Lydia Powell, Observer Research Foundation

As the world’s largest energy consumer and carbon emitter, China’s energy choices were expected to be at the centre of the global transition to a low carbon economy.  China has exceeded expectations as the stylised facts below reveal.

China is expected to invest about $360 billion in renewable energy by 2020 and terminate plans to build 85 coal fired power plants.  China’s investment of about $78 billion in renewable energy in 2016 was the largest in the world accounting for 32 percent of global investment in renewable energy.  The EU as a whole invested about  $59 billion in renewable energy and the USA about $46 billion.  China’s investment in research and development of renewable energy at about $2 billion in 2016 was close to the $2.2 billion invested by the EU, which leads the ideological narrative on the significance of a global low carbon transition.

China is expected to install 36 percent of all global hydroelectric capacity, 40 percent of all wind capacity and 36 percent of all solar capacity between 2015 and 2021.  China will also account for 54 percent of growth in nuclear capacity by 2040 and surpass the United States as the country with the largest nuclear power generating capacity by 2030.  China’s state power grid corporation, which is the largest in the World, plans to develop a global grid that draws on wind and solar power from around the world.  Five of the world’s six largest solar module manufacturers are in China and Chinese companies rank among the largest wind turbine manufacturers.  Chinese companies account for 90 percent of the production of lithium which is critical for manufacture of storage batteries. Batteries are not only critical for managing intermittency of electricity from renewable sources but also power electric vehicles which are seen as the future of transportation.  Chinese firms also account for over 72 percent of the production of rare earth minerals that are vital for the manufacture of renewable energy technologies.  China plans to reduce energy intensity by 15 percent in its 13th five year plan from 2016 to 2020.  China is the only developing country that has implemented efficiency standards for automobiles. Out of the 8.1 million supposedly green energy jobs available globally 3.1 million are in China.

These figures could intimidate even the uninitiated, but when seen in the context of China’s relative size and its level of industrialisation, China’s investments and initiatives may be interpreted as rational responses to domestic compulsions rather than a calculated effort towards global dominance of the future energy landscape.  China’s dominance in low carbon technologies is by no means an exception to the trend of Chinese dominance in some other emerging sectors such as mobile communication, e-commerce and quantum cryptography.

China’s pace of industrialisation was unprecedented but China’s path was much faster and far less energy intensive than that of Western nations.  While nineteenth century United States and Briton needed 50 years to double their real income, China achieved the same feat in 9 years as it was able to use less capital per worker leveraged by western technology and knowhow.  China’s demand for thermal coal (and other vital natural resources) grew faster in 19 years than the entire world’s demand grew in the previous 40 years.  Though China’s economy increased 18 fold from 1980-2010, its energy consumption increased only five fold.  Energy intensity per unit GDP declined by 70 percent in this period.

More recently, China’s transition from an investment and manufacturing led economy to a services and consumption led economy has lowered demand growth for energy and reduced energy intensity of its economy substantially.  China’s working age population has been on the decline since 2012 and is forecast to fall by 23 percent by 2050 which means that dependence on abundant labour for low end manufacturing is no longer possible.  Increasing productivity is the only option for China which means improving energy efficiency and lowering energy consumption by moving away from low end manufacturing.  In 2016, China’s service sector contributed 52 percent of GDP and domestic consumption contributed 60 percent of GDP growth.  China’s changing growth model along with global demographic and consumption trends are accelerating the low carbon energy transition.

Although the low carbon transition is described as a phenomenon at the level of primary energy use its driver is energy consumers and their preference for quality energy sources.  The first major global energy transition that began with the industrial revolution was a quantitative and qualitative transition from almost no external energy to abundant external energy.  In the United Kingdom which was the first to make this transition from traditional biomass to fossil fuels, the shift involved the development of a wide range of technologies at the supply and demand end between 1500 and the early 1900s.  The second significant transition that started in the early 1900s when the share of coal in global energy supply had peaked.  The diffusion of steam engines, internal combustion engines and electric motors drove quantitative changes in the supply and relative shares of fossil fuels.  The share of oil and gas increased at the expense of coal but it was not the scarcity of coal that led to the introduction of more expensive oil.  It was technological shifts at the demand end with consumers paying attention to convenience and cleanliness that drove the shift towards the delivery of refined petroleum and grid based energy forms (natural gas and electricity) even though their cost to consumers was above those of alternatives.  The factors driving China’s low carbon transition are no different.  The diffusion of technologies for mobile communication and transport that require stored electricity is driving demand for batteries which in turn is reducing the cost of using intermittent sources of renewable energy.

This transition to a low carbon economy is path dependent as initial conditions such as resource availability and other geographic, climatic, economic, social and institutional factors leading to differences in spatial structures, infrastructure and consumption patterns affect the pace of transition.  Initial conditions influence the level and type of technologies used both at the consumer end and within the energy sector that are costly to change quickly.  China’s initial conditions favour the transition to a low carbon economy.

Unlike the era dependent on fossil fuels that required natural endowment of resources, the transition to low carbon energy sources requires a knowledge intensive industrial production base and a large energy consumption base.  China has both. Relatively higher income levels of energy consumers, especially those in urban areas in China also favours a quality transition for energy use.  The fate of renewable energy sources crucially depends on the power sector because electricity is still the main vector for renewable energy.  China’s spatial power densities are particularly high, especially in urban areas due to the twin influences of high population density and high per person energy use.  The correlation between declining carbon intensities and rising incomes is well known.    Low carbon intensities mean that more primary energy must be mobilized for conversion to high quality fuels such as electricity even if it means incurring the economic costs and the inevitable conversion losses. Conversion deepening and increasing conversion losses of the global energy system is not necessarily unique to the current low carbon energy transition but China is pursuing the transition at relatively low levels of per person incomes.  This limits its ability to use markets as the instrument of change.   China is thus greening capitalism using mandates issued by a centralised bureaucracy.  Consequently China is less dependent on instruments such as carbon prices and taxes which are politically difficult to implement.

But there are concerns over China’s quantitative and qualitative power in influencing outcomes in the ongoing energy transition. China’s preference for mandates has meant that production of certain low carbon technologies involves state subsidies.  While these subsidies have reduced the cost of low carbon energy for many consumers across the world, it has raised concerns for producers who do not have the benefit of subsidies.

The main features of a renewable energy system are lower intensity of energy sources, low efficiency of conversion, temporal and spatial discontinuity, dramatic change in the economic concept of energy scarcity and a leading role for a network wherein energy, matter, information and monetary values circulate.  All this means higher levels of complexity and control.  Increasing significance of renewable energy and related challenges of matching peaks in provision with those of consumption is likely to entail higher levels of state involvement in monitoring and controlling consumption of energy at the household level.  This may not be among desired outcomes for many across the world.  But given that the global low carbon transition project is essentially a top-down process of state led energy transformation one cannot really complain about Chinese state interventions that have brought the low carbon goal much closer for the rest of the world.

Views are those of the author                   

Author can be contacted at



Monthly Power News Commentary: September – October 2017


The Pradhan Mantri Sahaj Bijli Har Ghar Yojana (Saubhagya) was launched by Prime Minister Narendra Modi with an ambition of providing electricity connections to all 40 million off-grid  families by December 2018. Connecting 40 million off-grid families under Saubhagya will increase the electricity requirement by 28,000 MW or 80 billion units in a year. The government said power will not be provided free of cost to any category of consumer under the recently launched Saubhagya scheme, which aims to provide electricity to all. The scheme is expected to increase the energy requirement by 28,000 MW per year. This may bring some good news to discoms. However, under the scheme the poor families will be provided electricity connections free of cost. Other families will pay ₹ 500 only, which shall be recovered by the distribution companies/power departments in 10 instalments along with electricity bills. A large proportion of coal-based power generation capacities in the private sector, under stress due to multiple factors, will remain depressed for a long time despite a raft of alleviation measures from the government, according to Crisil Research. As of August 2017, about 21 GW of commissioned private sector coal based capacities were under stress for want of long-term power purchase agreements or because of poor offtake. With demand growth expected to remain tepid, the outlook for these capacities is bleak for at least the next few years. Perhaps the Saubhagya scheme may bring some good fortune to these stranded generating companies.

The ADB, with co-financing from AIIB, will provide $150 million in an ongoing power transmission project in India, with an aim to deliver more clean energy. AIIB said that the project is being carried out to enhance energy connectivity in the country by strengthening its electricity transmission system. The new funding from the partners will be used for additional power transmission network components that will connect with the ADB-financed Green Energy Corridor and Grid Strengthening Project. According to the Manila-based ADB, the clean energy project will be expanded further to increase energy transmission to cover more states in the country. The project will include 400 kV transmission components in the southern state of Tamil Nadu to connect at Pugalur with the long-distance grid systems funded by ADB. The development bank will deliver $50 million, while AIIB will be co-financing $100 million for the component, which will be built at a cost of $303.5 million. India’s state-owned transmission company Power Grid will fund the remainder. India’s new grid system will mainly transmit solar and wind power, aimed at covering more locations.

The Punjab and Haryana High Court issued notice to various authorities in Punjab on the electricity subsidy given to rich farmers for their agricultural pump sets. Notices were issued to the Punjab government, the Punjab Electricity Regulatory Commission and the PSPCL on a PIL which seeks to abolish the subsidy to those who are financially well-off. The plea also seeks to identify the creamy layer among farmers on the lines of OBC reservation. Punjab has been providing free electricity for tube-wells for several years. The subsidy, which is reimbursed to PSPCL by the state government, was ₹ 61.13 billion during 2016-2017. The argument is that the method of giving subsidy is full of loopholes and some system to measure consumption of electricity should be evolved. While small farmers should be extended the benefit of free electricity on the basis of optimum consumption per acre as excessive use of tube-wells is resulting in receding water table, which is not in the interest of the state.

