bcm in 2021-22.

GAIL (India) Ltd will skip medium-term LNG deals for 2018 as it starts getting supplies from its US portfolio from February. GAIL has signed contracts for sourcing up to 5.8 mt of LNG from the US.  The company is also likely to cut its spot purchases once volumes from the United States begin. In 2018, GAIL expects to obtain close to 80 cargoes from the US. The company currently sells close to 35 mcm/d of super-cooled gas, of which close to 17 mcm/d is procured through medium-term and spot purchases. India wants to raise the share of natural gas in its energy mix to 15 percent in the next few years from about 6.5 percent now. But price-sensitive customers in the South Asian nation forced renegotiation of the price of two long-term LNG deals. Pricing of US LNG is linked to a formula but other charges including freight to India add an extra $2-$3/mmBtu leading to GAIL scouting for destination, time and volume swap deals. GAIL has swapped about 30 percent of its US volumes through destination swaps. The company has kept some US volumes for trading, while selling some through time-swap and direct sales in international markets. In March, GAIL signed its first time-swap deal with Swiss trader Gunvor to sell some of its US LNG. It has also sold some of the US volume to Shell. India’s gas demand could rise by about 10 percent in 2018/19 from about 140 mcm/d now as the country expands capacity of power generation and fertiliser production. State-run companies have been asked to boost supply of gas and alternate fuels in the states where use of petcoke and furnace oil is banned to cut emissions.

More than four months after the launch of GST the industry has pitched for inclusion of natural gas in the new indirect tax regime so as to help producers contain cost and aid in moving towards a gas-based economy. Industry body FICCI has said that keeping natural gas out of the GST is causing hardships and having adverse impact on the producers as it is increasing their costs. Currently, crude oil, petrol, diesel, jet fuel or ATF and natural gas are not included in GST, which kicked in from July 1. Hence, while various goods and services procured by the oil and gas industry are subjected to GST, the sale and supply of oil, gas and petroleum products continue to attract earlier taxes like excise duty and VAT. Unlike other industries which can take credit for any tax paid towards furtherance of business, no credits on input GST will be available to the oil and gas industry leading to huge additional indirect tax burden. Currently, gas sales including CNG and piped gas supplies attract lower VAT, ranging from 5 percent to 12 percent and inclusion of natural gas in GST should not result in any large revenue loss, it said. A GST based taxation for the natural gas sector would help the domestic gas producers to contain costs and also help spread use of natural gas which is 40 percent leaner than conventional fuels, it said. The chamber has requested the Centre and states to immediately consider covering natural gas under GST to avoid cascading effect and ensuring that the industries presently operating on natural gas do not get a “raw deal” under GST. Until introduction of GST on natural gas, the producers should get a refund of GST paid on all goods and services used in the exploration and production, it said.

India will save about ₹ 40 billion after it got US energy major Exxon Mobil Corp to lower the price of LNG after the new rates kick-in from January next year. Petronet LNG Ltd in August 2009 signed a 20-year deal to buy 1.44 mt of LNG from Exxon’s share in the Gorgon project in Australia. The deliveries under the contract started early this year. At $50/barrel oil price, Gorgon LNG, whose supplies started in January this year, would have cost $7.25/mmBtu at the port of loading. Adding another $1 for transportation would have led to delivered price of $8.25 in the old contract. In the new formula, Gorgon LNG delivered at Indian port will cost $6.9/mmBtu. India had used its status of Asia’s third largest LNG buyer to renegotiate in 2015 the LNG pricing formula with Qatar’s RasGas to buy the gas at half the original price. Petronet had in late 2015 renegotiated price of the long-term deal to import 7.5 mtpa of LNG from Qatar, helping save ₹ 80 billion. Petronet will buy 1 mt more LNG from Gorgon project as well but the additional volumes would come in after few years. Price renegotiation with RasGas led to saving of $5/mmBtu. Petronet had last year formally sought at least 10 percent cut in price of Gorgon LNG. The 14.5 percent indexation to prevailing oil rates agreed in August 2009 was one of the highest in the world. Petronet said LNG in spot or current market is available at $9.5/mmBtu.  State-owned GAIL, IOC, BPCL and ONGC hold 12.5 percent each in Petronet.

Rest of the World

Global gas supplies currently exceed demand, a situation that could lead to a “crisis” drop in prices similar to what occurred in the crude oil market, Russia said. Threats to global gas prices underscore the importance of long-term supply contracts, in which producers can be assured a stable price over the course of years instead of being subject to the ups and downs of the market the country said. Russia is the world’s second-largest producer of natural gas, behind the US.

CNPC plans to reduce natural gas supplies to industrial users as it expects shortages this winter after millions of residential households were switched to gas for heating under a government program to reduce pollution. CNPC, one of China’s top three gas producers, said it will cut supplies to industrial clients by a range of 3 percent to 10 percent. CNPC expects a 12-percent jump in gas consumption from a year ago because of the residential switch. The company will also try to increase imports from Central Asian countries, such as Kazakhstan. Analysts expect Kazakhstan to supply 1 bcm of gas before the end of the year as part of a supply deal through the Central Asia-China pipeline network operated by CNPC and local partners. CNPC said it can only provide about 76.5 bcm of gas even if it runs its gas fields and LNG terminals at full capacity and fully stocks its underground storage. This is below its expected current demand of 81.3 bcm. CNPC is the first natural gas producer to reduce supplies as China faces a potential supply crisis after the central government switched millions of residents to gas heating rather than coal this winter. Spot Asian gas prices have risen above oil-indexed cargoes as energy providers scramble to avoid a looming winter crunch. Under the new rules, residential users will have priority over industrial users in cases of supply curtailments. CNPC has a working volume of 7.4 bcm at its natural gas storage sites, accounting for 5 percent of its annual sales plan. CNPC’s unit PetroChina operates three LNG import terminals with a combined annual capacity of 43.7 million cubic meters at Dalian in Liaoning province, Caofeidian in Hebei province and Rudong in Jiangsu, although on average these terminals operate at 40 percent of capacity.

China’s domestic prices for LNG topped 7,000 yuan ($1,061)/tonne, highest since at least 2011, as demand soared with millions of homes burning gas for the winter instead of coal. Wholesale LNG prices have gained more than half their value from mid-November, meaning the jump in prices has come less than two weeks into northern China’s heating season. Two LNG dealers in the northern province of Hebei said the price could possibly be a record high as China’s LNG market is much less developed than other commodities, with significant imports of the fuel appearing only over the last five years. Xinkun Gas hauls the liquid fuel in hulking trailers to steel mills and porcelain makers in Tangshan, China’s steel capital east of Beijing. China’s state-owned oil firms are maximising production at domestic gas fields and boosting LNG imports at receiving terminals, although that has not kept the surge in demand from Beijing’s aggressive gas push from outpacing supply.

Venezuelan state-run oil company PDVSA is in contract talks to export natural gas to neighbours Colombia, Trinidad and Tobago, and Aruba. Gas sales could provide a welcome boost to energy revenues for a country suffering acute cash problems and in talks to restructure its debt. Venezuela, which is almost entirely dependent on crude exports, has seen income decline since oil prices crashed in 2014. Colombia used to export gas to Venezuela through a pipeline. That flow would be reversed if an agreement with Colombia is reached on price. Price talks between PDVSA and Colombian state-run energy firm Ecopetrol have taken a long time. The Venezuelan firm modified the pipeline in preparation to pump gas to Colombia. Venezuela has vast offshore gas reserves, but they are mostly underdeveloped, as the OPEC-member country has focused its investment on oil projects. PDVSA does not currently export natural gas. Exports to Trinidad and Tobago and Aruba could not yet start, as there is no infrastructure to get the gas to those countries. If all the contracts are agreed, PDVSA could export more than 610 million cubic feet per day, about 10 percent of Venezuela’s gas output. Venezuela injects most of the natural gas it produces back into oilfields to help maintain pressure and crude output.

Qatar’s Energy Minister said he expects oversupply of LNG in the coming years due to increased production, but the market should tighten after 2025. Qatar, the world’s largest exporter of LNG, is working to increase gas production and LNG exports.

Iraq has hired Japan’s Toyo Engineering to help build a gas pipeline to Kuwait and a related petrochemical plant as Baghdad looks to reduce flaring and finish paying reparations owed for its 1990 invasion of its neighbour. The project, details of which have not been reported before, would allow Kuwait to diversify its gas imports in the wake a political crisis between Gulf states and major supplier Qatar. It would also deal a blow to Royal Dutch Shell, which aimed to be the dominant gas player in Iraq before relations with Baghdad soured following Shell’s exit from large oil projects. The World Bank, which has repeatedly made reducing gas flaring a condition of lending to Baghdad, did not respond to a request for immediate comment. Toyo is proposing to construct a gas pipeline and start deliveries after 2019. Iraq’s gas reserves of 3.7 trillion cubic meters rank as 12th largest in the world but represent only a tenth of those of Iran, the world’s largest. It extracts large quantities of gas together with oil, however, and that gas is currently being flared.

