Shades of Grey: The Annals of the Indian Coal Industry

Lydia Powell, Observer Research Foundation

Part I

The title of this essay is adapted from an insightful special article in the Economic & Political Weekly (EPW) by K V Subramanyam written in 1968.[1] The article uses a quote from the Burrow’s Committee Report of 1936 that observed: ‘coal trade in India has been rather like a race in which profit has always come first with safety a poor second, sound methods an also ran and national welfare a dead horse.’ This was a time when coal mining was in the hands of the private sector in India. If the Burrows Committee were asked to sum up India’s coal industry today (when it is almost entirely in the hands of the State), it would probably choose to replace only one word: the word ‘profit’ with the word ‘politics’. How has the Indian coal industry which has run for over 200 years managed to stay in the same place? Will the current attempt to swing the pendulum back from ‘politics’ to ‘profit’ through privatisation or other means actually change anything? Most importantly when and how will national welfare, safety and security (both of the coal mines and that of the people who work in them) come before profit or politics? The aim of the series of essays is to find some answers to these questions.

The first published reference to coal mining in India as recorded by Gee of the Geological Survey of India dates back to 1774 when Warren Hastings granted permission to mine coal in the Raniganj region.[2] Mining activity was initiated but the effort was not a commercial success. Coal mining had to wait for another 40 years for a revival (in 1814). But this time coal mining developed fast riding on the development of the Railways.  According to Gee there were 50 collieries in India by 1858.[3]  By 1868, 5 companies operating in Raniganj were producing over 492,700 tonnes of coal per year accounting for 88% of total output. When railway lines were extended to Dhanbad, Jharia coal field was developed and soon production from Jharia exceeded production from Raniganj.  By 1900 coal production in India was about 6.1 million tonnes (MT) out of which over 5 MT came from Jharia, Raniganj and Giridih (today’s Karharbari field) fields.[4] The Giridih field was in fact the first captive coal block belonging to the Railways which was the biggest consumer of coal.[5]  Even in those days access to land was among the most important problems faced by coal companies.  As the imperial government was yet to establish rights over minerals beneath the surface, royalty based agreements with land owners was the norm. But according to Gee, many early coal mining ventures failed because of expensive legal disputes on account of ‘complexities of land ownership in India’. Gee would not have to change this observation even if he were writing today. Writing in 1913, R R Simpson, Inspector of Mines and Mining Specialist to the Geological Survey of India observed that lack of demand and also the lack of infrastructure for transport to ports (for transport to overseas coal consuming industries) were initial problems faced by the industry.[6] He records 18 coal fields being worked out of which only 7 were said to be of some significance. This included coal fields in Raniganj and Jharia that accounted for 89% of total production.[7]  In this period, British coal arriving as ballast of ships was the biggest source of competition for Indian coal.[8]

The spurt in demand for coal during the First World War is said to have increased coal production in India to over 22 MT by 1919 which fell dramatically during the years of global trade depression in the early 1920s before recovering to over 28 MT just before the Second World War.[9] Unlike today, the fortunes of the Indian coal mining sector in the colonial era were tied to global economic conditions but this failed to have a positive impact on the Indian coal sector as it did on the rest of the coal industry. Some of the issues that held up reform of the industry continue to haunt the Indian coal industry even today. The primary hurdle was fragmented ownership. It not only held up consolidation but also sustained inefficient practices. For example, mineral rights of the numerous surface land owners were not questioned and consequently mining was carried out from a number of small isolated mines in valuable coal seams rather than in large mines that made greater geological and economic sense.[10] This resulted in the use of inefficient methods of exploitation that resulted in waste of valuable resources in barriers separating various concessions. Apparently no lessons were learnt from history. In fact history is being allowed to repeat itself as a tragedy almost a hundred years later through the ad hoc policy on coal block allocation. The captive coal allocation policy may have been the result of good intentions, (that of increasing the production of coal), but it compromised on geological integrity, economies of scale and most importantly national welfare. As observed by former Secretary of the Ministry of Coal P C Parakh in his recent book, captive mining assigned coal mines to several medium sized industries, which fragmented mining activities and consequently lost significant scale advantages in mining.[11] Parakh also notes that when ‘demand for coal blocks increased, the Ministry sub-divided blocks into smaller blocks without reference to geological or geographic features unmindful of the loss at the barriers’.[12] As recorded in Parakh’s book (with concrete evidence), numerous submissions to the Prime Minister’s office calling for a review of the allocation policy were ignored on account of pressure from political leaders of various persuasions including some serving in senior positions in the current Government.[13]