Power consumers might be in for partial respite as far as the proposed 22.6% hike in power tariff is concerned after UPPCL reduced its ARR by around ₹ 50 billion for financial year 2017-18. The ARR document filed by the UPPCL in August had mentioned revenue requirement of over ₹ 700 billion. This has now been revised to just over ₹ 660 billion. The UPERC, which received the fresh ARR, is learnt to be considering to pass on the benefit to domestic consumers in urban as well as rural areas. UPERC said while the proposed hike in power tariff up to 300 units may not be changed, there could be some relief for those consuming between 301 and 500 units. Under the 301-500 unit consumption slab, the UPPCL had suggested an increase from ₹ 5.60/kWh in 2016-17 to ₹ 6.20/kWh as per the new ARR. The increase may now be limited to ₹ 6/kWh, UPERC said. Rural consumers, however, may be in for more relief with the commission contemplating to lessen the increase in per-unit charge for metered consumers in villages. UPPCL had proposed hike for rural domestic consumers from ₹ 2.20-₹ 3.90/kWh. The raise may now be restricted to ₹ 3/kWh only, UPERC said. UPERC said the idea is to rationalise the tariff structure so that consumers are spared a tariff shock and at the same time UPPCL does not face financial burden in supply power to consumers. Despite reduced ARR by UPPCL, revenue gap to the tune of more than ₹ 70 billion remains. UP government announced it will double the penalty on consumers caught pilfering electricity. So far, a penalty is slapped on a consumer based on an assessment of power consumption over a period of one year. The penalty assessment will now be based on two years. The decision was taken at a meeting of higher authorities of power department with their counterparts in the UPERC. UPERC has decided to change the distribution code to pave way for higher penalty on power consumers. UPPCL too had petitioned the commission seeking to double the penalty on those engaged in power pilferage. High line losses of around 31% have posed challenge to the state government.

Karnataka will buy an additional 1,000 MW of power for eight months as it faces a shortage of power supply from plants designated to the state. The tenders have been won by Sembcorp (400 MW), JSW Energy (300 MW) the Nigrie and the Bina thermal units of Jaiprakash Power Ventures (100 MW each) and Shree Cements (100 MW). The state would buy the power at ₹ 4.08/kWh. The Karnataka Electricity Regulatory Commission had allowed the state to float two separate tenders of 500 MW for the power procurement, one from power plants based in southern states, and the other from the rest of the country. The state expects power demand to rise from around 8,500 MW to 9,500 MW-10,500 MW in the upcoming festive season. The peak demand of power in Karnataka in September 2016 was 9,500 MW. The state is currently facing a shortage of 3,300 MW from its designated power plants.

The centre promised to electricity worth ₹ 4 billion will be given every year for free to Maharashtra after the Narmada Hydro Power project is complete. Recently, the state announced that electricity generation has dipped due to coal shortage and so it is forced to impose power cuts. The government also said it is facing a deficit of 2,500 MW to 2,800 MW. At present, rural areas of the state face power cuts that last up to six to eight hours despite the fact that power consumption during the monsoon drops as agriculture pumps are switched off. The total demand for power in the state is around 15,500 MW.

Spot market power prices in India have peaked at ₹ 9/kWh a three-year high, while the average price on India Electricity Exchange also rose to ₹ 5/kWh on low electricity supply. The prices are expected to remain high until the warm weather conditions recede. Wind-based generation dropped by 70 percent due to unfavourable weather conditions across states like Tamil Nadu, Gujarat and Madhya Pradesh. The hydro generation declined due to less rainfall in southern and western states. Data available with India Energy Exchange showed that the trading volume stood at an all-time high of 183 million units, while the prices peaked to ₹ 9.2/kWh across India for a 15-minute slot. The maximum clearing prices was ₹ 7.90/kWh.

Power Grid Corp’s board has approved an investment of ₹ 1.98 billion for setting up India portion of Baharampur-Bheramara (Bangladesh) 2nd 400 kV double circuit transmission line with 24 months commissioning schedule.

India has said that it would give Ethiopia a line of credit of $195 million for power transmission sector and medicines worth $2 million. The two countries will also work together in the UN and other multilateral bodies. India thanked Ethiopia for its participation in the International Solar Alliance, established in 2015.

Rest of the World

French oil major Total said it would undercut EDF and Engie in the French power retail sector with a 10 percent price discount, setting the scene for a possible price war. Total wants to win a 10 percent market share – or 3 million customers – within five years before expanding deeper into Europe. Total told investors in September that it targeted 5 GW in power capacity in five years’ time. Alternative energy suppliers are gradually clawing market share from EDF, but the state-controlled company still retains a stranglehold on the electricity market with an 84 percent share nearly a decade after the French market was opened up.

The Estonian state-run utility Eesti Energia has received approval from its shareholders to extend its retail sales businesses in the Swedish and Finnish power markets. The company will start the retail sale of electricity to private customers in both countries by the first half of 2018. The company has been selling electricity both in Latvia and Lithuania for around 10 years and entered the Latvian gas market along with the Polish electricity and gas markets in 2017. Eesti Energia entails a power generation unit and its 2016 installed capacity reached 2,109 MW.

Construction recently began work on a giant power supply pylon, believed to be the world’s tallest in east China’s Zhejiang Province, State Grid Zhejiang Electric Power Company announced. A pylon is a large vertical steel tower-like structure that supports high-tension electric cables. At an impressive 380 metres tall, the pylon will be four times the height of London’s Big Ben. According to the power company, the new pylon is a part of a new ultra-high voltage power line project between cities of Zhoushan and Ningbo.

The Iranian government expects to synchronize its domestic electricity network with Iraq by the end of November 2017, which would significantly increase the amount of power exchanges between the two countries. The rationale behind this plan is to enable the exchange of power between the two markets and in particular during peak demand hours. Iran estimates that it has been producing enough power throughout 2017 to be able to satisfy a significant portion of Iraq’s power needs without causing shortages in the domestic power grid. Iran already trades power with four neighbours, namely Azerbaijan, Turkey, Armenia and Iraq. Under swap deals, Iran imports electricity from Armenia and Azerbaijan in summer, when domestic demand soars, and exports electricity in winter.

The first sections of a power cable to run between Britain and Belgium were installed and the project is on track to start operations in 2019, increasing the UK’s capacity to send or receive electricity from the continent by 20 percent. Nemo Link, a joint venture between the UK’s National Grid and Belgium’s Elia System Operator, said it had started laying 59 km of a subsea cable in Kent, on the British east coast, while work at the Belgian end would commence next year. The National Grid, owner and operator of much of Britain’s gas and electricity distribution network, voiced concern in January that Brexit could dampen investment as the UK loses its say over EU regulations of networks and power trading. Average UK daytime demand for electricity is about 32 GW, depending on the season, with generation primarily from gas-fired power stations, wind turbines and nuclear plants. Interconnectors to Europe increase Britain’s flexibility to supply consumers with power. Britain plans to build three new cables to France, adding 3.4 GW of capacity to the existing 2 GW, as well as its first interconnector to Norway with 1.4 GW of capacity and to Denmark with 1 GW of capacity, according to UK energy regulator Ofgem.

MW: Megawatt, GW: Gigawatt, discoms: distribution companies, ADB: Asian Development Bank, AIIB: Asian Infrastructure Investment Bank, kV: kilovolt, PSPCL: Punjab State Power Corp Ltd, PIL: public interest litigation, UPPCL: Uttar Pradesh Power Corp Ltd, ARR: annual revenue requirement, UPERC: Uttar Pradesh Electricity Regulatory Commission, kWh: kilowatt hour, UN: United Nations, UK: United Kingdom, EU: European Union

Courtesy: Energy News Monitor | Volume XIV; Issue 19

Energy budget: purveying aspirations

Lydia Powell, Observer Research Foundation

‘The budget lacked energy’ is perhaps what one of the breathless media commentators could have said after the budget speech last week. The budget did not contain any path breaking announcements & even mundane statements on energy that are routinely made in budget speeches were missing.

But central budgets without spectacular announcements are not necessarily sub-optimal. When only a sixth of the central budget is available for discretionary spending, any spectacular plan that is announced will have to be aspirational as it is unlikely to be backed by realistic funding and execution plans. As a senior member of the planning body observed recently, ‘even indicative budgets do not make sense in a market economy where most of the investment decisions are made by the private sector’. Business led capitalism is the main principal of social regulation in India and budget makers have no choice but to become purveyors of aspirations and inspirations in the hope that their plants may be legitimised if they serve purposes of business. Moreover state budget spending is 40 percent more than central spending and is growing faster. The increase of allocation to States in the Fourteenth Finance Commission is likely to accelerate this trend. If so what can central budgets propose other than some aspiration and a bit of inspiration?

Increasing solar based capacity to 100 GW in the next five years and building 100 smart cities in an unspecified future period are some of the aspirational targets mentioned in the budget speech. If we put the target for solar based power generating capacity in perspective, India would have to create, in just 5 years, the equivalent of what the whole world created in solar photovoltaic capacity by 2012. The aspiration of creating 100 ‘smart’ cities is perhaps less ‘over the top’ precisely because the interpretation of the word ‘smart’ is subjective. Even cities having decent power supply, garbage bins and bicycle lanes can be declared as ‘smart’ cities. The announcement that 5 more ultra mega power plants (UMPPs) would be constructed is puzzling.  When existing UMPPs are struggling for closure what justifies new projects?

The doubling of the cess on coal production from Rs 100 per tonne to Rs 200 per tonne ‘to finance clean energy schemes’ as the honourable Finance Minister put it is probably less aspirational because it will generate real money. The production of 500 million tonnes of coal annually should in theory yield about Rs 100 billion which is substantial but insufficient to underwrite the aspirational goal for renewable energy capacity.  The cess levied on coal since 2010 has contributed about Rs 170 billion to what has been labelled ‘national clean energy fund’. According to the Economic Survey this sum is currently underwriting 46 clean energy projects at a cost of roughly Rs 165 billion. The close tally of the two figures makes them appear as if they were creatively engineered. The idea of increasing the cess (or clean energy tax) on coal is elaborated in the chapter titled ‘From Carbon Subsidy to Carbon Tax: India’s Green Actions’ in the Economic Survey 2014-15. The chapter gratefully acknowledges the ‘help of Muthukumara Mani and Fan Zhang from the Office of the Chief Economist, South Asia Region of the World Bank’. Should we then conclude that India’s aspirations are inspired by the World Bank?

The chapter appears to congratulate India for progressing from being a subsidiser to ‘penaliser’ (through taxes) of carbon use. We should probably take this as approval from the World Bank. The first illustration in the chapter is the decontrol of petrol and diesel prices with parallel increase in excise duties to match declining global crude prices. With the decline in global crude prices, under-recoveries (the difference between global and domestic prices) have been eliminated for petrol and diesel. Though the budget speech and the Economic Survey claim this to be a dramatic reduction in petroleum subsides executed by the Government, it was just a natural consequence of the decline in global crude prices. But the Government did do something: It did not allow the fall in global prices to pass through to the consumer by increasing the excise duty on both petrol and diesel.  The chapter treats this as a measure equivalent to imposing a tax on carbon emissions. It is not a secret that the shift from subsidisation to taxation of petrol and diesel is driven by concerns over Government revenue.  Revenue from taxes and duties on petroleum is estimated to be roughly equal to 3 percent of GDP (including Central and State taxes). But if this tax makes a contribution to reducing carbon emissions, this is perhaps an item that we should include in our Intended Nationally Determined Contribution (INDC) for climate change.  According to the Economic Survey the implicit tax on diesel in India is $42 per tonne and that on petrol is $64 per tonne which the report claims is above $25-35 per tonne considered to be reasonable initial tax on CO2 emissions. The report calculates that measures taken on taxing petrol and diesel would result in 11 million tonnes of carbon reduction which the report says is equal to the annual emissions of Luxembourg in 2012.