Gas exporting giant Qatar has all but sold out of winter supply after committing its spare output to China and South Korea, a development that could tighten Asia’s gas markets as the peak demand season bites. Doha’s bumper sales will also ring alarm bells for other regions reliant on Qatari LNG such as Europe and may further boost Asian spot prices, which have already surged 55 percent since September, traders said. Despite widespread forecasts of an LNG glut, China’s shift to gas this year as it moved millions of households away from coal to combat smog has lifted its LNG imports by 43 percent and squeezed global gas markets. But some traders are split on the sustainability of the rally, citing weather, crude oil price movements and the degree of residual demand left in China as big unknowns that could potentially dampen prices. Normally Qatar plays the role of swing supplier to global LNG markets, churning out cargoes to cover demand spikes. Qatar’s absence from spot markets may be felt in higher LNG prices which some traders predict may hit three-year highs above $11/mmBtu this winter, from $9.40/mmBtu currently. The shift in sentiment has bulls wondering whether forecasts of global LNG markets re-balancing in the early 2020s may not be wide of the mark given the quickening pace of Chinese consumption growth.

Egypt will stop importing liquefied natural gas in 2018 and may eventually export gas after it starts producing this year at the giant Eni SpA-operated Zohr field off the country’s Mediterranean coast. Zohr’s output will mostly supply the domestic market, and the nation’s two existing gas-liquefaction facilities are large enough to process any available surplus into LNG for international sale in 2019. If Zohr and other gas fields generate enough supplies, Egypt may consider adding a third LNG-exporting terminal. The country expects Zohr to start producing this year at about 350 million cubic feet a day. The government will issue another tender for LNG in early 2018 to cover needs for the second quarter, and it plans to stop importing the fuel by the end of next year.

Egypt exported gas until 2014 but had to forego those sales to meet local demand and because sporadic sabotage attacks on its main pipeline in the Sinai Desert throttled shipments. With Zohr expected to begin producing this year, the North African nation targets re-starting exports in 2019. The field has a potential 850 billion cubic meters of gas in place, according to Eni. The first phase of Zohr’s development is almost finished, with drilling operations of the phase’s wells completed, the oil ministry said. Russia’s state-owned producer Rosneft PJSC closed a deal to acquire 30 percent of the field in October. BP Plc bought a 10 percent stake in Zohr last year. The country has also adopted a flexible gas-pricing formula to encourage investment and boost supply. Egypt previously paid a fixed price of $2.65 per thousand cubic feet. SDX is in talks to price the gas it hopes to start producing at the South Disouq field at $4 per thousand cubic feet.

The governments of Pakistan and Malaysia have signed an intergovernmental agreement on LNG. The LNG supplies will be delivered to Pakistan and will be ensured by the Malaysian company Petronas, which was competing against Gazprom and managed to secure the deal. The Pakistani government has set up Pakistan LNG to secure LNG deals through open competitive biddings as well as through government-to-government arrangements. Pakistan intends to reduce the country’s energy dependence and satisfy the increasing energy demand. It plans to gradually substitute oil imports with imported gas, including in the transport sector, and has set up an LNG import target of 60 mcm per day by 2018. A preliminary agreement with China for the development of a massive LNG export project in Alaska will boost its profile, but does not ensure the $43 billion development will go ahead, analysts said. China’s biggest state oil company, Sinopec, one of its top banks and its sovereign wealth fund agreed early to develop the Alaska LNG export terminal and an 800 mile (1,290 kilometre) pipeline to deliver fuel to China. Alaska LNG, backed by the Alaska Gasline Development Corp with input from North Slope energy producers, envisions a lengthy pipeline from the North Slope to an export terminal in south-central Alaska. With planned output of some 20 million tonnes a year, Alaska LNG would need to sign numerous major offtake deals, likely with customers beyond just China, before it can secure financing for construction, analysts said. US natural gas production growth is expected to surge in 2018, after rising more modestly in 2017, the US EIA said. US dry natural gas production was forecast to rise to 73.45 bcfd in 2017 from 72.85 bcfd in 2016, according to the EIA’s Short Term Energy Outlook. The latest November output projection was a little lower than EIA’s 73.63-bcfd forecast in October and falls short of the record high 74.14 bcfd produced on average in 2015. The EIA also projected natural gas production would rise to 78.90 bcfd in 2018, up from a forecast of 78.49 bcfd issued in October. Total gas consumption in the US is likely to fall slightly in 2017 to 73.06 bcfd from 75.1 bcfd a year earlier. Total consumption is expected to rebound in 2018 to 76.83 bcfd. However, natural gas usage in U.S. homes is expected to grow in both years, rising slightly to 11.90 bcfd in 2017 and climbing to 12.89 the following year.

Pakistan is in LNG supply talks with France, Italy and Spain. IGAs could help Pakistan speed up its ambitious plans to bolster LNG imports as it aims to end the country’s chronic energy shortages. Pakistan opened its second LNG import terminal in Karachi and up to five more terminals are in the works. Islamabad aims to source about 3 mt of LNG per year for the new terminal through intergovernmental deals, or about four cargoes per month. Pakistan’s demand is expected to grow to 30 mt in three years, which would make it a major LNG buyer. It is already one of the fastest-growing LNG markets, attracting interest from producers such as Shell and ExxonMobil and from traders such as Trafigura and Gunvor. Pakistan last year agreed a deal with Qatar to supply 3.75 mtpa for its first LNG terminal and this year in an open tender it awarded Eni a 15-year supply contract. Russia, Malaysia, Turkey and Azerbaijan have all signed IGAs with Pakistan and their companies have begun commercial negotiations. Pakistan expects to sign deals with Indonesia and Oman soon.

Turkmenistan may ship natural gas to Eastern Europe through Russia, state energy firm Turkmengas after Moscow stopped buying gas from the Central Asian nation. Russia’s halt on imports of its energy has effectively left Turkmenistan with China as the only buyer of its gas, straining its economy due to a drop in hard currency revenue. Turkmenistan produces about 70 bcm of gas a year and Russia used to buy up to 40 bcm of that. Last year, however, Turkmen exports were just 37.3 bcm, of which 29.4 bcm went to China.

ONGC: Oil and Natural Gas Corp, RDG: Raageshwari Deep Gas, FY: Financial Year, mscfd: million standard cubic feet a day, boepd: barrels of oil equivalent per day, EOR: enhanced oil recovery, O&G: oil and gas, mt: million tonnes, bcm: billion cubic meters, mcm/d: million cubic meters per day, mmscmd: million metric standard cubic meter per day, KG: Krishna-Godavari, mmBtu: million metric British thermal units, LNG: liquefied natural gas, US: United States, GST: Goods and Services, VAT: Value Added Tax, CNG: compressed natural gas,  ATF: aviation turbine fuel, IOC: Indian Oil Corp, BPCL: Bharat Petroleum Corp Ltd, CNPC: China National Petroleum Corp, OPEC: Organization of the Petroleum Exporting Countries, EIA: Energy Information Administration, bcfd: billion cubic feet per day, mtpa: million metric tonnes per annum, IGAs: Intergovernmental agreements

Courtesy: Energy News Monitor | Volume XIV; Issue 27

Crude Oil: The Problem of Plenty

Lydia Powell, Observer Research Foundation

In the article titled ‘The Shocks of a World of Cheap Oil’ published in the January / February 2000 issue of Foreign Policy, the authors Amy Myers Jaffe and Robert A Manning argued that the shocks of a World of cheap oil could be more damaging than the shocks of a World of expensive oil. At the time the article was published (early 2000s) crude oil prices were $25-$30 per barrel (above $ 100/bbl in today’s dollars) and many observers were beginning say that it could materialise in to a crisis similar to the oil crises of the 1970s. World oil demand, especially Asian oil demand had recovered from the drop suffered during the 1997 currency crisis but supply had fallen on account of low investment. Most observers of the oil market did not see the possibility of change in this scenario of growing demand and dwindling supply. They predicted disaster for oil importing countries as crude oil prices were expected to keep rising to levels not seen before. Geo-political commentators anticipated a significant imbalance in power relations as wealth was transferred from oil importing countries to oil exporting countries which were invariably dominated by countries in the Persian Gulf.

The authors of the article cited above took a contrarian view and argued that the long term trend of low oil prices on account of prolonged surplus in the oil market could destabilise oil producing States ‘especially those in the ellipse stretching from the Persian Gulf to Russia’ as the authors put it. They pointed out that oil reserves (recoverable at prices of the day) had increased to more than a trillion barrels, double the level predicted by the Limits to Growth report for the year 2000. The authors added that if unconventional oil sources such as tar sands and shale oil were included, global oil reserves would touch 4 trillion barrels.

Other arguments that the authors made in the paper to support their prediction of a glut in the oil market included the falling costs of finding and producing oil on account of technological improvements, the emergence of alternative fuels in the transportation segment and the fall in oil required to produce a unit of GDP. One of the most interesting part of the paper is the high probability the authors attached to oil prices staying in the range of $12-$20/bbl (about $ 20-32/bbl in current dollars) over the period 2000-2020 and the impact this could have on oil export dependent countries. Though actual oil prices did not exactly follow these predictions for the first half of the period, the second half appears to be edging close to the levels predicted.

The report by Citibank released last week argues that crude oil prices would fall to $20/bbl over the short term and that OPEC’s hold over oil prices is over. According to the report, the new oil world order is said to depend on a ‘call on shale’ rather than a ‘call on OPEC’ as it used to be. The reason is that with shale oil technologies, oil production had become more like manufacturing in the sense that it got cheaper with better technology.  Unlike traditional resource extraction which was characterised by high upfront costs, long gestation periods and extended periods of production that amounted to inelasticity of supply, shale oil production had low capital costs, very low gestation periods and small production cycles that underpin elasticity of supply.  When oil prices are above $60/bbl more fracking wells will come on line and when oil prices fall below $60/bbl, many wells go offline.