Returning to history, resentment over the absence of a level playing field for coal mining for western and Indian companies and the persistent conflict between labour and capital left deep scars on the industry which are visible even today.  According to Ratna & Rajat Ray, the Bengal Coal company which came under the ownership of the European Andrew Yule and Company ruined many Indian colliery and land owners in the Raniganj area in the early 1900s.[14] This marked the beginning of the battle between small Indian coal producers and larger western coal producers operating in India. The Indian coal companies were supplying to small local industries such as brick kilns and households while the latter were captive units of imperial economic interests which included but not limited to large Jute mills.[15] As recorded in detail by the authors, conflict, sometimes violent, between Indian and European coal companies characterised this period with access to transport for coal playing the role of a key weapon. They describe situations where the Indian coal producers attempted to block the transport of coal on the Damodar River to counter the tight control of access to Railway wagons by the European companies. At the height of this conflict, Indian coal producers formed the Indian Mining Federation affiliated to the Bengal National Chamber of Commerce in 1913 with 250 members owning 331 collieries accounting for a third of coal production in India.[16] The authors also point out that when it came to fighting labour unrest (which eventually grew into political unrest), the Indian and European coal producers joined hands and met demands for increase in wages with the threat of complete lock-out.[17] The reason lies in the structure of the coal industry. The proportion of wages to gross value of output is about 6% for petroleum but close to 50% for coal.[18] Obviously, this meant that labour and wages were a significant issue for the coal industry unlike petroleum which depended on capital.

[1] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[2] GEE, E R, 1940. History of Coal Mining in India, 10th August, Vol VI, No 3, pp 314-318

[3] GEE, E R, 1940. History of Coal Mining in India, 10th August, Vol VI, No 3, pp 314-318

[4] GEE, E R, 1940. History of Coal Mining in India, 10th August, Vol VI, No 3, pp 314-318

[5] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[6] SIMPSON, R R. 1914. Coal Fields of India, The Geographical Journal, Vol 44, No 1, July 1914, pp 82-85, Blackwell Publishing on behalf of the Geographical Society (with the Institute of Geographers)

[7] SIMPSON, R R. 1914. Coal Fields of India, The Geographical Journal, Vol 44, No 1, July 1914, pp 82-85, Blackwell Publishing on behalf of the Geographical Society (with the Institute of Geographers)

[8] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[9] GEE, E R, 1940. History of Coal Mining in India, 10th August, Vol VI, No 3, pp 314-318

[10] GEE, E R, 1940. History of Coal Mining in India, 10th August, Vol VI, No 3, pp 314-318

[11] PARAKH, P C, 2014. Crusader or Conspirator: Coalgate and Other Truths. Manas Publications: New Delhi, pp 98

[12] PARAKH, P C, 2014. Crusader or Conspirator: Coalgate and Other Truths. Manas Publications: New Delhi, pp 98

[13] For names of the politicians, refer to book by P C Parakh

[14] RAY, Ratna & RAY, Rajat. 1974. European Monopoly Corporations and Indian Entrepreneurships, 1913-22: Early Politics of Coal in Eastern India. Economic & Political Weekly, Vol 9, No 21, (May 25, 1974), pp M53-M55

[15] RAY, Ratna & RAY, Rajat. 1974. European Monopoly Corporations and Indian Entrepreneurships, 1913-22: Early Politics of Coal in Eastern India. Economic & Political Weekly, Vol 9, No 21, (May 25, 1974), pp M53-M55

[16] Ibid.

[17] RAY, Ratna & RAY, Rajat. 1974. European Monopoly Corporations and Indian Entrepreneurships, 1913-22: Early Politics of Coal in Eastern India. Economic & Political Weekly, Vol 9, No 21, (May 25, 1974), pp M53-M55

[18] GHOSE, Aurobindo, 1968. Interaction of Private and Public Sector: Case of Petroleum & Coal. Economic & Political Weekly, Vol 3, No 4 (Jan 27), pp 229-232.  The figure quoted is for a later period (1960s) but the proportion is unlikely to have been any different in the 1930s.