As for coal, the Economic Survey considers the proposed cess of $3 per tonne of coal as very low compared to $50-60 per tonne tax required to account for health care costs imposed by coal use. The estimation of tax to be imposed on coal to offset healthcare costs is said to be anything between $3.41 per tonne to $51.11 per tonne based on what the report labels ‘statistical value of life’. What the statistical value of life means is not elaborated in the Survey. The paper cited for the estimate on healthcare costs is a working paper by Resources for the Future (RFF) that assumes that coal based power generation produces only one consequence: that of killing people prematurely on account of respiratory problems induced by particulate emissions from the coal plant.  The value of the electricity it generates, the economic growth it contributes to, the employment it generates, the poverty it alleviates, the hospitals, schools and trains it powers have apparently zero value according to the RFF paper. This is an irrational exaggeration of costs and complete exclusion of benefits of fossil fuel based power generation. We live in a world that treats economic growth measured in terms of the Gross Domestic Product as the greatest common good that a country can produce. Coal based power generation underwrote the production of this greatest common good in industrialised nations in the past and is currently doing so in poor countries such as India. In this light, the Economic Survey’s unquestioning acceptance of the RFF paper is quite puzzling especially when the Government seeks to invite companies to ‘make in India’ to contribute towards growth and employment.

The average Indian consumer pays an inefficiency tax for coal based electricity which is probably far higher than the carbon tax.  He also pays one of the highest prices for a litre of petrol or diesel as a share of his income. The high cost of electricity and the inefficient manner in which it is delivered (along with factors such as low household incomes which has deeper structural causes) ensures that average household electricity consumption is far below the levels required for decent living. The high cost of petrol ensures that the average Indian continues to cover most of his everyday commuting needs by foot or by bicycle. These are the biggest contributions an average Indian makes to carbon emission mitigation. This unintended and undesirable contribution that millions of unwashed masses make is almost completely forgotten in what appears to a hurriedly green washed and largely aspirational budget!

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 38

Indian Coal needs a bath

Ashish Gupta, Observer Research Foundation

Most of the power plants in the country are using inferior grade coal as shown in the table below. The question is very simple: why coal washing is not getting done despite its importance.

Grading of Indian Coal[1]

Serial number Grading of Coal Criteria
1 Superior Grade Grade – (A+B+C): 5,800 Kcal/ kg
2 Intermediate Grade Grade – D: below 5,800 Kcal/kg
3 Inferior Grade Grade – (E+F+G): 4,000 Kcal/kg

The Ministry of Environment & Forests and Climate Change mandated use of beneficiated coal to bring the ash content to 34 percent in the power plants through the following directions:

  • Power plants located beyond 1,000 km from the pithead (there is a possibility that it will be modified to 500 km)
  • Power plants located in the critically polluted areas, urban areas and in ecologically sensitive areas
  • Power plants using Fluidised Bed Combustion technologies and Integrated Gasification Cycle Combustion mechanisms are exempted from the above mandates.

The country’s coal washing capacity currently stands at 131 Million Tonnes/ per annum with 17.03 percent capacity utilisation. Despite the mandate capacity utilisation of the coal washeries is low in the country and this is an issue that needs to be explored.

The trend of washed coal is given in the table below:

Production of Washed Coal during the Last Ten Years[2]

Washed Coking Coal Washed Non-Coking Coal
Year Production (MT) Growth % Production (MT) Growth %
2004-05 8.79 7.2 10.556 Not known
2005-06 8.376 -4.7 12.555 18.9
2006-07 7.025 -16.1 12.688 1.1
2007-08 7.171 2.1 12.686 0
2008-09 7.181 0.1 13.55 6.8
2009-10 6.547 -8.8 13.963 3
2010-11 6.955 6.2 14.531 4.1
2011-12 6.496 -6.6 15.437 6.2
2012-13 6.55 0.8 14.19 -8.1
2013-14 6.615 1 15.7 10.6

Are there technical reasons behind under utilisation of coal washing capacity such as Run of Mine coal characteristics or is technology available is not efficient?

Are there economic concerns such as high capital costs or operating cost or poor yield or recovery?

The answers will be available only when the issue is studied in depth. This is a pressing need for the country as narratives not supported by fact such as lack of coal washing capacity being a major problem in washing coal prevail.

Views are those of the author                    

Author can be contacted at

[1] Parivesh – Clean Coal Initiatives June, 2000

[2] Provisional Coal Statistics, 2013-14 (Washeries not owned by coal companies are not included)

Courtesy: Energy News Monitor | Volume XI; Issue 39


Monthly Coal News Commentary: September 2017


While renewable energy platforms are busy writing the obituary for coal, monsoon rains highlighted the importance of coal in ensuring that India’s power grid keeps ticking round the clock. Coal stocks at thermal power plants across the country were reported to have dropped to alarmingly low levels. Private power companies are the worst-hit, as state-run NTPC Ltd, under government patronage, is reportedly getting out-of-turn supplies. According to power companies, the shortage of fuel supply is primarily due to reduced production by CIL and its failure to open new mines and commission new railway sidings for seamlessly transporting the dual power plants. Adding to the woes is Jharia coalfield underground fire which led to closure of the critical Dhanbad-Chandrapura railway line in December 2016, badly affecting the railway’s network planning. The coal ministry had said in May that NTPC’s Kahalgaon and Farakka plants (both pithead), which source coal from CIL’s Rajmahal open-cast mine, would not face any coal shortage issues after CIL reportedly faced troubles while acquiring land for the expansion of the mine. Recently, an official note sent by the CCL, a CIL subsidiary, to the railways urged the latter to prioritise six NTPC plants for coal supply. This led to coal stocks at some private thermal power plants which receive the fuel from CCL to reach precarious levels. As of now, 36 plants including GMR’s 1,050 MW Kamalanga unit, Hindustan Power’s 1,200 MW Anuppur unit and Reliance’s 1,200 MW Rosa plant have coal stock of less than 4 days. Unavailability of adequate coal in the sidings has increased the time taken to load railway rakes. Some sidings of CIL subsidiaries are taking up to 7-8 hours to load coal instead of the standard 3 hours, due to lack of coal at loading sites. At one of the sites of the Bharat Coking Coal Ltd, which is affected by the closure of the Chandrapura rail line, it is taking up to 12 hours against 9 hours to load a rake. Increase the quantum of coal supply to private power plants such as 1,980 Lalitpur plant and 1,200 MW Roja plant and state utility-owned generating stations such as 665 MW Harduaganj plant and 1,140 MW Parichha power plant has been sought.

State governments and power plants were also blamed by the central government for the critical condition in some thermal power plants for want of coal.  The real culprit may be monsoon rains.  Following floods at a number of coal pits power generation units started asking for the coal that they did not lift earlier. The situation was compounded as railway tracks and roads were submerged.

CIL has drawn up an emergency plan to regulate coal movement to the non-power sector for pushing additional coal to the thermal power plants. In the long run, it plans to redefine its priorities much on the lines of the governance practiced in CCL. Redefining priorities has helped in complete transformation of this CIL subsidiary, both in terms of physical and financial parameters. CIL is looking to replicate the Kayakalp model of governance in the long run. This model, which is based on the principles of democratic planning, delegation of power and enforcement of discipline, has resulted in a turnaround of CCL. With improvement in production, improvement in finances would also be possible by bringing about a check in the cost of production. CCL’s cost of production went up to ₹ 1,046/tonne in FY16 from ₹ 1,039/tonne in FY12. This was virtually a decrease in the cost considering adjustment with the inflation. Profits went up to ₹ 445/tonne in FY 16 from ₹ 228/tonne in FY12. CIL plans to use the road-cum-rail mode to supply stocks from CCL, Western Coalfields, South Eastern Coalfields, Bharat Coking Coal and Mahanadi Coalfields. CIL said higher grade coal can substitute imports since imports have come down 19 percent during April — July period compared to the same period last year. Coal imports during April-July 2017 were 19.29 mt, compared to 23.76 mt during same period last fiscal. However, in the long run CIL would look for a balanced growth in production, although it has no plans of shelving its target of producing 1 bt by 2022.

In an effort to improve the stock situation at power stations and help increase electricity generation, CIL has allowed power plants to lift as much coal as they can, even beyond their quota, if they are within 60 km of pitheads and use trucks to transport it. For plants beyond 60 km, CIL has decided to send as much additional coal as possible so that their stocks reach a comfortable position. It has also urged power utilities to stock up adequate quantities to avoid criticality. Rising demand for thermal coal has given CIL an opportunity to liquidate some 33 mt of stock lying at its pitheads. Backed by a 20 percent rise in coal supply in August at 34.4 mt, power plants managed to generate 17 percent more against the previous corresponding period. Average rake loading in September 2017 grew 22 percent as CIL has taken it up on a war footing to shore up coal stocks at thermal power stations, raising the rake loading to 197 rakes per day against to 162 rakes in the previous corresponding period. Since September 14, loading is at 215 rakes a day.

For their part, the discoms reverted back to their time tested method of adaptation to scarcity situations. The Rajastan discom announced load shedding as power production in the state has been reduced drastically by 2,700 MW due to severe shortage of coal. The discoms said that station-wise load shedding would continue till the power production is stabilized. According to Rajasthan Power Development Corp, out of the total capacity of 1,500 MW of power at Surajgarh Thermal Power Station, only 725 MW power is being produced now while at Kota Super Critical Thermal Power Station only 590 MW of power is produced against the total capacity of 1,240 MW.

The issue of fires in coal mines continues to haunt the coal sector. A team of mines and fire experts were reportedly conducting fresh studies on the status of the underground fire in the Dhanbad-Chandrapur railway line in Dhanbad Division of East Central Railway. Coal ministry has ordered Directorate General of Mines Safety (DGMS) to constitute the joint committee of mine and fire experts of different institutions to probe fresh status of fire under railway track of Dhanbad-Chandrapura railway line. The ministry has directed BCCL to bear the cost of study.