This raises some interesting questions. What led to the problem of too much oil when all along we were anticipating a problem of too little oil? Was it the creation of an industry that thrived on making predictions of the world running out of oil? Was technology developed in response to these ‘end of the world’ predictions? Or is it the new Malthusian error?

There is an eerie sense of accuracy in the author’s geo-political prediction that low oil prices would complicate Russia’s troubled transformation and contribute to the political turmoil in Venezuela. The author’s recommendations, largely addressed to the United States, include a revision of American policy towards oil export dependent countries that it should not be limited to military assistance but include political and social institution building and diversified economic development. Once again some interesting questions could be raised: Were high oil prices just ‘protection money’ being paid to keep oil exporting countries off the backs of the rest of the World? What happens now when technology has wiped out this ‘protection money’?

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 35


Monthly Oil News Commentary: November 2017


India’s crude oil production in September remained flat at 2,920,000 tonnes as compared to the corresponding month a year ago while natural gas output grew 4.74 percent to 2,723 mmscm in the same month. The country’s gross petroleum imports in value terms increased a whopping 21 percent to $7.5 billion in September as compared to the corresponding month a year ago. Cumulatively, gross petroleum import bill increased 17 percent to $43.4 billion in the first six months of 2017-18 as compared to the corresponding period last year on the back of increased international crude oil prices. Oil production dipped due to poor performance of fields under PSC data shows. The growth in natural gas production is attributed to healthy performance of acreages under government-owned ONGC, OIL and fields under PSC, data released by PPAC indicated. On a cumulative basis, the country’s crude oil production in the first six months of 2017-2018 remained almost flat at 18,025,000 tonnes decreasing 0.22 percent as compared to the corresponding period a year ago. Cumulative natural gas production during the period grew 4.38 percent to 16,413 mmscm as compared to the corresponding period a year ago. Government-owned ONGC, responsible for 63.15 percent of country’s crude oil production in September, witnessed a crude output growth of 2.25 percent to 1,844,000 mt in September. Cumulatively, the oil and gas behemoth witnessed a 2.48 percent increase in production to 11,302,000 tonnes in the first six months. The company’s natural gas production witnessed a growth of 5.20 percent to 1,938 mmscm in September as compared to the year ago period. Cumulatively, gas production increased 9.28 percent to 11,675 mmscm in the first six months.

India’s crude oil import bill jumped over 20 percent to $56.25 billion in the first seven months (April-October 2017) of the current financial year and is likely to rise up to $90 billion by March 2018 – a 29 percent increase over last fiscal. The swelling oil bill could further impact the already widening trade deficit and push up inflation. India’s trade deficit widened to its highest in nearly three years in October, government data showed. Higher crude price, coupled with a more than a quarter jump in volumes from a year ago pushed petroleum import bill to $9.2 billion in October. Any further increase in oil bill will add pressure on the country’s trade deficit which widened to $14 billion for the month of October, an increase of 26 percent as compared to the corresponding month a year ago, primarily on the back of a 28 percent increase in oil import bill. Crude oil and products were responsible for 25 percent of the country’s total import bill of $37 billion in the month of October.

Nearly 25 years after ONGC’s prime discovered oilfields were privatised, the oil ministry has identified 11 more producing oil and gas fields of the state-run firm for handing over to private firms to raise output. The ministry is approaching the Cabinet to allow private companies take 60 percent stake in producing oil and gas fields of national oil companies, ONGC and IOC with the view that they would raise production above the baseline estimate. As many as 15 fields – 11 of ONGC and four of OIL – with a cumulative in place reserve of 791.2 mt of crude oil and 333.46 billion cubic meters of gas have been identified. These include Kalok, Ankleshwar, Gandhar and Santhal – the big four oilfields of ONGC in Gujarat. All of these fields are in blocks or areas that were given to the national oil companies on nomination basis and the current policy does not allow private firms taking equity stake in a nomination block.

The oil ministry has asked geo-scientific community to reduce oil and gas import dependency by at least 10%, and ensure energy accessibility as well as affordability for entire spectrum of people. The country ranks third in energy consumption in the world and with the efforts of scientists E&P industry was growing. The sector is a priority of the government and the time was ripe for energy to synergy. Revenue collection increased from ₹1 trillion to ₹ 2 trillion.

OVL has turned its focus to buying stakes in overseas producing oil and gas assets to meet output targets after a delay by Iran in awarding development rights for a gas field. Indian firms led by OVL, the foreign investment arm of ONGC, have been negotiating with Iran for development rights of Farzad B gas field since its discovery in 2008. OVL is targeting production of 60 mt of oil and gas by 2030 from 12.80 mt in 2016/17. Africa, Central Asia and Latin America are listed as preferred regions for acquiring producing assets. India was hoping to get rights to develop Farzad B as the South Asian nation was one of the handful countries that continued to deal with Tehran despite sanctions.  India modified its bid several times to match Tehran’s expectations and terms to get the development rights. Iran has modified its petroleum contract model, ending a decades old buy-back system that barred foreign firms from booking reserves or taking equity stakes. Under new terms Iran wants India to operate the field for 20 years and commit to buy gas for 25 years at prices higher than those proposed by ONGC. Iran’s previous contracts gave investors an assured return of 18 percent. India, the world’s third biggest oil consumer, has told state oil firms to acquire assets overseas to improve energy security. India imports about 80 percent of its crude needs.

The Centre has flagged off a techno-economic feasibility study to build a mega port to cater to the $40 billion west coast refinery and petrochemicals complex being planned by three state-run oil firms. The proposed port will come up at Vijaydurg in Maharashtra’s Sindhudurg district. The proposed port will be developed through a joint venture between Mormugao Port Trust, Mumbai Port Trust and Maharashtra Maritime Board (MMB) – the state government agency tasked with developing ports in Maharashtra. IOC, HPCL and BPCL signed a joint venture in June this year to build one of the world’s largest integrated refinery and petrochemicals complex with a capacity of 60 mt a year. The refinery is expected to start operations in 2022. The proposed refinery is being developed by government oil PSUs and so, a government-run refinery with a government port will be more ideal. This port will have guaranteed cargo and require huge investments.

Indian refiners processed a record 5.2 million bpd of oil in October as the world’s third biggest oil consumer added extra capacity to meet the rising fuel demand, government data showed. The world’s third biggest oil importer sees its diesel and gasoline consumption rising by about two-thirds by 2030. The nation, which produces a fraction of its oil consumption, shipped in a record 4.83 million bpd in September ahead of processing to fuel the additional capacities. India is increasing refining capacity to keep pace with the expected growth in fuel demand as India seeks to boost the manufacturing sector. Recently the country added 170,000 bpd of capacity at the Kochi plant of Bharat Petroleum Corp and Bathinda refinery of HPCL-Mittal Energy. Kochi refinery’s oil processing rose by about 23 percent and that of Bathinda by about a quarter, data showed. Crude refining in October also jumped as several refiners resumed operations after extensive maintenance while IOC deferred a maintenance shutdown of its 300,000 bpd Paradip refinery to meet the fuel demand during festive seasons. Crude oil processing at IOC’s 300,000 bpd coastal Paradip refinery rose by a third. The refinery, commissioned in 2016, resumed full operation earlier this year. Together state-run refiners processed 6.52 percent more oil in October than a year ago, while private refiners used about 13 percent more crude, the data showed.

India’s annual diesel consumption could rise to 150 billion litres by 2030 from 90 billion litres now. Annual gasoline consumption in the world’s third-biggest oil consuming nation could rise to 50 billion litres by 2030 from 30 billion litres now. India currently imports about 80 percent of its oil needs.

IOC began trading crude oil through its Singapore unit, buying a million barrels of Nigerian oil Akpo. IOCL Singapore Pvt Ltd has bought the parcel from Total for December 8-17 loading. The company will gradually increase its workforce in line with transactions from the city state.

India’s state-run MRPL has floated its first tender to buy high-sulphur crude oil from the United States, a tender document showed. The refiner is seeking 1 million barrels of US crude for delivery between February 1-15. The tender will close on November 28 with bids valid up to November 30. Other state refiners such as IOC, HPCL and BPCL have also bought US oil in recent months.

IOC is considering buying Venezuelan crude for the first time in at least six years, in a move that could help the crisis-struck South American nation settle unpaid bills with another state-owned Indian energy firm. The OPEC-member’s economy has collapsed since crude prices plummeted in 2014, forcing it to delay payments for oil services and fuel supplies. Venezuela depends on oil for more than 90 percent of its export revenues. Venezuela’s national oil company PDVSA has missed debt payments to OVL, the foreign investment arm of Indian explorer ONGC for six month and wants to settle $449 million dues using existing and new Indian clients. IOC confirmed that it had received a letter from Venezuela seeking to sell crude. Venezuela has a supply agreement for more than 360,000 bpd with Indian companies. It is not clear, however, whether Venezuela could supply more oil to overseas customers. To meet its highly subsidized domestic needs, PDVSA is said to have been siphoning off crude from cash-paying joint ventures with foreign firms. Currently, only private refiners Reliance Industries and Essar Oil currently buy Venezuelan oil.