Part II

Part I of this essay that appeared in the ORF Energy News Monitor, Volume XI, Issue 16, ended with the observation that labour and wages have always been significant issues for the coal industry in India. The second part of the essay continues from there.

A casual survey of literature on mining labour in the Indian coal industry reveals that it is the result of a complex interplay of factors beginning with caste & class at the local level, colonial interests, nation building and politics at the national level and war, market forces and geo-politics at the global level. In the early periods of coal mining in India, Zamindars (land owning classes) who owned coal mines gave small holdings to labourers on condition that they work on the mines.[1] Mineral rights rested with the Zamindars and the miners paid royalty to the owners.[2] Most of these coal mining labourers were classified by the Chief Inspector of Mines as ‘semi aboriginals’, (probably the British way of referring to people from lower castes).[3] For reasons that are not evident, the British chose to see this system as a form of human exploitation.  This resulted in the passing of the Indian Mines Act in 1901 to enforce measures for labour safety and protection by Lord Curzon on the advice of Sir Thomas Holland.[4] The 1901 Act could be called the first incidence of interference by the State on the otherwise free Indian coal sector and it prohibited the employment of children and women in coal mines, regulated working hours and conditions of work and in addition enforced safety measures in the mines.[5]

As pointed out by Subrahmanyam, the immediate impact of this piece of legislation was not improvement of labour conditions across coal mines but the enhancement of differences in the cost of production between mines that worked under favourable conditions (geological, logistical etc) which were the large western owned coal companies and those that did not (which were invariably Indian owned small collieries).[6] There was no scheme for assistance to mines that were operating under challenging conditions. Nor was there any serious attempt to enforce these regulations. When the demand for coal increased after the onset of the World War, issues of safety and welfare of workers were set aside in order to increase coal production.  Contract recruiters known as recruiting Sirdars (or Arkattis) were used to recruit labourers for coal mining.[7] Chakrabarti observed that some of the land (and mine) owners became recruiters of labour as it was more lucrative than collecting royalties from coal mining.[8] He noted that a Coalfield Recruiting Organisation (CRO) was set up by the land owners with active connivance of the British Government to recruit workers on a temporary basis to meet wartime demand for labour.[9]  If we fast forward to the present, we will see that nothing has really changed in the context of labour use in coal mines. As pointed by an investigative report on the Dhanbhad coal fields, the launch of CIL as the world’s largest low cost coal producing company just prior to its initial public offering (IPO) in 2010 depended on the control of what the report calls ‘the undesired by-product’ of coal mining: the large mass of unruly industrial workers.[10] According to the report the re-composition of the mining workers in the coal belt was influenced by uneven development, technological changes and migration. The report notes that the concentrated local space of mining workers consisted of pauperised indigenous people (labelled as ‘adivasis’ today and ‘semi-aboriginals’ by the British in colonial times as observed earlier), the rural poor in the fringes of mining areas, which the report claims is the main recruiting base for the armed struggle against the State (labelled Maoism), workers in illegal mines, casual workers in the main (legal) mines earning 10% of their permanent peers, the families and unemployed off-spring of all of the above.

The report goes on to describe how this ‘peculiar composition of workforce and industry brought about specific forms of mediation of the class struggle’. The recruiters of mining labour evolved into money-lenders, labour contractors and then indulged in what we could call backward and forward integration in the coal industry as transport contractors, real estate agents and illegal miners. Contrary to common belief that this ‘mafia mode of production’ is one of the key barriers to reform of the coal sector, the investigative report claims that it is in reality a ‘complementary department’ of the coal industry through which the industry outsources control over low cost casual workers, strike breaking thug operations and strong integrated trade unions with political links.  The question that comes to mind at this point is whether the status of low cost coal producer was achieved through real efficiency gains or through the mechanism that essentially legitimised the ‘casualisation’ of labour to suppress wages. To answer this question let us look at available figures on the progress of the Indian coal sector (see chart).