Captive coal production in India rose 7.2 percent to 14 mt in the five months to August, according to data compiled by the Coal Controllers Office. The output was 13.45 mt in the year-ago period. Data showed that Sasan Power produced 7.3 mt from its Moher and Moher Amlohri Extension mines, while Rajasthan Rajya Vidyut Utpadan Nigam Ltd (RRVUNL) produced a shade over 3 mt from its Parsa East and Kanta Block. Jaiprakash Power produced around 1.7 mt from its Amelia North coal mine during the period. NTPC, which started coal production this year, mined 0.6 mt during the period from its Pakri Barwadih block. Rest of the captive coal block holders, 11 in number, each produced less than 1 mt of coal during the period. NTPC which started production this year, produced around 0.6 mt during the same period from its Pakri Barwadih block.

Two Adani Power companies managed to secure a shade over one third of the total coal auctioned by CIL under the Shakti scheme by offering discounts ranging between ₹ 0.01 – 0.03/kWh over their existing tariffs. Others in the race were GMR’s power arm GVK Power, Inland Power, Lalitpur Power, ACB India, KSK Mahanadi Power and Sai Lilagar Power. They were among the 10 companies, including Adani, that collectively managed to secure 27 mt of coal supply contract for 25 years on committing to generate power at discounts ranging between ₹ 0.01-0.04/kWh over their existing tariffs. Adani Power Maharashtra and Adani Power Rajasthan together secured supplies of 9.9 mt of coal. The grade they have been allocated ranged from G6 and G13. It would be supplied from South Eastern Coalfields’ Korba, Mand Raigarh, and Korea Rewa mines, Mahanadi Coalfields’ Ib Valley, Basundhara and Talcher mines as well as from Western Coalfields and Northern Coalfields. Others like GMR Kamlanga Energy secured 1.5 mt of coal while GVK Power bagged 1.7 mt. ACB India managed to secure 200,000 tonnes of coal a year, Inland Power secured 67,400 tonnes of coal while Sai Lilagar Power Generation bagged supplies of 376,200 tonnes of coal.

Judicial intervention continues to step in where politicians fear to tread when it comes to environmental regulations. CIL subsidiary Mahanadi Coalfields Ltd is facing a penalty of more than ₹ 200 billion in the wake of a SC order that rendered illegal all mineral production in violation of environmental laws. The Odisha government is evaluating the company’s liability after the top court in its verdict ordered the state to recover the value of all minerals produced without or in excess of caps under environment, forest laws, pollution control rules and mining plans. The SC ruling — in a case filed by social organisation Common Cause against the Union of India and others over violations of iron ore and manganese miners in Odisha — has also prompted the expert appraisal committee of the central environment ministry to defer clearances to coal projects. Odisha directorate of mines has already sent notices to 152 errant lessees, including Orissa Mining Corp, Tata Steel and Aditya Birla company Essel Mining, to recover ₹ 175.76 billion. The state has time till the end of the year to recover from another 34 lessees the value of ore mined from forest areas without permission. The Odisha government is of the view that the order may apply to coal, chrome and other major minerals. The government has sought the state advocate general’s view on what coal and chrome miners owe the government.

The declining prospects for coal have made them an affordable target for acquisition. On the lookout for acquisition of coking coal assets abroad CIL is in an advanced stage of talks with an Australian coal mining company based out of Queensland, where it plans to acquire substantial stake. In this regard, CIL had floated a closed tender for empanelled merchant bankers of which PwC and Ernst & Young have shown interest, to carry the transaction forward. For taking the equity stake, CIL will have to commit a minimum purchase of coking coal every year from the Australian company. The proposed agreement includes a technology transfer clause, from which CIL hopes to improvise its own Indian mining operations in open cast mines. Around 30 percent of the 50-60 mt annual demand for coking coal is met by domestic supply. The rest is catered from import, mainly from Indonesia, Australia and South Africa. Estimates suggest that by 2030, the steel sector will be demanding 180 mt of coking coal a year, when steel production is targeted to reach 300 mt. In August last year, CIL signed an  MoU with the South African government’s African Exploration Mining and Corporation to identify, acquire, explore and develop coal assets, namely, the coking variant, in South Africa.

Notwithstanding short term scarcities, the longer term trend of increase in production of coal is reducing imports and saving foreign exchange.  Hike in coal production in the last three years has helped mining major CIL save ₹ 259 billion in foreign exchange. Coal imports accounted for 25 percent of the country’s total consumption in 2015-16, and 23 percent in 2016-17. Coal stock in at least over a dozen thermal power plants in the country turned critical, the CERC had said in a recent report. Singh said the share of coal in India’s commercial primary energy supply was 55 percent in 2015-16, and is expected to remain high at 48-54 percent, even in 2040. CIL has maintained its projection of one billion tonne coal production target by 2022. The company produced 554.14 mt of coal in 2016-17, while coal off-take was 543.32 mt during the same period.

India needs to partner with other countries to tap cheaper funds for cleaner coal technologies as the South Asian nation is expected to use the fuel to produce over half of its power in the next two decades, the World Coal Association said. India, the world’s second-largest coal importer, relies on the fuel for about 78 percent of its electricity generation. The federal think tank NITI Aayog has projected coal’s share in the country’s overall energy mix will reduce to 48-54 percent by 2040 from around 55 percent in 2015. India will need to ally with countries including the US, Japan, and Australia, to get cheaper funding from multilateral development banks to access cleaner technology and catch up with Japan and China. India’s reliance on imported coal would be significant in the coming years to power the nation’s economic expansion. India will need to be on board with a global partnership to develop its domestic coal expertise. Coal demand in India is expected to rise despite companies offering very low tariffs for solar power. Global output for coal is also expected to rise in 2017, led by US and China.

Adani Enterprises appears to be at odds with the state of Queensland over royalties for its Carmichael coal project, just days after the Indian company said it would soon break ground on the Australian mine. Adani announced it would start work in October on the project using $319 million of its own funds, even as it looks to lock in financing for the controversial mine. Previously it had said it needed to borrow to get the project off the ground. The company said it would target first shipments from March 2020 for the first stage of the project which has been trimmed back to a cost of about $3 billion. The project relies on a $704 million concessional loan to help Adani build a rail line linking the mine with a shipping port. The government is assessing whether to give Adani the loan through its Northern Australia Infrastructure Facility program aimed at encouraging economic development in rural regions. Adani had originally planned to develop the mine, rail and port infrastructure at a cost of $12.9 billion, before last year downsizing the first stage and trimming the cost.

Rest of the World

Guangzhou port, the largest coal transport hub in southern China, has reportedly halted foreign coal imports. Traders said the move caught merchants using Guangzhou by surprise and interpreted it as a sign of Beijing stepping up its campaign to cut pollution caused by the burning of coal. China already banned coal imports at small ports in July but Guangzhou has 14 coal berths and can handle 60 mt of shipments per year. Chinese coal imports in the first seven months of 2017 totalled 110 mt, an average of over 15.7 mt a month. China’s north-eastern industrial heartland may face winter power and heating cuts after authorities in Beijing spurned requests from provincial providers for help securing coal supplies after two major mines were forced to halt output, utilities warned. Coal-dependent power in the major manufacturing province of Heilongjiang issued their plea to the NDRC via the state power grid after authorities suspended work at mines in neighbouring Inner Mongolia last month, according to documents posted on the website of coal publication The mines halt is part of concerted efforts by China to tame increasingly severe winter smog in industrial centres. But it also shows Being’s war on pollution can roil key industries while sending coal prices sharply higher, both in China and across Asia. In its response to the request, the NDRC acknowledged the coal shortage but did not offer more supplies, the documents showed, instead calling on the provincial government to ramp up clean fuel output while cutting coal-fired generation from inland power plants.

China-backed coal miner Yancoal Australia Ltd said it had exercised its option to buy a 29 percent stake in the Warkworth operation from Japan’s Mitsubishi Corp for $230 million. The agreement brings Yancoal’s stake in the Warkworth project to about 85 percent, it said. The project, which was part of a bidding war between Yancoal and commodity trader Glencore PLC, was snatched up by Yancoal earlier this year as part of its acquisition of Rio Tinto’s Coal & Allied unit.

Chinese energy conglomerate CEEC said it is in talks about investing $1.2 billion in a coal power project in Bosnia, one of the biggest energy schemes in the Balkans. If a deal is reached CEEC would fund virtually the entire project to build a 430 MW coal-fired power plant and develop a coal mine in Bosnia’s autonomous Bosniak-Croat Federation, which is seeking to revive its energy sector as many of its coal-fired power plants are past their prime. Talks with Bosnian private company Lager, which holds a 30-year concession to operate the Kamengrad coal mine in Sanski Most in northeast Bosnia, were well underway and could soon lead to an agreement. The mine has 115 mt of proven coal reserves and an estimated 400 mt of untapped coal reserves. Coal is widely available in the Balkans, making it appealing to governments seeking ways to ensure security of supply and keep energy prices low while also placating influential mining lobbies. As the European Union, the World Bank and other institutions cut back on coal financing, Balkan states are encountering difficulties in securing finance for their projects, prompting Chinese institutions and contractors to step in.

Washington State rejected a key permit needed for a proposed terminal to export coal to Asia, another blow to companies eager to sell Wyoming and Montana coal to Asian markets and to the Trump administration’s policy of global energy dominance. Washington’s Department of Ecology rejected a water quality permit for the Millennium Coal Terminal, one of several permits sought by the company to build what would be the largest coal export terminal in the US. Millennium said it would appeal the decision, and accused the state agency of being biased against the project. The terminal would export up to 44 mt of coal mined in Wyoming and Montana’s Powder River Basin each year from companies such as Cloud Peak Energy and the coal-producing Crow tribe of south-eastern Montana. The proposed terminal would offer coal mining companies an alternative to exporting coal through the West shore terminal in Vancouver, British Columbia. It is the last of six proposed coal terminals in the Pacific Northwest that have been denied approval by state regulators or the Army Corps of Engineers amid opposition from states and the Lummi Tribe, who argued that coal terminals interfered with their fishing rights. The US has been in a trade spat with Canada over exports of softwood. In response, British Columbia threatened to halt exports of US coal through Canada. US coal exports have jumped more than 60 percent this year because of soaring demand from Europe and Asia, according to a Reuters review of government data in the first half of the year. Some analysts said the trend may be temporary, depending on coal price trends in Asia.

As Pakistan bets on cheap coal in the Thar desert to resolve its energy crisis, a select group of women is eyeing a road out of poverty by snapping up truck-driving jobs that once only went to men. Such work is seen as life-changing in this dusty southern region bordering India, where sand dunes cover estimated coal reserves of 175 billion tonnes and yellow dumper trucks swarm like bees around Pakistan’s largest open-pit mine.