Ultra-clean Euro-VI grade petrol and diesel, sourced from refineries in Uttar Pradesh, Madhya Pradesh and Punjab, will be supplied in the national capital from next April in a bid to combat alarming levels of air pollution. To meet Delhi’s consumption of over 900,000 tonnes of petrol and 1,260,000 tonnes of diesel, Mathura refinery in Uttar Pradesh, Bina in Madhya Pradesh and Bhatinda in Punjab will start making Euro-VI grade fuel by mid-January so that supplies to customers start from April 1. Also, storages will have to be separated for BS-VI fuel from the present quality BS-IV fuel. India had in 2015 decided to leapfrog to Euro-VI emission norm compliant petrol and diesel from April 2020, from the Euro-IV grade at present. The deadline for the rest of the country stands. However, for Delhi, which is choking on thick toxic smog, the deadline for introduction of BS-VI – equivalent to Euro-VI grade, was preponed to April 2018. Euro-VI grade fuel contains 10 parts per million (ppm) of sulphur as against 50 ppm in Euro-IV fuels. Oil firms have been asked to examine the possibility of introduction of BS-VI auto fuels in the entire NCR, which includes adjoining cities of Ghaziabad, Noida, Gurgaon and Faridabad, from April 1, 2019. IOC the nation’s biggest oil firm, will source the BS-VI fuel to meet Delhi’s requirement from its Mathura refinery, while HPCL will do so from its joint venture refinery at Bhatinda. BPCL supply the fuel from its Bina refinery. The current BS-IV emission norm was introduced across the country from April 1, 2017. Oil refineries will need to invest ₹ 280 billion in upgrading petrol and diesel quality to meet cleaner fuel specifications by 2020. According to IOC, for petrol engines, one of the most critical specification is Research Octane No. (RON), which has improved from 88 in BS-II to 91. It is at par with regular 91 octane gasoline (petrol) required for Euro VI emission norms.

The PMUY, which has provided more than 30 million LPG connections to poor households over the last one and a half years, has had a multiplier effect on the manufacturers of equipment such as cylinders, pressure regulators, stoves and tubing — most of which fall in the micro, small and medium enterprises (MSME) segment. The number of cylinder makers across the country in 2014-15 was 102, which has gone up to 146 in 2016-17 and this industry’s turnover has surged from ₹ 34.91 billion to ₹ 52.58 billion during the period. Similarly, the number of stove manufacturers has gone up from 39 to 45 and the corresponding increase in turnover has been from ₹ 22.53 billion to ₹ 27.28 billion. Overall, the total turnover of companies manufacturing cylinders, pressure regulators, stoves and connecting tubes has increased by 42% between 2014-15 and 2016-17 from ₹ 62.40 billion to ₹ 88.58 billion. For the six months between April and September, 2017, the combined turnover of these industries stood at ₹ 42.81 billion. The oil ministry launched PMUY in May 2016 to provide subsidised LPG connections to women belonging to the below-poverty-line category. The government is targeting to provide 5 billion LPG connections by May 2019 under the scheme with the ministry of finance providing a support of ₹ 80 billion. The petroleum ministry is in the process of getting Cabinet approval to add another 30 million beneficiaries at an additional cost of ₹ 48 billion. The average life of an LPG cylinder is 20 years wherein it is typically repaired once after 10 years and then five years from then. The three OMCs IOC, HPCL and BPCL, together hold an inventory of 250-300 million LPG cylinders at any point in time as many of the cylinders undergo repair at bottling plants. The increased usage of LPG has also led OMCs to plan expansion of bottling capacity.

The Madhya Pradesh government said it would decide on bringing petroleum products under the GST after considering its impact on the revenue. Finance Ministry admitted that there is a shortfall in tax collection following the introduction of the GST, but added that the situation has been improving. On October 13, the state government reduced the VAT on petrol and diesel by three and five percent, respectively. Besides, the additional cess of ₹ 1.5/litre on diesel was also withdrawn. Diesel had become cheaper in MP compared to neighbouring Rajasthan, Gujarat and Chhattisgarh.  About 34 percent of the commercial tax revenue comes from VAT and other taxes on petroleum products.

The oil ministry remained non-committal on cutting excise duty on petrol and diesel to cushion the rise in retail fuel prices that followed the rally in international oil rates. Petrol and diesel prices have risen by almost ₹ 1.5/litre in the last one month, taking away bulk of gains that accrued from a one-off cut in excise duty cut on the two fuels. The government had in October cut excise duty on petrol and diesel by ₹ 2/litre in a bid to moderate the relentless rise in fuel prices witnessed in the previous three months. After the cut, petrol price came down to ₹ 68.38/litre and diesel to ₹ 56.89/litre in Delhi on October 4. Rates have since climbed to ₹ 69.85/litre for petrol and ₹ 58.31/litre for diesel in the national capital. The excise duty cut cost the government ₹ 260 billion in annual revenue and about ₹ 13,000 billion during the remaining part of the current fiscal year that ends on March 31, 2018. The government had between November 2014 and January 2016 raised excise duty on petrol and diesel on nine occasions to take away gains arising from plummeting global oil prices. In all, duty on petrol was hiked by ₹ 11.77/litre and that on diesel by ` 13.47/litre in those 15 months that helped government’s excise mop-up more than double to ₹ 2420 billion in 2016-17 from ₹ 990 billion in 2014-15. State-owned oil companies in June dumped the 15-year old practice of revising rates on 1st and 16th of every month and instead adopted a dynamic daily price revision to instantly reflect changes in cost. Rates during the first fortnight starting June 16 dropped but have been on the rise since July 4.

More than 2,300,000 customers have received LPG or cooking gas subsidy of ₹ 470 million in their respective Airtel Bank accounts they don’t seem to have opened, prompting the government to intervene even as the top mobile operator denied any wrongdoing. Consumers receive cooking gas subsidy in their bank accounts linked to their unique biometric identity, or Aadhaar. But after several consumers lately complained about not receiving subsidy, it emerged that their subsidy had actually been credited to their respective Airtel Bank accounts. The oil ministry has clarified that the rule is to transfer subsidy to the latest bank account of the beneficiary seeded with their Aadhaar number. Since June 9 this year, more than 2,300,000 gas consumers received over ₹ 470 million of subsidy in more than 4,100,000 transactions in their Airtel Bank accounts, according to a communication sent by a state oil company to NPCI. Of these, about 1,100,000 gas customers belong to IOC while the balance is evenly split between BPCL and HPCL. NPCI maps bank accounts with Aadhaar and oversees retail payments and settlement systems in the country.

Cooking gas or LPG price was hiked by ₹ 4.50/cylinder, the 19th increase in rates since July 2016 when the government decided to eliminate subsidy on it by raising prices every month. Also, jet fuel or ATF price was increased by 2 percent on firming international rates, the fourth straight increase in rates since August, according to price notification posted by state-owned retailers. The price of non-subsidised LPG or market priced cooking gas has been hiked by ₹ 93 to ₹ 742/bottle. At the last revision on October 1 the rate was hiked by ₹ 50 to ₹ 649/ bottle. Subsidised LPG price has been hiked by ₹ 4.50/14.2 kg cylinder to ₹ 495.69. The government last year had asked state-run oil firms to raise prices every month to eliminate all the subsidies by March next year. Since the implementation of the policy of monthly increases from July last year, subsidised LPG rates have gone up by ₹ 76.51/cylinder. A 14.2 kg LPG cylinder was priced at ₹ 419.18 in June 2016. Every household is entitled to 12 cylinders of 14.2 kg each at subsidised rates in a year. Any requirement beyond that is to be purchased at market price. ATF will now cost ₹ 54,143/kilolitre (kl) in Delhi, ₹1,098/kl more than ₹53,045 previously, oil companies said. State-owned oil firms revise rates of LPG and ATF on 1st of every month based on average oil price and foreign exchange rate in the previous month.

The IOC subsidiary in Sri Lanka has dismissed as “mischievous and factually incorrect” the allegations that it was responsible for the fuel shortage in the island nation. The Lanka IOC received flak for the fuel shortage after motorists lined up in long queues at petrol stations. The company denied any responsibility to the ongoing petroleum crisis. The Lanka IOC said it catered to only 16 percent of the Sri Lankan market, while the remaining 84 percent relied on Ceylon Petroleum Corp supplies.

Rest of the World

The global oil market could tighten towards the second half of 2018 if demand remains robust and key producers continue their current policies, IEA said amid concern that OPECs efforts to rebalance the oil market might overshoot by creating a global deficit and spurring a further price rally. The world will still have a surplus of oil by end-March next year, Saudi said, signalling a willingness to extend output cuts.

The US is expected to account for more than 80 percent of global oil production growth in the next 10 years and it will produce 30 percent more gas than Russia by that time IEA said. IEA said the US, whose upstream energy industry has seen a resurgence with the development of fracking technology, would become the “undisputed leader of oil and gas production worldwide.” On the broader market the IEA expected oil markets to rebalance in 2018 if oil demand remained “more or less” as robust as it was now and if OPEC and its allies extended output cuts. OPEC and other producers are expected to extend production cuts beyond a March deadline in a bid to cut oversupply. The Paris-based IEA cut its oil demand forecast in its latest monthly report by 100,000 bpd for this year and next, to an estimated 1.5 million bpd and 1.3 million bpd, respectively. According to OPEC’s own numbers, inventories were 154 million barrels above the five-year average in September. OPEC states have said they want to reduce stocks to their five-year average.

OPEC raised its forecast for demand for its oil in 2018 and said its deal with other producers to cut output was reducing excess oil in storage, potentially pushing the global market into a larger deficit next year. OPEC said in a monthly report it had cut its estimate of 2018 supply from non-OPEC producers and said oil use would grow faster than previously thought due to a stronger-than-expected world economy. OPEC said the world would need 33.42 million bpd of OPEC crude next year, up 360,000 bpd from its previous forecast and marking the fourth consecutive monthly increase in the projection from its first estimate made in July. The projections pointing to a growing 2018 supply deficit could influence debate on how long to maintain the curbs. The 14-country producer group said its oil output in October, as assessed by secondary sources, was below the 2018 demand forecast at 32.59 million bpd, a drop of about 150,000 bpd from September.