New Hope Corp is chasing more coal mine acquisitions in Australia over the next year to drive growth, its boss said after reporting a huge rise in annual profit on the back of an earlier expansion and higher coal prices. New Hope said the company sees more opportunities to supply coal to Asia, including China, Japan, South Korea and Taiwan, particularly for new high efficiency-low emissions power stations, and would look for acquisitions to help meet that demand. New Hope, one of two listed independent coal producers in Australia, bought a 40 percent stake in the Bengalla mine in New South Wales state from Rio Tinto two years ago for $606 million. Australia’s Newcastle coal prices have traded between about $72 and $106 this year, well above lows around $47 last year. The current Japanese benchmark price is around $85. The firm could also benefit from Asian coal buyer concerns about Glencore’s expansion in Australia following its recent acquisition with China’s Yancoal Australia of Rio Tinto’s Coal & Allied unit.

Share prices of some of Indonesia’s biggest coal miners plunged after the government indicated that it would be open to revising domestic coal pricing rules. Indonesia was considering drafting new rules on marketing coal for domestic supply, as part of government efforts to reduce electricity prices. Recent high coal prices have put pressure on state electricity utility Perusahaan Listrik Negara (PLN), which buys the bulk of the roughly 90 mt of coal consumed domestically each year. Indonesia requires miners to set aside a portion of their output, based on assumptions of domestic demand. PLN has been pushing for the government to adopt a cost plus margin mechanism for coal purchases, which would allow it to maintain pricing stability, but which analysts say would hurt coal producers’ profits. Strong Asian demand for coal from Australia is depriving domestic power generators of fuel and driving electricity prices higher. Local power companies are typically unable or unwilling to match the price premiums some Australian coal has been fetching in Asian markets, where less-polluting high energy, low emissions plants are being introduced at a rapid rate. Australian Newcastle thermal coal cargo prices, a benchmark for Asia, have jumped by more than 20 percent since July to over $100 per tonne on strong demand from overseas buyers. The shortage in one of the world’s top producers of the commodity comes as the nation battles to avoid blackouts that have become more frequent following a decade of uncertainty over carbon policy. The shortfall in coal is most acute in New South Wales, the nation’s most populous state, according to the Australian Energy Council, which represents power suppliers that generate most of the country’s electricity. In contrast, Japan, Australia’s largest overseas thermal coal market, taking more than a third of all exports, has plans for an additional 45 coal plants. Data from the Department of Industry shows Australia is forecast to produce around 251 mt of thermal coal this year and export 201 mt. Coal exports through the Port of Newcastle jumped to 14.2 mt in July from 12.3 mt in June, port figures showed.

CIL: Coal India Ltd, CCL: Central Coalfields Ltd, MW: Megawatt, kWh: kilowatt hour, FY: Financial Year, mt: million tonnes, discoms: distribution companies, SC: Supreme Court, MoU: Memorandum of Understanding, CERC: Central Electricity Regulatory Commission, US: United States, NDRC: National Development and Reform Commission, CEEC: China Energy Engineering Corp

Courtesy: Energy News Monitor | Volume XIV; Issue 18


Monthly Gas News Commentary: September 2017


The southward movement in global gas prices is benefiting consuming nations such as India, with New Delhi succeeding in negotiating better terms for the Gorgon LNG contract that supplies the fuel to Petronet LNG. The Gorgon contract involving Exxon Mobil’s output in Australia is the second long-term deal to be repriced after RasGas reworked the pricing formula in 2015 in favour of Indian companies. The new prices provide relief to Petronet LNG, BPCL, GAIL (India) Ltd, and IOC. India was among the first countries in Asia to rework its longterm gas contacts when Petronet LNG re-negotiated with Qatar’s Rasgas. India consumed about 19 mtpa of gas in the last fiscal, with half the requirement being met by imports. Under the new gas pricing formula, the Gorgon output will cost 13.9 percent of Brent crude as compared with an earlier ratio of 14.5 percent of JCC -an Asian benchmark for gas. If one assumes Brent at $50/barrel, this means gas prices will come down to $6.95/mmBtu from $7.25/mmBtu. The new prices will include shipping costs, saving Petronet LNG the transportation expenses. Gas pricing with the 14.5 percent JCC ratio has been considered one the most expensive LNG contracts globally. The savings could translate into a decline of $1/mmBtu in gas prices. For the entire contract period of 20 years, this would mean savings of around ₹ 80-10 billion. The delivered price of Gorgon contract will be nearly equivalent to RasGas contract prices at around $7/mmBtu.

Essar Ports is looking to invest around $500 million or over ₹ 25 billion to set up one LNG terminal each on the western and eastern coasts in the next 18 months. The company is looking at a cluster of small ports which will be closer to potential customers. Hazira and Salaya, where it already operates ports, could be the sites where it can set up the LNG terminals. Typically, each terminal will cost between $150-300 million, depending on the amount of work to be carried out, the company said. The capacity will range between 2.5-5 mt. The company is expected to tie up with banks and also put in its own resources as equity. Essar Ports, which delisted in late 2015, will close 2017-18 with a pre-tax profit of about ₹ 10 billion and is targeting to take it up to ₹ 13 billion with the commissioning of new facilities. ONGC plans to relinquish its CBM block in Raniganj, West Bengal, but is on course to produce gas from another CBM block in Bokaro in February. It is reported that it would be difficult to develop the Raniganj North block since an airstrip is coming up on the same land. The company evaluated the feasibility of lateral drilling to tap gas underneath the air strip, but it was found that this was not possible. ONGC has stakes in three other CBM blocks in Bokaro, Jharia and North Karanpura. Of the total nine CBM blocks allocated to ONGC, five have already been relinquished due to poor output potential. It plans to produce first gas from its Bokaro block in February. Land acquisition for the project is in progress with ONGC purchasing or taking land from owners on long lease. A key contract to build gas gathering station has been awarded and is expected to be ready by mid-2019. A peak production of 700,000 cubic meters a day is expected from the field. Recently, the government freed up pricing for CBM. ONGC is finalising a marketing plan for its output from Bokaro.

GAIL has chartered an LNG tanker from French major Total SA for three years to haul gas from the US beginning early 2018. GAIL had through the Shipping Corp of India invited bids for hiring four LNG carrying tankers. Some 30 LNG ships were offered, with Total offering the lowest day rate of $44,900 for a ship with 165,000 cubic meters of storage capacity. The French company had chartered the ship till 2029 but due to turmoil in the country, Yemen LNG project was temporarily shut in 2015. GAIL had resorted to short-term chartering after its $7 billion tender for hiring newly build ships fell due to bidders not agreeing to ‘Make in India’ terms. In the tender, GAIL had sought to time-charter nine newly built LNG ships of cargo capacity of 150,000-180,000 cubic metres to ferry LNG it has tied up from Sabine Pass and Cove Point LNG projects in US.

Sri Lanka has invited Petronet LNG to set up a liquid gas import terminal in that country, marking a major success for the Narendra Modi government’s energy diplomacy and signalling India’s emergence as a gas bridge for South Asia.  The deal has been in the making for over a year to weave a web of energy relationships in the extended neighbourhood — spanning Myanmar in the east to the Gulf in the west — by suitably leveraging India’s position both as a large consumption centre and a major source of petro-products and expertise. For Petronet, the deal paves the way for its first overseas liquid gas project, an area that has traditionally been dominated by global majors such as Shell and BP. The company submitted its bid for building a terminal with a capacity of handling 5 mt of gas shipments a year. India has been a major player in Sri Lanka’s fuel retail business for many years through Lanka IOC, a subsidiary of IndianOil. The LNG terminal will help it straddle the gas sector, the dominant fuel for future economic growth. With rising demand, Sri Lanka and Bangladesh offer an expanded market for large volumes of gas separately tied up by Petronet and GAIL, one of its main promoters, from Qatar, Australia, the United States and Spain’s Fenosa.

India must push for a trans-national deep water gas pipeline from Iran, passing through Oman but by-passing Pakistan, to feedstock the country’s power, fertilizer and steel plants in an environment-friendly and affordable way and for sustainable supply of the fuel, according to an Assocham study. During 2016-17, India consumed 55,534 mscm of natural gas of which 24,686 mscm was imported. India is now the fourth largest natural gas importer, mainly from Qatar. The study said India must take a stronger and more pro-active approach to build a least one trans-national gas pipeline in the next five years.

IGL, IOC-Adani Gas Ltd combine and HPCL-OIL JVs are set to win licences to distribute gas in one city each in the latest round of auction. In the much delayed 8th round city gas bidding, licences for gas distribution in Karnal, Haryana is set to go to IGL. The licenses for Ambala-Kurukshetra, also in Haryana, would go to HPCL-OIL, and South Goa to the JV between IOC and Adani Gas. Actual award of licences will take place probably a month later by when new members are likely to be appointed to the PNGRB the downstream regulator that conducts these auctions. In the latest auction, every bidder submitted a bid of 1 paisa as network tariff, as has become the norm for years, allowing the winner to be decided by the quantum of performance guarantees submitted. IGL submitted highest performance bond of ₹ 3.06 billion for Karnal, higher than HPCL-OIL’s ₹ 2.03 billion. Indian Oil-Adani Gas offered ₹ 4.03 billion performance bond for South Goa. HPCL-OIL was again in the second spot with a bid bond of ₹ 3.24 billion. It, however, furnished the highest performance bond of ₹ 3.03 billion for Ambala-Kurukshetra licence, just ahead of IOC-Adani’s ₹ 3.02 billion bond. The bids for three other cities — Yanam in Puducherry, Bulandshahr and Baghpat in Uttar Pradesh — have not been opened as yet.

Rest of the World

China’s state economic planner, the NDRC, has revived a plan to create a national natural gas pipeline company, aiming to provide gas producers with better access to infrastructure to help increase take-up of the cleaner-burning fuel. NDRC is working with state oil companies including CNPC and Sinopec Group on the proposal. The plan, first raised about five years ago, is part of Beijing’s proposed reforms to make the state-dominated oil and gas sector more efficient and follows a string of smaller steps over the past two years, including cutting down transportation costs and encouraging investment in gas storage. The proposed national pipeline company is expected to oversee China’s trunk line projects such as the West-to-East pipelines operated by CNPC and Sinopec’s project linking gas fields in the southwestern province of Sichuan to the east coast. China is the world’s third-largest gas consumer after the United States and Russia, with imports of the fuel making up about a third of consumption. The world’s top energy user aims to boost the use of natural gas, which emits half of the greenhouse gases produced by that burning coal produces, to about 15 percent of the total energy share by 2030 from just under 6 percent currently. The NDRC said earlier this year it expects the country’s gas pipelines to total 104,000 kilometers by 2020, up from 64,000 kilometers at the end of 2015. CNPC currently operates nearly 80 percent of China’s gas pipelines.

China’s technologically recoverable shale gas reserves dropped by 6 percent in 2016, the Ministry of Land and Resources said, with no new volumes of the unconventional resource added last year. Reserves stood at 122.41 bcm at the end of 2016, down from 130.18 bcm a year earlier. Shale gas was the only one of 22 major minerals listed to add zero newly discovered reserves in 2016, although potash was assigned a negative figure, indicating that some previous reserves were written off. The numbers suggest China’s efforts to replicate the North American shale gas revolution and reduce a hefty reliance on energy imports are running out of steam.

Royal Dutch Shell, ConocoPhillips and Santos face curbs on exporting gas from Australia’s east coast in 2018 if they fail to plug a projected local supply shortfall, Prime Minister Malcolm Turnbull warned. To deal with the crisis the government passed a law earlier this year that would allow it to limit exports from any of the three LNG plants on the east coast to beef up local supply. The three LNG exports plants, which were completed between 2014 and 2016, have long-term contracts to sell gas to customers in Asia, but have also been selling spot cargoes overseas instead of locally due to high costs and access issues on pipelines in Australia. Under the terms of the Australia Domestic Gas Security Mechanism, the LNG plant that has been seen most at risk of being forced to divert gas from exports to the domestic market is the Gladstone LNG plant, operated by Santos Ltd.

Trading house Glencore is to buy LNG supplies from Angola LNG over a multi-year period, adding to similar recent deals between the producer and traders including Vitol. Angola LNG said the deal was another step toward building its sales book with the most important players in the LNG market. Last month it sold LNG to Vitol over a multi-year period and also entered a sales deal with the trading arm of Germany’s RWE. Until recently, Angola has been selling all of its LNG via competitive tenders in the spot market, partly because a previous plan to ship LNG to the US fell through because of the US shale gas boom. Concerns over the Angola LNG plant’s reliability as well as limitations on feed gas supplies from offshore fields also prevented the Chevron-led project from previously locking in an LNG sales deal.

Angola’s sole LNG export facility will begin delivering shipments to commodity trader Vitol later this year under a deal announced. Angola LNG, which has steadied output following lengthy outages in recent years, has guaranteed Vitol access to supply for the first time, part of a wider shift in which trading companies are taking a greater share of the LNG market. In a global first, LNG from Angola has been entirely sold via competitive tenders into the spot market, partly because the plant’s original plan of shipping LNG to the US fell through following that country’s shale gas boom. Concerns over the plant’s reliability as well as limitations on feed gas supplies from offshore fields also prevented the Chevron-led project from locking-in a mid-term LNG sales deal immediately. Output from Angola LNG stabilised this year with production on track to hit up to 3.5 mt in 2017 compared with 0.77 mt  in 2016. Though improved, it will still fall short of the plant’s 5mtpa design capacity. Vitol could use its new-found Angolan volumes to help cover a 10-year obligation to supply South Korea’s Korea Midland Power Co. with 400,000 tonnes of LNG annually, or to grow its share of the spot market. A 70-percent drop in spot LNG prices LNG-AS since April 2017 and a growing supply overhang has given trading houses room to manoeuvre as established players from producers to oil majors turned to traders as a flexible source of demand.

Russian oil major Rosneft will invest in gas pipelines in Iraq’s Kurdistan, expanding its commitment to the region ahead of its independence vote to help it become a major exporter of gas to Turkey and Europe. Now Rosneft is widening its investments to gas by agreeing to fund a natural gas pipeline in Kurdistan. The investments would amount to more than $1 billion. The arrival of Rosneft will speed up gas development, which has so far largely been driven by mid-sized companies. For Rosneft, the deal is a major boost to its international gas ambitions. Rosneft has long sought to challenge Gazprom, Russia’s gas export monopoly, in supplying gas to Europe. For Turkey, it means the arrival of new supplies for its energy-hungry economy and the potential to become a major centre for gas supplies to Europe. The pipeline’s capacity is expected to handle up to 30 bcm of gas exports a year, in addition to supplying domestic users. Kurdistan sits on some of the largest untapped gas deposits on Europe’s doorstep. The pipeline will be constructed in 2019 for Kurdish domestic use, with exports due to begin in 2020.

Russian gas giant Gazprom has signed a 12-year deal to supply GNPC with LNG, a subsidiary of Gazprom Marketing & Trading Group said. GGLNG said LNG supplies were due to start in 2019. The agreement is the first stage in a planned series of partnerships between GGLNG and GNPC, with both companies working to develop the infrastructure and services required to manage and market the projected gas flows from the region, Gazprom said.

The Netherlands will receive its second-ever LNG shipment from Cheniere Energy’s Sabine Pass export facility in the US on October 6, according to shipping data. The vessel, with a capacity of 166,031 cubic metres, is currently berthed at Sabine Pass, live ship-tracking data shows.

Bangladesh will sign a 15-year deal with Qatar’s RasGas Co to import LNG  starting in 2018 to bridge the supply gap for power generation. The deal will be signed on September 25 in Qatar. Under the deal, RasGas will supply 1.8 mtpa of LNG for the first five years and 2.5 mtpa for the next 10 after that. The deal is Bangladesh’s first LNG import agreement and will help to cover the country’s domestic natural gas shortfall. The contract with the world’s biggest LNG exporter underscores the rise of South Asia as a new market for the fuel. The deal is for less gas than the 4 mtpa Bangladesh agreed to take in a 2011 memorandum of understanding with state-owned RasGas, since it instead plans to take more spot cargoes amid a supply glut that has lowered prices.  Bangladesh’s first floating storage and regasification unit, supplied by Excelerate Energy of the US, is to be commissioned by April 2018. Its second, supplied by the country’s own Summit LNG of the Summit Group, is due for commissioning by next October. Bangladesh is also looking to add two additional floating LNG terminals next year. Bangladesh, a country of more than 160 million people, could import as much as 17.5 mt of LNG a year by 2025. The country’s own gas reserves are depleting at the same time it is seeking to almost double its power capacity to 24,000 MW by 2021. Bangladesh is planning to tap the currently cheap and plentiful global LNG supplies and invest heavily in importing the fuel. South Asia is emerging as a hotspot for LNG, with Pakistan and Bangladesh set to join India as major consumers and help ease the oversupply that has dogged the market for years.

Iraq’s Kurdistan is poised for a major increase in gas output following the settlement of a court case with developers who are now looking to unlock the full potential of the region’s large resources, investor Dana Gas said. The semi-autonomous region settled a case with the Pearl Consortium by paying $1 billion to its members – Dana, Dana’s biggest shareholder Crescent Petroleum, Austria’s OMV, Hungary’s MOL and Germany’s RWE. The consortium has a 10-year-old deal with Kurdistan’s government to develop the Khor Mor and Chemchemal fields – one of the largest gas deposits in Iraq, with reserves of 400 bcm – enough to supply the whole of Europe for one year – and estimated resources of as much as 75 trillion. Pearl had been claiming against the government of Kurdistan for underpaying for gas liquids production, as well as delays to field development, but reached the settlement after the long-running case in London. Production will be raised from the current 3.3 mcm/day or 8 bcm/year. That volume would be enough to supply the annual gas needs of a country the size of Austria.

The US is proposing to speed up approval of small-scale exports of natural gas, including LNG, the US Department of Energy said. The Energy Department said the proposed rule would “expedite the review and approval of applications to export small amounts of natural gas in the emerging small-scale LNG export market,” which it said includes the Caribbean, Central America and South America. To date, most applications for export approval have been for larger-scale natural gas exports, but Central and South American markets require smaller volumes, the Energy Department said.

LNG: liquefied natural gas, BPCL: Bharat Petroleum Corp Ltd, JCC: Japanese crude cocktail, mmBtu:  million metric British thermal units, CBM: coal-bed methane, ONGC: Oil and Natural Gas Corp, mt: million tonnes, mscm: million standard cubic metres, IGL: Indraprastha Gas Ltd, IOC: Indian Oil Corp, HPCL: Hindustan Petroleum Corp Ltd, OIL: Oil India Ltd, JV: joint venture, PNGRB: Petroleum and Natural Gas Regulatory Board, NDRC: National Development and Reform Commission, CNPC: China National Petroleum Corp, bcm: billion cubic meters, mcm: million cubic meters, mtpa: million tonnes per annum, MW: Megawatt, US: United States, GNPC: Ghana National Petroleum Corp, GGLNG: Gazprom Global LNG Ltd

Courtesy: Energy News Monitor | Volume XIV; Issue 17


Monthly Oil News Commentary: August – September 2017


The largest opposition party in the Indian parliament said that the Centre was targeting the poorest of the poor by not reducing the taxes of LPG, kerosene and other petroleum products. According to the opposition, party prices of essential commodities were mounting due to the Centre’s apathy towards the poor. It said that the Centre had been providing “absurd reasons” such as ‘Hurricane Harvey and Irma’ for the increase of petrol and diesel prices. It said the central excise duty was increased 11 times in last three-and-a-half years, resulting in a cumulative rise of 133.47 percent on the price of petrol and 400.86 percent on diesel. It added that while the Consumer Price Index recorded an increase of 3.36 percent in August from a year earlier, the Wholesale Price Index rose to a four-month high to 3.24 percent compared to the year-ago period. According to the party, the Centre earned a windfall of around ₹ 2.5 trillion from the reduced price of crude oil.

Petrol and diesel prices have risen to their highest in three years in some cities in the country. Petrol price in Mumbai rose to its highest since August 2014 while diesel prices reached their peak since August 2014 in Kolkata and Chennai. In Delhi, Kolkata and Chennai, petrol prices are at their peak since January this year. Since July 1, petrol has climbed ₹ 5.18/litre in Mumbai, and diesel by ₹ 5.75/litre in Kolkata, and ₹ 5.71/litre in Chennai. Indian fuel retailers such as IOC, BPCL and HPCL started daily revision of prices of petrol and diesel from the middle of June, replacing the previous practice of fortnightly revision. Companies align local fuel prices with international rates and account for currency fluctuations in daily revision. Daily price changes are small and rarely make it to the headlines and go largely unnoticed. The recent price spike is expected to result in enormous gains for oil companies who while charging higher fuel prices also benefitted from lower crude rates as refinery shutdown in US cut demand for crude oil.

The government said the dynamic pricing regime would continue despite petrol prices going up by over ₹ 7/litre since the scheme was introduced pan-India from mid-June.  The government said that dynamic pricing ensured that the benefit of even the smallest change in international oil prices can be passed down the line to the dealers and the end-users. Daily revision allows any fall in international oil rates to be passed on to consumers immediately rather than having to wait for 15 days as in the old system. What this means is that the government is no longer the mediator of oil price risk. The consumer is now at the mercy of global oil price volatility.  Earlier, the state-run oil marketing companies used to review and revise retail fuel prices every fortnight on the basis of global crude oil prices, while the revision took effect from midnight. Dynamic fuel pricing is followed in many developed countries and India opted for it as a response to the recent volatility in global crude oil prices.