Saudi Arabia plans to cut crude exports by 120,000 bpd in December from November, reducing allocations to all regions. Crude exports to the US will be more than 10 percent lower than November levels. The world’s top oil exporter said it planned to ship slightly more than 7 million bpd this month, up from low levels during summer when domestic demand was at its peak. Seasonal drops in domestic crude demand free up more oil for export during the winter months. The OPEC along with other non-member oil producers led by Russia, agreed to cut output by around 1.8 million bpd from Jan. 1 this year until March 2018. Russia, Saudi Arabia, Uzbekistan and Kazakhstan are ready to do more work to reduce global oil inventories. Russia and Saudi Arabia are leading a deal between OPEC and non-OPEC producers to cut global oil production, with the aim of propping up oil prices. First oil has flowed from Brazil’s giant Libra field operated by Petrobras and a consortium that includes Total, Shell and CNPC and CNOOC, the companies said. Libra, which has recoverable volumes estimated by oil regulator ANP at between 8-12 billion barrels, is located in the high-yield region off the coast of Rio de Janeiro. Production began and the FPSO vessel Pioneer of Libra has daily capacity to process up to 50,000 barrels of oil and 4 mcm of gas, Petrobras said. French oil and gas major Total said that the production start-up will generate revenue while collecting data for subsequent development phases of the field. Total estimates the technical cost of production for the field at about $20/barrel. A final investment decision on another FPSO with a capacity of 150,000 barrels per day would be made soon, Total said. A third FPSO with the same capacity would follow soon after. Taiwanese refiner CPC Corp has bought 4 million barrels of US crude via tender for January-February delivery, skipping African oil. Occidental and Unipec sold 2 million barrels each of the WTI Midland crude to CPC. This would be CPC’s second purchase of US crude in two months and replaces Angolan crude which the refiner typically buys. The supplies are part of a large influx of US crude heading to Asia after WTI prices fell to their lowest level against Brent in years. The members of OPEC, Russia and nine other producers are curbing oil output by about 1.8 million bpd until March 2018. They are expected to extend the deal at the Vienna meeting. OPEC said the group was seeking to achieve consensus before the meeting on how long to extend the pact on curbing production.

South Africa wants the national oil companies of its BRICS partners to help build a new 400,000 bpd refinery that will be structured by senior debt and equity. The idea of building a refinery in Africa’s most industrialized economy has been under consideration for almost a decade. The cost of the new refinery was estimated at $10 billion in 2010. South Africa, a net importer of refined oil products, would consider West Africa and the Middle East, including Iran, for potential partners on a new refinery project. The cabinet expects to decide by December whether to build the refinery that has never came to fruition because of a lack of equity partners. Some refinery owners in South Africa wanted to exit the domestic market, citing the high costs of upgrading refineries to meet cleaner fuel specifications. Royal Dutch Shell, BP, Total and Sasol are among the main refinery operators in Africa’s most industrialized country.

China has raised its 2018 crude oil import quota for “non-state trade,” generally meaning independent refiners, by 55 percent over 2017, raising the clout of the independents in the global market after a setback this year. The move took market participants by surprise after Beijing cut the quotas to independents for 2017. The annual quota setting, announced earlier than usual, is a sign the government is relaxing its policies towards the independent refiners after the cuts and after banning them from exporting fuel this year. The commerce ministry said companies can start applying for quotas for 2018 totaling 142.42 mt or about 2.85 million bpd up from 91.73 mt for 2017. The new quotas are equal to about one-third of China’s imports during the first nine months of the year. The ministry said the quotas will be issued in batches, with the first lot based on companies’ actual purchases during the January to October period this year. Companies without any import record will be banned from new quotas for 2018 and those which under-use quotas are required to return the unfinished permits.

ONGC: Oil and Natural Gas Corp, OIL: Oil India Ltd, PPAC: Petroleum Planning & Analysis Cell, mmscm: million metric standard cubic meter, PSC: Production Sharing Contracts, mt: million tonnes, IOC: Indian Oil Corp, E&P: Exploration & Production, OVL: ONGC Videsh Ltd, BPCL: Bharat Petroleum Corp Ltd, HPCL: Hindustan Petroleum Corp Ltd, MRPL: Mangalore Refinery and Petrochemicals Ltd, US: United States, OPEC: Organization of the Petroleum Exporting Countries, PMUY: Pradhan Mantri Ujjwala Yojana, LPG: liquefied petroleum gas, OMCs: Oil Marketing Companies, GST: Goods and Services Tax, MP: Madhya Pradesh, NPCI: National Payments Corp of India, IEA: International Energy Agency, bpd: barrels per day, FPSO: floating production, storage and offloading, WTI: West Texas Intermediate, ATF: aviation turbine fuel, CNPC: China National Petroleum Corp, CNOOC: China National Offshore Oil Corp

Courtesy: Energy News Monitor | Volume XIV; Issue 26

Ramping up Coal Production: Planning Experience

Saumitra Chaudhuri, Former Member, Planning Commission

(Transcript of comments made at the round table ‘Ramping Up Coal Production: Policy Pathways’ organized by the Observer Research Foundation on 18 February 2015 at New Delhi)