Indian petrol and diesel prices are much higher than what prevailed on the same day in Southeast Asian nations such as Malaysia and Indonesia and neighbouring countries like Pakistan, Nepal, Sri Lanka, Bhutan. Petrol price of ₹ 32.19/litre in Malaysia was less than half what prevailed in India. The diesel price in the Southeast Asian country at ₹ 31.59/litre was 44% lower compared to India. On the same day, petrol and diesel were available in Indonesia at prices that were 41% and 24% lower compared to India. The difference in auto fuel prices in India and countries within the subcontinent is also no less surprising. For example, on the same day petrol was available at ₹ 42.14/litre at fuel retail outlets in Pakistan, a price that is nearly 40% lower compared to India. Similarly, diesel was cheaper by 17% there. Petrol and diesel were selling at ₹ 53.47 and ₹ 39.69/litre in Sri Lanka, nearly 23% and 30% lower compared to India. In Nepal, retail prices of petrol and diesel were 12% and 19% lower than prevailing rates of auto fuels in India on the same day. In Bhutan, the selling price of petrol was nearly 10% lower compared to India, though difference in diesel price was less pronounced at 1%. While the retail price of petrol in Bangladesh was nearly at the same level as in India on that day, diesel price was 10% lower.  Crude oil prices are currently ruling at less than half their 2012-13 and 2013-14 levels. Petrol and diesel prices ruled at ₹ 68.31-73.16/litre and ₹ 48.63-55.48/litre respectively in 2013-14 when the price of Indian crude basket averaged at the staggeringly high level of $105.52/bbl. However, retail fuel prices still remain at the same level, though the price of Indian crude basket has fallen to below $47.86/bbl since then. However, the reason for India’s high fuel prices is quite clear. Taxes constitute 45%-52% of the retail price of auto fuels, far higher than what would be the incidence if petrol and diesel are brought under introduced GST and the highest tax rate of 28% is levied. The UPA government had decontrolled petrol prices in June 2010. Diesel pricing was deregulated by the NDA government in October 2014. The economic logic was that market forces should determine fuel prices and not the government. But the NDA government has taken away benefits of low oil prices from consumers, acting against the very logic propounded for the deregulation of the retail auto fuel market.

Maharashtra, Gujarat and UP top the list of states earning the most from VAT on petroleum products, fresh data from the PPAC, the statistical arm of oil ministry shows. Maharashtra earned ₹ 231.6 billion in 2016-2017 followed by Gujarat at ₹ 159.58 billion and UP at ₹ 158.5 billion in the same year. Collection of VAT on petroleum products contributed to over 8 percent of the state governments’ total revenue receipts last financial year and collection of excise duty on petroleum products by the centre contributed to over 24 percent of the centre’s total revenue receipts in the same period, PPAC data indicated. The central government earned over ₹ 3.3 trillion in 2016-2017 from levy of central excise on petroleum products, a growth of 30 percent over ₹ 2.5 trillion earned in the previous fiscal year 2015-2016. Andhra Pradesh and Madhya Pradesh charge the highest VAT on petrol and diesel but fall behind in total VAT collections as compared to states like UP, Tamil Nadu, Karnataka and Rajasthan due to the higher quantum of POL sold in the latter states. Andhra Pradesh registered 6,584 tmt of POL products sale in 2016-2017 as compared to 15,926 tmt of POL products sold in the same period in UP. UP earned more than Andhra Pradesh despite its significantly lower VAT on POL products. Similarly, 6,962 tmt of POL products were sold in MP in 2016-2017 as compared to 13,285 tmt of POL products sold in the same period in TN. TN earning more than MP despite its lower VAT rate on POL products. The central government wants to bring oil products within the ambit of the GST in the interest of consumers.

Petroleum imports including crude oil shipments accounted for 21 percent ($80 billion) of India’s total value of imports at around $380 billion last financial year. Petroleum products accounted for 10 percent of the country’s total outbound shipments in 2016-17. Petrol and diesel prices has seen an upward trend OMCs implemented daily fuel revisions from 16 June this year.

India’s trade growth for August is likely to record slight moderation while inflation could be higher, thanks to the high crude oil prices observed last month, global financial services firm Morgan Stanley has said. The Indian basket of imported crude oils gained nearly $3.50 a barrel even as petrol prices in the country touched their highest levels since the new government assumed office three years ago, data showed. The Indian basket, comprising 73 percent sour-grade Dubai and Oman crudes, and the balance in sweet-grade Brent, averaged $53.28 per barrel in August, 27 percent up as compared to $41.91 per barrel in the same month last year.

The effective tax rates for subsidised kerosene and cooking gas rose up to 5% but fell on average 10-12% for most other oil products such as fuel oil, naphtha and lubricants under the freshly rolled out GST, an analysis by the oil ministry showed. For subsidised cooking gas used by households, the effective tax rates went up by 4-5% in several states including Delhi, Rajasthan, Tamil Nadu, UP, Bihar, West Bengal, Karnataka, Jammu and Kashmir, Goa and Chhattisgarh. In many other states, tax rates remained unchanged or rose just a bit. The GST rate is 5% on domestic cooking gas, and 18% on non-domestic gas. In most states, the effective tax rates have fallen 3-6% on non-domestic cooking gas although in some states the rates have marginally risen too. The effective tax rate on subsidised kerosene, which attracts 5% rate under GST, has swelled 3-5% in several states including Rajasthan, West Bengal, Uttarakhand, Odisha, Jharkhand and Haryana. For kerosene used for industrial purpose, which attracts 18% GST, the effective tax rate has shrunk 10-12% in most states. The effective tax rate has substantially fallen in most states for fuel oil, naphtha, light diesel oil, bitumen and lubricants, all of which attract 18% GST. On average, the decline in effective tax rates under GST in most states is 12-13% for fuel oil, naphtha and lubes. The fall varies between 10-20% for light diesel oil. In case of bitumen, the decline is mostly limited to less than 2%.

Subsidised cooking gas or LPG price was raised by over ₹ 7/cylinder, in line with the government’s decision to hike prices every month so that all subsidises are eliminated by this fiscal-end. A subsidised 14.2 kg LPG cylinder now costs ₹ 487.18 in Delhi as against ₹ 479.77 previously, according to IOC. The government had asked state-owned oil companies to raise subsidised LPG prices by ₹ 4/cylinder every month to eliminate all the subsidies by March next year. Rates were, however, raised by ₹ 2.31/cylinder on the previous due date on August 1 and the oil companies have effected a larger hike to equalise that. Since the implementation of the policy of monthly increases of ₹ 2 from July last year, subsidised LPG rates have gone up by over ₹ 68/cylinder. A 14.2 kg LPG cylinder was priced at ₹ 419.18 in June 2016. The government had previously asked IOC, BPCL and HPCL to raise rates of subsidised domestic LPG by ₹ 2 per 14.2 kg cylinder per month (excluding VAT). The quantum has now been doubled so as to bring down the subsidy to nil. 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. The price of non-subsidised LPG or market-priced cooking gas has also been hiked by ₹ 73.5 to ₹ 597.50/cylinder. Rates were at the last revision cut by ₹ 40/cylinder. Simultaneously, the oil companies also raised prices of ATF by 4 percent, in keeping with rising global rates. ATF, or jet fuel, now costs ₹ 50,020/kilolitre, ₹ 1,910 more than ₹ 48,110 previously. This hike comes on the back of a 2.3 percent increase effected from August 1. Also, price of kerosene sold through PDS was hiked by about ₹0.25/litre. The government is adopting the same policy as in LPG for eliminating subsidy on kerosene. Since July 1 last year, rates have been hiked by ₹ 0.25/litre each fortnight. While Delhi has been declared a kerosene-free state, the fuel now costs ₹ 22.27/litre in Mumbai compared to ₹ 22/litre previously. Kerosene was on July 1, 2016, priced at ₹ 15.02/litre in Mumbai.

India’s Oil Minister said that fuel prices may come down by Diwali, which falls next month. The comments come amid criticism by opposition parties of a sharp rise in oil prices after the daily rate revision mechanism was introduced by the government recently.

The oil ministry is considering withdrawing from management committees of O&G fields, crucial bodies comprising nominees of the ministry, upstream regulator and the contractor, which oversee field development plans, annual work programme and budgets. The government hopes the proposed move would enhance ease of doing upstream business, but industry executives say that the presence of bureaucrats in these committees also has some benefits. The O&G fields auctioned under the previous policy are guided by a production-sharing contract, which provides for a management committee to ensure that the spending proposed and incurred by the operator of the field did not adversely affect the government’s revenue interests. There are about 250 production-sharing contracts operational in the country. For each contract, there’s a management committee comprising one nominee each from the oil ministry, the DGH, and all companies with stake in the field. DGH is the technical arm of the oil ministry and also acts as the upstream regulator.

India will offer larger areas with higher oil and natural gas reserves in the next auction of discovered fields later this year to curtail rising crude oil imports. India last year offered 67 small oil and gas fields holding about 625 million barrels of reserves in its first auction in six years allowing new entrants such as drug-makers and engineering companies to try their hand at boosting local production. The government also relaxed rules by allowing pricing freedom for oil and gas and a uniform policy for extraction of all hydrocarbons under a single license to encourage investments. Cairn Oil & Gas is producing more than a quarter of India’s crude oil output through the six blocks it operates in India. A 10 percent cut in oil imports by 2022, involves a lot of work ahead. A burgeoning appetite for energy has increased India’s import dependence to 82 percent last year from 76 percent five years ago. The IEA estimates India will be the fastest-growing oil consumer through 2040. The South Asian nation’s oil imports are estimated to touch $85 billion in the year to March 2018, according to India’s oil ministry. The government approved spending more than $452 million for appraising new areas with limited data. The DGH has created a data bank of the nation’s sedimentary basins and has launched an open-acreage licensing program, that gives explorers the freedom to carve out areas for exploration.

In a step that could further promote collaboration in the O&G sector between India and Myanmar, IOC’s Assam based subsidiary NRL dispatched the first consignment of HSD by land route, the oil ministry said. NRL has entered into an agreement with Parami Energy Group of Companies of Myanmar for the supply of diesel and collaboration in the retail petroleum sector of Myanmar. Under which NRL dispatched 30 mt of HSD through NH 37 across the Moreh custom check point on the Indian side and Tamu custom check point on the Myanmar side. OVL, GAIL (India) Ltd and Oil India Ltd have assets in the upstream sector as well as pipelines in Myanmar. In their effort to strengthen the oil and gas engagement, more Indian companies are planning to set up their offices in Myanmar soon. OVL has an office in Yangon.

IOC expects its largest and newest east coast Paradip refinery to outperform benchmark Singapore GRMs in the third quarter ending December. GRM is the difference between price of crude oil price and total value of petroleum products produced by the refinery. GRM is one of the parameters which indicate the physical performance of a refinery. Normalised GRM accounts for the gross refinery margin excluding the inventory gain or loss. Paradip refinery posted a capacity utilization of 88 percent for the first quarter ended June 2017 and is expected to run at 100 percent capacity from the second quarter of the current fiscal which is expected to boost the bottom line of IOC and improve the overall GRM of the company. Also, with Paradip being a coastal refinery, its inventory is expected to account for lower inventory losses. Paradip refinery has been configured to have a nelson complexity index of 12.2, second highest in the country. The nelson complexity index indicates the ability of a refinery to process heavy crudes. With Paradip refinery reaching average capacity utilization of 100 percent from second quarter, coupled with a high nelson index configuration, the refinery will be able to source cheaper heavy crudes leading to increased profitability, improved crack spread and higher GRM. The company also informed it plans to invest ₹ 200 billion as capex in the current financial year of which ₹ 45 billion will go for the refinery segment, ₹ 19 billion for pipeline, ₹ 60 billion for marketing and ₹ 30 billion towards Exploration and Production activities.

Rest of the World

Global use of petroleum and other liquid fuels will grow by nearly a fifth by 2040, driven by the transportation and industrial sectors, the US government said. Consumption is set to grow from 95 million bpd in 2015 to 104 million bpd in 2030 and 113 million bpd in 2040, according to the US EIA’s international energy outlook for 2017. That reference case would mean a 19 percent increase between 2015 to 2040. Countries outside of the OECD account for most of the increase, with demand rising by 1.3 percent per year, compared with a slight decrease for those in the group. OPEC countries will maintain or increase their combined market share of crude and lease condensate production, the EIA said.

Oil prices are expected to hold between $50 and $60/bbl as bloated global stocks fall after a deal between OPEC and other producers to trim output, BP said. The OPEC and other producers, including Russia, are reducing crude output by about 1.8 million bpd until next March in an attempt to support prices by cutting a glut of crude oil on world markets. OPEC top producer Saudi Arabia and several other countries have held talks in recent days on a possible extension of the deal.  Russia expected the 2018 price of Brent crude to be in the range of $45 to $55/bbl.

CNOOC Ltd is searching for partners to develop oil prospects deep into the Gulf of Mexico as the Chinese giant extends its global reach. After bidding alone for exploration rights in Mexico’s first-ever deep-water auction in 2016, CNOOC is seeking deals known as farm-outs, a common type of joint venture where a stake in an oil prospect is exchanged for help with drilling and production. The company has yet to choose partners. China has sought a foothold in crude production everywhere from Africa to Canada as it looks to ensure supplies to its fast-growing economy. Several Latin American countries like Venezuela and Brazil have taken advantage of China’s thirst for crude to secure investments or loans that haven’t always been easy to obtain elsewhere. CNOOC is the first foreign producer to seek a farm-out in Mexico since the opening of the country’s oil industry to competition, following decades of a monopoly in the hands of state-owned producer Petroleos Mexicanos.

Independent oil refiners in China’s Shandong province are planning to form a consortium to integrate their production of oil products and petrochemicals, according to a planning document. Since late 2015, China has allowed 31 mostly privately owned oil refineries to import crude oil, the majority of them based in Shandong province. With a combined capacity to import about 2 million bpd, their demand has upset oil trading flows in Asia and in the wider global crude market. Shandong Dongming Petrochemical Group and Shandong Qingyuan Group Co, both independent, or teapot, refineries in the province, will be among the key investors of the proposed group, according to the document that Shandong provincial authorities approved on September 1. The group will have the name Shandong Refining & Chemical Group Co, according to the document. Most of China’s independent refiners are based in the eastern province of Shandong.

Chinese refineries newly allowed to import crude oil will be penalized for reselling crude oil or expanding capacities without approvals, according to the NDRC. Qualifications will be stripped and trade permits revoked for the refineries that recently were allowed to use or import crude oil if they are caught in these violations, the NDRC said. Experts said the policy to crackdown on these violations is not new but the government was reaffirming the penalties amid growing concerns that abuses are getting more widespread. China has since late 2015 allowed about 31 companies, mostly privately-run refineries, to import crude oil in an unprecedented liberalization of China’s oil market, the world’s second-largest after the United States.

Venezuela published the price of its oil and fuel in Chinese currency in what it called an effort to free the socialist-run country from the “tyranny of the dollar,” echoing a plan recently announced by the President. The Venezuelan government would shun the dollar after the US announced sanctions that blocked certain financial dealings with Venezuela on accusations that the ruling Socialist Party is undermining democracy. The global oil industry overwhelmingly uses the dollar for pricing of products.

Royal Dutch Shell is set to end a century of oil production in Iraq by withdrawing from two of the Arab state’s flagship fields to focus on more profitable gas development. Shell’s retreat highlights the challenges foreign operators face with low-margin oil contracts in Iraq, an OPEC member that sits on some of the world’s biggest oil reserves and wants to boost production after years of conflict hindered development. The Anglo-Dutch firm said it had agreed with Iraq’s oil ministry to relinquish operations at Majnoon field to the government after unfavorable changes to fiscal terms. Shell is also selling its 20 percent stake in West Qurna 1 oil field in the south of the country. The field is operated by Exxon Mobil. Shell produced almost 20 million barrels of oil from Iraq during 2016, which accounted for about 3.5 percent of the firm’s total oil output last year, according to Shell’s annual report. Foreign firms in Iraq have long urged Baghdad to revise oil production contract terms to encourage development of reserves that Iraq estimates at about 153 billion barrels, the fourth biggest in the OPEC.

War-ravaged South Sudan is considering scrapping state subsidies on oil because it hasn’t been able to pay civil servants for four months and diplomatic staff abroad are being evicted over unpaid rent. Ending the subsidies would free up desperately needed cash. The government expects to receive $820 million from oil this year. Out of that, $453 million will go to neighbouring Sudan as payment for using its infrastructure for export; $183 million on the oil subsidy; and $166 million is allocated to the budget, which has a gaping deficit. State-subsidized oil sells at 22 SSP per liter, but severe shortages mean many people buy it on the black market for 300 SSP per liter. The SSP trades at about 17.5 to the dollar on the black market and 17.68 at the central bank.

Saudi Arabia will supply full contracted volumes of crude oil to at least five north Asian term buyers in October, while a sixth regional refiner was notified of cuts to its October Arab Extra Light supplies. Saudi Arabia is likely taking advantage of the lower refinery run rates and ample crude inventories in the United States in the wake of Hurricane Harvey, to redirect the allocation cuts from Asia to the US. Saudi Arabia plans to cut crude oil allocations to its customers worldwide in October by 350,000 bpd. In comparison, Saudi Arabia pledged last month to cut its September crude oil worldwide allocations by 520,000 bpd. Iran will reach an oil production rate of 4.5 million bpd within five years. Iran has been producing around 3.8 million bpd in recent months. Iranian gas production will reach 1.3 BCM/day and production of gas condensate will reach 864,000 bpd in the next five years. The boost in oil production will come from an increase of 420,000 bpd from the West Karoun oil field and an additional 280,000 bps from oil fields in central and southern Iran as well as the Falat Ghare oil company. Oil exports are expected to reach up to 2.5 million bpd within five years.

France will stop granting new exploration permits next year as it seeks to end all oil and gas production by 2040, according to a draft bill presented at a cabinet meeting. The move would allow the government to turn down more than 40 exploration requests already made, while some existing permits may be extended to respect contracts. France pumped 6 million barrels of oil in 2015, covering just 1 percent of its demand. Oil and gas exploration and production on French soil generates as much as €300 million ($358 million) in annual revenue, and accounts for as many as 5,000 jobs, directly and indirectly. Existing production licenses wouldn’t be extended beyond 2040 under the proposed law. France will end the sale of gasoline- and diesel-powered vehicles by 2040.

Iraq’s proposal to change the way it prices crude oil in Asia faces resistance from refiners who fear that longer lead times between pricing and deliveries will expose them to more risk. Iraq’s state oil marketer SOMO surprised traders by seeking feedback on plans to switch its Basra crude benchmark in Asia to pricing based off the Dubai Mercantile Exchange from January 2018, dropping quotes based on assessments by oil pricing agency S&P Global Platts. The move would affect the price of about 2 million bpd of crude oil supplies to Asia, mainly shipped to India, China and South Korea. Some buyers were concerned that almost 80 percent of the crude used to price DME Oman futures goes to China, reflecting the economics and fundamentals of just one Asian buyer.

US shale production is set to rise for the 10th month in a row in October, the US government said, spurred by US oil prices rising above the $50 a barrel threshold. Output across seven shale plays is forecasted to rise by nearly 79,000 bpd to 6.1 million bpd, according to the US EIA’s monthly drilling productivity report. North Dakota’s Bakken output is set to rise by 7,900 bpd to 1.06 million bpd, the highest since May 2016. In Texas, Eagle Ford oil output is set to fall by 9,000 bpd to 1.27 million bpd, the first monthly decline since April, the EIA said. Permian production is forecast to rise by nearly 55,000 bpd to 2.6 million bpd, the highest level in records dating back to 2007.

LPG: liquefied petroleum gas, BCM: billion cubic meters, Indian Oil Corp, BPCL: Bharat Petroleum Corp Ltd, HPCL: Hindustan Petroleum Corp Ltd, GST: Goods and Services Tax, NDA: National Democratic Alliance, UP: Uttar Pradesh, VAT: Value Added Tax, PPAC: Petroleum Planning and Analysis Cell, POL: Petroleum, Oil and Lubricants, tmt: thousand metric tonnes, MP: Madhya Pradesh, TN: Tamil Nadu, OMCs: Oil Marketing Companies, ATF: aviation turbine fuel, O&G: Oil and Gas, DGH: Directorate General of Hydrocarbons, IEA: International Energy Agency, HSD: High Speed Diesel, NRL: Numaligarh Refinery Ltd, OVL: ONGC Videsh, OPEC: Organization of the Petroleum Exporting Countries, ONGC: Oil and Natural Gas Corp, GRM: gross refining margin, EIA: Energy Information Administration, OECD: Organisation for Economic Co-operation and Development, bbl: barrel, SSP : South Sudanese pounds, bpd: barrels per day, NDRC: National Development and Reform Commission

Courtesy: Energy News Monitor | Volume XIV; Issue 16