  • Since the nationalization of the coal industry in 1971−73 and to date, the industry has been largely run by the State. To that extent the plans and targets set for it and the policy structure designed and run by the administration has been central to the industry. I will dwell on the plans briefly, but not exclusively, for in order to profit from the lessons of the past one must be focused on the future.
  • We have some prime coking coal and some what we call semi-coking coal that we use for blending for use in steel plants and foundries. The deposits are relatively small and the quality mediocre. Ever since the mid-1980s when import of coking coal was first permitted, an increasingly large share of coking coal used by steel plants has been imported. Some steel plants have come up over the last 25 years that use low ash non-coking coal in direct reduction furnaces. However, what is material and relevant to our discussion here is non-coking coal and lignite for use in our power plants and to a much lesser extent in cement and other areas. In 2013-14, we produced 605 million tonnes (MT) of coal & lignite, of which 507 MT was non-coking coal and 44 MT was lignite – a total of 552 MT.
  • It is interesting to note that average production increase of thermal coal & lignite in the decade that followed nationalization was actually a bit lower than in the decade that preceded it – namely 4.0% (1970-71 to 1980-81) and 4.3% (1960-61 to 1970-71) per annum respectively. Output growth picked up in the eighties to an average of 7.8% − with four years posting 9.3 to 10.5% growth. This experience was not repeated in the nineties; average growth slowed to 5.2% per annum and in only two years growth was close to 10%. Some non-coking coal blocks began to be allocated to power and steel producing companies since the mid-nineties, but any augmentation to overall supply materialized in the next decade.
  • Between 2000-01 and 2010-11, average growth picked up slightly to 5.9% − though it collapsed to a decline of (−) 0.2% in 2010-11, to be followed by marginal increases of 1.9% in 2011-12, of 3.9% in 2012-13 and of 0.1% in 2013-14. The average growth in the four-year period 2010-11 to 2013-14 was thus a mere 1.4%.
  • In Apr-Dec 2014, total coal output growth was up at 9.1% (and more for thermal coal). It is likely that for 2014-15 as a whole, total coal output growth will be about 9%, despite the strike last month and associated loss of output; and output growth for thermal coal and lignite will be about 9.5%.
  • In the 4-year period when coal output was held down on account of over-regulation, not only was there lower growth, but the output trajectory was shifted downwards. Had output growth continued at the pace in evidence over the past two decades – that is between1991-92 and 2009-10, we would have produced 90 MT more thermal coal & lignite in 2013-14 than we actually did.
  • Despite the smart pick-up in 2014-15, the “notional” loss of output this year would still be 72 MT. When can we catch up with the old trajectory and reduce this “notional” output loss to zero? If output were to increase at a steady 7.3% per annum every year, then we would catch up with the old trajectory by 2020-21. At 9.3% rate of growth catch-up can be by 2017-18. Somewhere in between would be a satisfactory achievement.
  • Returning to planning. We should remember that the conventional wisdom even in the late nineties a decade after “power-cuts” became a word in every Indian language was that we could at best hope to add 25 GW in each 5-year Plan period. BHEL perhaps reflected this and had a capacity till well into the next decade of 5 GW a year. How much did we really add? In the Seventh Plan (1985-90) 21 GW; in the Eighth Plan (1992-97) 16 GW; in the Ninth Plan (1997-2002) 19 GW and in the Tenth Plan (2002-07) 21 GW. The targets were of course higher – 40 GW in the Tenth Plan. It is only in the Eleventh Plan that targets were set higher (78 GW), actual capacity creation was much higher at 55 GW and new capacity for power equipment manufacture was created. BHEL increased its capacity fourfold to 20 GW. The several joint venture units by L&T/Mitsubishi Heavy Industries, Doosan, BGR-Hitachi, Toshiba-JSW, Alstom-Bharat, Ansaldo-Gammon, Thermax-Babcock and Cethar-Riley for complete BTG and/or boiler an TG sets reportedly aggregate in excess of 40 GW boiler and 35 GW TG (Ministry of Heavy Industries, IEEI Mission Plan 2021-22).
  • Just as power capacity addition and equipment manufacture stepped up on to a new trajectory, coal output decided to step down to a lower one: A most perverse outcome. The Twelfth Plan (2012-17) had slated total new capacity creation of 88.5 GW, of which thermal was to be 72.3 GW. Of this, 49.2 GW or 68% had been completed by the end of January 2015. Of the total increase to capacity the completion rate was lower at 55% on account of large shortfalls in hydro and nuclear. The direction of coal output was in this scenario, a complete shocker. The reasons were diverse – from the institutional weakness of the state-owned monopoly, to regulatory obstruction, to grave charges of financial impropriety and a general state of disorder.
  • The Twelfth Plan has two projections of domestic thermal coal output. In the business-as-usual (BAU) the slated output for non-coking coal was 715 MT by 2016-17; in the “Optimistic” scenario it was 795 MT. Lignite is treated as a separate department. This was against actual coal output of 540 MT in 2011-12. As against the projection of 605 MT in 2013-14, actual output was lower at 560 MT. In 2014-15, as against projection of 635 MT, actual output may be 611 MT. The BAU projection is so safe: you can catch up in one year! The “Optimistic” scenario which posited output of 795 MT in 2016-17 and 1,102 MT in 2021-22 were more realistic as planning objectives and of course were harder to keep pace with. But with a 7.5% steady and sustained output growth from now onwards it is possible to catch up with even the “Optimistic” scenario by 2021-22.
  • The point of course is what will get us on that path and help realize those goals. The problem has been that the Plans for the past four decades were about Coal India and Coal India only: about being offered explanations (aka excuses), deconstructing it with varying zeal, goading and coaxing it and getting caught up in intra-ministerial warfare as in the period end 2009 to 2012.
  • A travesty where goal setting and development of policy frameworks became largely replaced by investing all resources in micro-managing a reluctant monolith caught up in the cross-hairs of another overweening arm of government: all losses are presumed to be non-material and which could co-exist with other “notional” losses of trillions. The consequence was inevitably that that insufficient attention was paid to dealing with institutional and framework issues.
  • The idea that a monolith like Coal India Limited – a holding company with several subsidiaries each of which is a monopoly in their particular geographies – is not out-dated even by the standards of the central public sector is absurd. The several recent initiatives taken in law can create space for private sector units not only to meet its own requirements (captive blocks), but also to compete in the market through merchant mining. The several changes in the law that seek to create this framework are at the present time ordinances that will need parliamentary approval at some point in time.
  • But for the sake of Coal India a useful step would be to de-merge the several constituent companies – BCCL, ECL, CCL, WCL, NCL, MCL, SECL and NECL – and leave them to perform on their own and in friendly  competition with each other. It will do wonders. A problem with having such a colossus is that each of its several parts observes the first dharma of a joint family – covering up for their sins, severally and jointly. Each one of these companies has large reserves and can define and face up to their individual corporate challenges. The problems that enterprises face must be solved in the regular course of affairs. They should not routinely migrate to the very top for resolution. The successor companies formed as a result of the de-merger can also tie up in joint venture or other associations with Indian and foreign companies for mine development and service facilities. Without doubt the process would get much simplified in a competitive framework.
  • Then there is the issue of working on coal deposits at greater depths. The clear preference for open-cast or what used to be called “strip mining” once has limitations for extracting coal at greater depths. There seems to be reluctance for underground mechanized mines. But that is the obvious solution for working coal at greater depths, for producing better coal and working in areas that are not suitable for open-cast operations for surface reasons – be it forest cover or cultivated fields and habitation. The “fire zone” at Jharia has remained unresolved even 50 years after its identification and the first “plans” to deal with the problem. Bringing appropriate technologies to bear – be it in mechanized underground mining where conventional long-wall equipment has reportedly found to be not suitable to our seams or with raging underground fires that consume millions of tonnes of good quality coal each year or for that matter to identify and develop coal bed methane (CBM) resources need institutional change. The patch work that we have been doing is simply inadequate.
  • Finally, a word on coal washeries. The freight composition of Indian Railways is 47% coal by tonnage and 44% by Net Tonne Kilometres. Of this 40−45% is mineral content, i.e. ash or non-coal. Moving washed coal with half of the mineral content/ash can free up 20% of the railway’s freight carrying capacity besides improving performance at the power house. The efficiency gains are enormous. However, Indian coals wash poorly. With a target clean coal ash content of 20% we will get 30 to 40% of rejects, which contain 20−35% coal. Of course, the rejects will be less if the target ash drop is shallow, but then the logistical and other economics will work differently. The objective should be to create a framework so that these choices are made on a commercial and rational basis. In any case, we must not waste the coal contained in the rejects or store them in towering heaps that smoke in forbidding desolation. It can be used in fluidized bed furnaces for steam and power generation.

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Courtesy: Energy News Monitor | Volume XI; Issue 36


Monthly Non-Fossil Fuels News Commentary: October – November 2017


Indian power company NHPC Ltd could bid for a $2.5 billion hydropower project in Nepal after Kathmandu cancelled a deal with China Gezhouba Group Corp. China and India jostle for influence over infrastructure projects in Nepal and the deal with China was scrapped after it was criticised for being handed to the company without any competitive bidding. NHPC could look at developing what will be the country’s biggest hydropower plant. Among other projects in Nepal, a 750 MW project is to be built on the western part of the country by China’s state-owned Three Gorges International Corp, while two Indian companies – GMR Group and Satluj Jal Vidyut Nigam Ltd – are set to build one 900 MW hydropower plant each, mainly to be exported to India.

Power and Renewable Energy Minister R K Singh said India must encourage development of hydro power projects as they help in providing inexpensive power in the long-term and are ideal for meeting peaking load demand. Singh was speaking at the meeting of the Consultative Committee attached to his ministries in Guwahati. The meeting reviewed the functioning of NHPC and implementation of the government’s Solar Rooftop Programme and the Solar Pumps Programme. During the meeting, NHPC gave a presentation on the company’s areas of operation, portfolio of projects, performance on financial parameters, diversification into thermal and renewables and the way forward. NHPC informed the committee that NHPC is commissioning 22 projects of 6,691.2 MW capacity and is engaged in 25 projects of 14,000.5 MW capacity which are under various stages of development involving hydro, solar and thermal projects. Also, 14 projects of 9,167.5 MW are at various stages of clearances. NHPC has expanded its objective of developing renewable source of energy by commissioning 50 MW wind project in Jaisalmer, Rajasthan. The committee was also informed that 2,363 MWp solar rooftop systems have been sanctioned and about 810 MWp aggregate capacity projects have been installed in the country so far. The ministry said it is in the process of formulating a new scheme for solar pumps to promote stand-alone solar off-grid pumps with an objective to replace existing diesel pump sets. Similarly, a new scheme for solarisation of grid-connected solar pumps is also being formulated for areas where agriculture power feed is separated.

Restarting of the second 1,000 MW nuclear power unit at Kudankulam belonging to Nuclear Power Corp of India Ltd is expected to happen during November second week.  Some of the equipment for the upcoming third and fourth units at Kudankulam has arrived from Russia. The mega nuclear power plant was shut down on August 4, due to hydrogen concentration in the stator. Kudankulam in Tirunelveli district has two 1,000 MW nuclear power plants, built with Russian equipment. Two more units — third and fourth — of similar size are being built at Kudankulam. Construction work is going on for the third and fourth units.

Reliance Infrastructure is slated to win a ₹ 10 billion order from NPCIL after emerging as the lowest bidder for an engineering and construction contract for the Kudankulam plant. NPCIL opened bids for the engineering, procurement and construction tenders related to the third and fourth units of 1,000 MW each of the Kudankulam nuclear power project. Reliance Infra was the lowest bidder, beating Larsen & Toubro and Tata Projects. The projects are scheduled to be completed in 56 months. They entail design, engineering, procurement, manufacture, supply, erection and construction, testing, commissioning, handing over and performance guarantee of common services, systems, structures and components for the plant in Tamil Nadu. India and the former Soviet Union agreed in 1998 to set up the Kudankulam Nuclear Power Project with six units of 1,000 MW each. So far, two units have been commissioned, one in 2013 and the other in 2016. India is building the third and fourth units. India and Russia signed a pact in June for two nuclear reactors for the fifth and sixth phase of the Kudankulam plant, which is estimated to cost ₹ 500 billion.

In a bid to push nuclear power development in India, the state-run ONGC has submitted a plan to collaborate with the NPCIL for setting up reactors, Minister of State in the Prime Minister’s Office Jitendra Singh said. The government has recently amended the Atomic Energy Act 1962 to enable the NPCIL to form joint ventures with public sector undertakings in order to meet the high cost of setting up nuclear plants. Earlier this year, the government approved the construction 10 indigenous pressurised heavy water nuclear reactors with a total capacity of 7,000 MW. Each of the reactors would have a capacity of 700 MW. He also said that the Centre is currently working with various state governments to sensitise about the additional uses of nuclear energy in fields other than electricity like in irradiation of agriculture products, medicine, among others. He also stressed the need for a vast sensitisation programme to remove misconceptions about the health and safety aspects of nuclear power.

The India is on track to catalyse $200-300 billion of new investment in its renewable energy infrastructure in the next decade with global capital inflows playing an increasingly crucial role, according to the IEEFA. At present, India relies on thermal power generation for 80 percent of its electricity, while hydro supplies a significant 10 percent and renewables just seven percent. However, India has set an ambitious but achievable national target of 275 GW of renewable capacity installed by 2027.

The tipping point may have been 2016-17, when the net thermal capacity plummeted and renewable installs more than doubled, according to the report “Indian electricity sector transformation” published by the IEEFA. The report examines the rapid transformation in India’s electricity market, showing how renewable energy and energy efficiency measures can help the country minimise the growth of coal-fired electric generation. Electricity demand in India is expected to double over the coming decade, and how this electricity will be generated is important for both India and the world. Clearly India can look forward to further renewable energy tariff reductions medium term, the report said. While renewables are expected to surge, IEEFA forecasts that net thermal power capacity additions are likely to remain below five GW annually in the next decade, held in check by increased retirements of highly polluting, end-of-life sub-critical coal-fired power plants.

The bidding activity for wind and solar energy projects has slowed down in the current calendar year in terms of awarded project capacity, research and ratings agency ICRA said. The solar project capacity awarded in 2017 stood at 3.75 GW by October end as against 7.2 GW in the corresponding period of 2016. ICRA said state utilities are preferring reverse auction for wind projects owing to lower tariffs than feed-in tariffs approved by State Electricity Regulatory Commissions varying from ₹ 3.74/kWh to ₹ 5.76/kWh. Solar power tariffs too have come down to ₹ 2.44/kWh in May 2017 for Bhadla solar park in Rajasthan. The agency also said the recent increase of around 15 percent (or 6-7 cents per watt) in imported PV module prices, if sustained, could have an adverse impact on the viability of projects with tariffs lower than ₹ 3.5/kWh. The slowdown in the bidding activity for solar projects comes on the back of GST roll-out from July 2017, upward pressure on PV module prices, and finalization of new bidding guidelines for award of solar projects. India requires 63 GW of additional renewable energy through 2022. Within this, ICRA estimates the share of wind and solar energy capacity addition requirement to be at least 35 percent and 55 percent, respectively.

India and the World Bank signed a $100 million loan and grant agreement to help the country increase its solar power generation capacity. The loan for “Shared Infrastructure for Solar Parks Project” would go towards financing solar parks in the country, the finance ministry said. The funding has two components: a $75 million loan from the International Bank for Reconstruction and Development, which has a five-year grace period and a maturity of 19 years, and a $23-million loan from the CTF with a 10-year grace period, and a maturity of 40 years. The second component of $2 million is an interest-free CTF grant. According to the World Bank, the first two solar parks are in Rewa and Mandsaur districts of Madhya Pradesh with targeted installed capacities of 750 MW and 250 MW. Other states where potential solar parks could be supported under this project are in Odisha, Chhattisgarh and Haryana.

Solar developers are up in arms over Tamil Nadu’s decision not to pay for power they produce by achieving higher efficiencies, which they claim has already cost them over ₹ 1 billion. In a memorandum to the TANGEDCO, the National Solar Energy Federation of India has protested its decision not to pay for the excess power generated by any solar plant which exceeds a CUF of 19%. CUF is the ratio of the actual output from a solar plant to the maximum possible output from it under ideal conditions. Most solar plants in India achieve an average CUF of 15-19%, depending on the quality of the plant and the strength of the solar radiation, but have on occasions, especially in sunshine-rich states like Rajasthan, crossed 20%. Tamil Nadu began conducting solar auctions only in mid-2016 before which solar tariffs were fixed by TNERC. The first TNERC order, in September 2014, set the tariff at ₹ 7.01/kWh while the second, in March 2016, lowered it to ₹ 5.10/kWh. All the 1600 MW odd of solar projects currently supplying power to TANGEDCO do so at tariffs fixed by TNERC, since the projects won through auctions have yet to be completed. They are paid either ₹ 7.01/kWh ₹ 5.10/kWh depending on whether they were commissioned before March 2016 or after. While passing its orders, TNERC had also set down the parameters it used to arrive at the tariff, and assigned estimated values to each parameter. These included capital cost, operation and maintenance cost, interest on working capital, depreciation and many more, including the CUF expected. In both the orders, it estimated the CUF at 19%. TANGEDCO has interpreted this to mean that power produced in excess of a CUF of 19% will not be paid for.

MNRE has expressed hope that developed nations would earmark certain proportion of their overseas development assistance for solar energy projects in developing countries. Multilateral Development Banks and other financial institutions provide wholehearted support for solar projects through low cost finance.

Karnataka government ordered the state’s electricity regulator to call back its September decision to cut wind power tariffs and approve all power purchase agreements with wind developers signed before March 31, 2016, the latter has yet to officially respond. KERC may ignore the said order as it believes it overstepped the government’s jurisdiction. The government order, passed on October 27, had invoked the rarely used Section 108 of the Electricity Act to insist that wind developers whose power purchase agreements were signed in 2016-17, should be paid ₹ 4.50/kWh and not ₹ 3.74/kWh as KERC had laid down in September.

India’s massive effort towards renewable energy has resulted in considerable drop in solar price and the country now believes that the solar power is cheaper than coal without subsidy, US lawmakers have been told during the hearing on Energy and International Development. They were told that India’s effort in renewable energy there has been a considerable drop in solar price.

Several solar projects in India are facing delays and inflated costs as customs officials have blocked more than 900 containers of panel shipments for more than a month by demanding higher import duties. Officials clearing import shipments at the Port of Chennai in South India are classifying solar panels as motors, which attract 7.5 percent import duty as opposed to zero on solar modules, A 30 MW shipment of Hero Future was cleared after paying higher duties.

Though India was a major inspiration behind the formation of the Gurugram-headquartered International Solar Alliance, the government’s earlier thrust on renewable energy seems to have abated, stakeholders said. One indicator was the government’s emphasis on coal-fired power plants in its latest Economic Survey brought about by the finance ministry. Having first announced that solar would be in the 18 percent tax slab, the GST Council later lowered the rate and clarified that all solar equipment and parts would attract five percent GST. Solar was previously in the exempt category. Besides, unlike the equipment makers, solar power developers like SunSource cannot avail the benefit of input credit for the tax paid under GST. The India sales head of Chinese module manufacturing giant Trinasolar, spoke of the lack of clarity surrounding smaller components such as cables, meters and the steel structures that go into a solar project. Norwegian solar panel multinational REC said anti-dumping measures recommended three years earlier had been rejected by the finance ministry on the ground that the local industry lacked the capacity to meet the government’s target of achieving 100 GW solar capacity by 2022. Few companies in India are currently manufacturing solar cells, according to Trinasolar, which makes the largest cumulative shipments worldwide, and has supplied equipment for 3 GW capacity in India. The solar stakeholders said that with the sharp fall in solar and wind tariffs, as well as in equipment costs, government incentives had dried up.

SBI announced the sanction of loans worth ₹ 23.17 billion in collaboration with the World Bank to finance grid-connected solar rooftop projects in the country. SBI said that it has availed line of credit facilities worth $625 million from World Bank for onward lending to viable solar rooftop projects. SBI said the loans are intended for developers and end-users for installation of rooftop solar systems on the rooftops of commercial, institutional and industrial buildings. The seven companies sanctioned loans are JSW Energy, Hinduja Renewables, Tata Renewable Energy, Adani Group, Azure Power, Cleantech Solar and Hero Solar Energy. SBI has so far sanctioned 43 projects with aggregate credit facilities of ₹ 27.66 billion under the programme, which would add 695 MW of solar rooftop capacity to the grid. The bank has so far drawn-down over 50 percent of the line credit and the remaining facilities are expected to be used in the next 18 months. So far, the SBI has lent a total of ₹ 120 billion to solar energy projects, while there are hardly any bad loans-related concerns in this sector.

The government gave a call to start-ups run by the city youth to initiate a clean cooking movement by tapping the huge market potential of solar energy, saying they would get blessings of women from the poor sections of society. Prime Minister Narendra Modi said in the last 35 years, governments had spent ₹ 40 billion on renewable energy but within three years of his government assuming office, nearly ₹ 110 billion had been spent. By 2030, India aimed to address 40 percent of its power needs by means of renewable energy. The government’s aim is to produce 175 GW power by 2022. LED bulbs which earlier cost more than ₹ 350 were now available for ₹ 40 to ₹ 45 under the Ujala scheme. More than 27 billion LED bulbs had been distributed so far, he said, adding that through this scheme the middle class had been able to save ₹ 70 billion. The government had distributed more than 30 million gas connections to rural women which had not only made a positive difference in their lives, but also contributed to a cleaner environment.

Rest of the World

China’s first offshore nuclear reactor is set to be completed soon, engineers involved in the project said, bolstering Beijing’s maritime ambitions and stoking concerns about the potential use of atomic power in disputed island territories. Beijing hopes offshore reactors will not only help win new markets, but also support state ambitions to become a “strong maritime power” by providing reliable electricity to oil and gas rigs as well as remote South China Sea islands. CSIC said the technology was “mature” and the first demonstration project would be deployed soon at drilling platforms in northern China’s Bohai Sea. The demonstration project is being developed by a research team established by CSIC, China National Offshore Oil Corp and two reactor builders, China National Nuclear Corp and China General Nuclear Power. China has urged nuclear firms to develop technologies that will help boost domestic capacity and win projects abroad  Floating reactors also served a wider political goal to strengthen China’s maritime presence.

The French government has postponed a long-held target to reduce the share of nuclear energy in the country’s power production after grid operator RTE warned it risked supply shortages after 2020 and could miss a goal to curb carbon emissions. It is believed that it was not realistic to cut nuclear energy’s share of electricity production to 50 percent by 2025 from 75 percent now and that doing so in a hurry would increase France’s CO2 emissions, endanger the security of power supply and put jobs at risk. The government would be working towards a 2030 to 2035 timeframe.  While there was a delay, the government would in a year’s time have a clear programme on which reactors to close and when. In 2015, the previous government of Socialist Francois Hollande passed an energy transition law setting out the 50 percent target by 2025. But Hollande took no concrete steps towards closing any reactors. Centrist President Emmanuel Macron, elected in May, had promised to keep the target and Hulot, France’s best-known environmentalist, said in July it might have to close up to 17 of its 58 reactors by 2025 to achieve it. RTE said in its 2017-2035 Electricity Outlook that if France went ahead with plans to simultaneously shut down four 40-year-old nuclear reactors and all its coal-fired plants as planned, there could be risks of power supply shortages. For this winter, RTE said electricity demand was expected to be stable, although unplanned nuclear reactor outages and a prolonged cold spell could squeeze supply. Concerns that nuclear-reliant France could face tight supplies similar to last year have contributed to wholesale power prices touching new highs in recent weeks, as utility EDF announced delays in the restart of several reactors for safety and regulatory reasons. France would then have to postpone the closure of coal-fired power plants and would have to build 11 GW of new gas-fired capacity, boosting CO2 emissions. Under one of the four scenarios, France may cut nuclear capacity by 14.5 GW and reach 50% of nuclear in the power mix by 2030, i.e. five years later than planned. The government has reaffirmed it remains committed to reducing nuclear energy but no new deadline has been set so far.

Pakistan plans to build at least three to four big reactors as it targets nuclear power capacity of 8,800 MW by 2030, Muhammad Naeem, Chairman of the Pakistan Atomic Energy Commission, said. Pakistan has five small reactors in operation with combined capacity of just over 1300 MW. The last one in the four-reactor Chashma plant in Punjab province, built by China National Nuclear Corp, went into operation in September this year. It is also building two Chinese Hualong One reactors with a capacity of 1100 MW each near the port city of Karachi. These two new reactors are now 60 percent and 40 percent complete respectively and should become operational in 2020 and 2021. Pakistan is now also in the final stages of awarding contracts for an eighth nuclear reactor with 1100 MW capacity which would take the country’s total nuclear capacity to about 5,000 MW when it is finished. Pakistan’s five operating reactors – including a tiny 125 MW Canadian-built reactor in Karachi in operation since 1972 – generate just five percent of the country’s electricity, with the rest coming from oil, gas and some hydropower. With about one quarter of Pakistan’s population having no access to electricity, the government said late last year that it wants to boost nuclear capacity to 8,800 MW, or about 20 percent of power generation capacity, by 2030. Naeem said Pakistan is looking at building at least three to four more big nuclear reactors before 2030 in order to reach that target.

China aims to prevent power generated by its renewable energy sector being wasted by 2020, the country’s NEA said. Power from wind, solar and hydro plants is often wasted as there is not enough transmission capacity to absorb it, leading to high curtailment rates, especially in north-western China. The NEA said that the utilization rate of hydro-power plants in the south-western provinces of Yunnan and Sichuan should reach around 90 percent by 2017. It expects the wind power curtailment rate to drop to about 30 percent in the north-western provinces of Gansu and Xinjiang and to around 20 percent in the north-eastern region of Jilin, Heilongjiang and Inner Mongolia in 2017. Solar power waste in Gansu and Xinjiang provinces should be controlled below around 20 percent and in Shaanxi and Qinghai to below 10 percent this year, it said. Power generated from wind and solar power plants in other regions across the country will have to meet the 2017 targets set by the NEA last year, it said. China has vowed to raise the portion of its renewable and non-fossil fuel power consumption to 15 percent of total energy mix by 2020 and 20 percent by 2030. It also said that it will promote the power trade market and improve its cross-region power transmission capacity to boost renewable energy consumption and cut its coal dependence.

Nepal has scrapped a $2.5 billion deal with China Gezhouba Group Corp to build the country’s biggest hydropower plant, citing lapses in the award process. Nepal’s rivers, cascading from the snow-capped Himalayas, have vast, untapped potential for hydropower generation, but a lack of funds and technology has made Nepal lean on neighbour India to meet annual demand of 1,400 MW. Kathmandu has cleared a 750 MW project to be built on the West Seti River in the western part of the country by China’s Three Gorges International Corp. It has also permitted two Indian companies – GMR Group and Satluj Jal Vidyut Nigam Ltd – to build one hydropower plant each, both capable of generating 900 MW of power each, mainly to be exported to India.

OPEC said growth in global oil demand will steadily lessen from an annual average of 1.3 million barrels a day between 2016 and 2020, to 300,000 barrels a day by 2035-2040. But it said fossil fuels will remain the main energy source decades from now. The report by the 14-nation OPEC said that the use of fossil fuels – 81 percent of the global energy mix in 2015 – will decline by 2040.

The world’s largest wind turbine makers said a proposed Republican tax bill that would cut support for the industry in the US would put its businesses and future investment at risk, in a rare public criticism of government proposals. Equipment makers operating in the world’s second-largest wind turbine market have relied upon so-called production tax credits agreed in 2015. Shares in Denmark’s Vestas, the world’s largest maker of wind turbines fell as much as 12 percent, due to its large exposure to the US market, where it overtook GE last year in installed capacity. The tax credit scheme was considered critical to enabling wind projects to compete with fossil fuel plants and the wind energy industry has said the proposed cuts put $50 billion in planned investment at risk. The planned legislative step comes after long-standing industry concerns that Trump might curb support for renewable energy to promote coal and other fossil fuels instead.

One of the world’s biggest oil companies is working on hundreds of low-carbon energy projects, from algae engineered to bloom into biofuels and cells that turn emissions into electricity. The work by Exxon Mobil Corp includes research on environmentally-friendly technologies in five to 10 key areas. While any commercial breakthrough is at least a decade away, Exxon’s support for clean energy suggests the world’s most valuable publicly-traded oil company is looking toward the possibility of a future where fossil fuels are less dominant. While Exxon has discussed some of its research before and runs advertisements about its work in algae, the remarks from Exxon are the first indication of the breadth of the oil company’s interests in alternative energies. It’s part of the $1 billion a year Exxon spends on research worldwide and the $8 billion it has spent since 2000 researching, developing and deploying low-carbon technologies. Exxon didn’t disclose the exact amount it’s spending on the green technologies. The broader investments it has made since the beginning of the century also include things like managing methane emissions from oil wells, on co-generation and on making its plants more efficient. The company joins a growing list of oil majors hedging against the wider adoption of renewables, which could displace some 8 million bpd.

South Korea’s trade ministry said it may consider filing a complaint with the WTO in response to US solar panel import restrictions. The ministry said that it will take all available measures and weigh the possibility of taking the case to the WTO once a detailed report from the US ITC is released on November 13. The move came as the ITC made three different recommendations for restricting solar cell and panel imports including an immediate 35 percent tariff on all imported panels. Last year, South Korean solar power equipment manufacturers including Hanwha Q CELLS Co Ltd exported about $1.3 billion worth of solar cells and modules to the US, making up 15.6 percent of the US solar market, the ministry said.

Korean companies will bid to take part in Saudi Arabia’s project to build nuclear power plants. Saudi Arabia is considering building 17.6 GW of nuclear-powered electricity generation capacity by 2032 and has sent a request for information to international suppliers to build two plants, a first step towards a formal tendering competition. A consortium led by Korea Electric Power Corp is building four nuclear reactors for Saudi neighbour the United Arab Emirates.

Nine US senators from states that have oil refineries sent a letter to President Donald Trump urging changes to the country’s biofuels policy and asking for a meeting to discuss the issue. The letter reflects growing tensions between refiners that oppose the US Renewable Fuel Standard – a law requiring them to blend increasing amounts of ethanol into the nation’s fuel each year – and the Midwest corn lobby that supports it. The Trump administration bowed to rising pressure from Midwest lawmakers assuring them in letters and phone calls that it would ditch proposals, supported by the refining industry, to overhaul the biofuels policy. The senators said that decision could cost jobs. The Renewable Fuel Standard was implemented by former President George W. Bush in 2005 as a way to support farmers, reduce imports and combat climate change. The oil industry has opposed the regulation, mainly because the increasing biofuels volume mandates cut into their petroleum-based fuel market share. A number of independent refiners, like Valero Energy Corp, CVR Energy and PBF Energy are also vocally opposed to the regulation’s requirement that refiners blend the biofuels or purchase credits from rivals that do – which they say costs them hundreds of millions of dollars each year. The EPA said that it did not believe shifting the blending requirement off refiners was appropriate. The EPA also jettisoned a proposal to cut biofuels volumes mandates, and another to count ethanol exports against those mandates.

RE: Renewable Energy, MW: megawatt, GW: gigawatt, MWp: megawatt peak, NPCIL: Nuclear Power Corp of India Ltd, ONGC: Oil and Natural Gas Corp, IEEFA: Institute for Energy Economics and Financial Analysis, kWh: kilowatt hour, PV: photovoltaic, GST: Goods and Services Tax, CTF: Clean Technology Fund, TANGEDCO: Tamil Nadu Generation and Distribution Corp, CUF: capacity utilisation factor, TNERC: Tamil Nadu Electricity Regulatory Commission, KERC: Karnataka Electricity Regulatory Commission, US: United States, SBI: State Bank of India,  LED: light emitting diode, MNRE: Ministry of New and Renewable Energy, CSIC: China Shipbuilding Industry Corp, CNNC: China National Nuclear Corp, NEA: National Energy Administration, OPEC: Organization of the Petroleum Exporting Countries, WTO: World Trade Organization, ITC: International Trade Commission, EPA: Environmental Protection Agency

Courtesy: Energy News Monitor | Volume XIV; Issue 25