Progress of the Indian Coal Sector: 1945-2011

Source: Volume of coal production and number of workers Sanhati (see reference)

The chart is an oversimplification of issues on account of two factors. It does not capture complex social, political, economic and geo-political factors that shaped outcomes and it does not differentiate between casual and permanent workers. However it may be treated, with caution, as a representation of reality from which it could lead to some conclusions: (1) production and production per worker increased by over 15 times in the 66 year period between 1945 to 2011 (2) the number of employees returned to 1945  levels after peaking in the 1970s. Shri Kumar Mangalam, who was India’s Minister for Steel and Mines at that time, was the architect of nationalisation of the coal industry. He thought that nationalisation was the only solution to poor labour conditions, absence of economically and geologically sound scientific methods for mining and low production volumes of coal.[11] If we overlook inaccuracies, we could say that the vision Late Shri S Mohan Kumar Mangalam was achieved in a limited sense. The reality was that dramatic progress on production concealed and eventually marginalised the absence of progress on the better mining practices and labour reform.

Shri Kumar Mangalam died in 1973 just as nationalisation was being completed and the coal industry was ‘orphaned and rudderless’ as the Late Shri Gulshan Lal Tandon put it.[12] The result was exploitation of the coal industry on a scale that had not been seen in its long history.  Part of the blame could be assigned to the oil crises of the 70s.

A cursory reading of the India’s Plan documents from the fifth plan period onwards reveal that the increased emphasis on coal as fuel for power generation began in the 1970s as part of India’s response to the increase in crude oil prices. During the Fifth Plan period (1974-79) the outlay for the coal sector was increased to ` 1025 crores (~$ 78.92 billion)[13] following the recommendations of the Fuel Policy Committee formed after the first oil crisis in 1973-74.[14] This was a tenfold increase over the outlay during the Fourth Plan period. The Sixth Plan document (1979-84) recommended a strategy of ‘self reliance’ based on coal, hydropower and nuclear energy to reduce the economy’s exposure to crude oil prices.[15] Even though the document cautioned that in per person terms India’s coal resources were small compared to that of countries like USA, Russia and China, implementation of the strategy of ‘self-reliance’ skewed in favour of coal at the expense of hydro power. This was in spite of the Plan documents pointing out the risk of increased foreign exchange exposure on account of import of coal powered generators. Returning to the chart, dramatic increase in coal production since Nationalisation in the 70s was the result of the tenfold increase in State investment in the sector.

G L Tandon observed that in the 1970s the ‘Indian Government was only interested in producing more and more coal and in the process sidetracked the building of an organisation and overlooked systems and rules needed to restore order and health of the industry’.[16] He also highlighted how unwanted manpower was thrust on the sector. At the time of independence, the Indian coal industry is estimated to have had over 320,000 people in about 900 coalmines that produced about 26.89 million tonnes (MT) of coal.[17] In 1966 the number of employees increased to over 425,400 and the production increased to 70.38 MT. G L Tandon noted that just before nationalisation (Coking coal in October 1971 and May 1972; and all non-coking coal mines in January 1973), the number of employees had fallen to well below 400,000. But it increased to well over 600,000 (or 1 million if casual labour is included) by November, 1975 when Coal India was formed. He noted with regret that the addition of contract unskilled labour and unwanted persons under political pressure and vested interests could not be checked. He narrated how ‘telegrams were sent to far off places inviting loved ones to come and join in the big bonanza and how in some cases the industry had a situation where sons had retired but fathers were still working’. The situation had not changed in 2004 as pointed out by P C Parakh in his recent book. [18] Parakh documents how the coal industry is constantly under pressure from various political leaders to employ workers of their respective parities, as labourers or as even as Directors on the Board, build speciality hospitals or give away coal to well-wishers of a political party.[19] One of the letters written by a Member of Parliament (in 2005) in response to denial of one such request (reproduced in the book) takes strong objection to the coal industry wanting to become competitive and argues that State owned companies are constitutionally required to meet social obligations.[20]

[1] Ministry of Labour & Employment, Government of India, 1969. Report of the National Commission on Labour

[2] CHAKRABARTI, Prabhas Kumar, 1990. Coal Industry in West Bengal. Northern Book Centre: New Delhi

[3] Annual Report of the Chief Inspector of Mines 1902

[4] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[5] Ibid.

[6] Ibid.

[7] Ministry of Labour & Employment, Government of India, 1969. Report of the National Commission on Labour

[8] CHAKRABARTI, Prabhas Kumar, 1990. Coal Industry in West Bengal. Northern Book Centre: New Delhi

[9] KUMARMANGALAM, S M. 1973. Coal Industry in India. Oxford & IBH: New Delhi

[10] Sanhati, 2011. Overview of Coal Mining In India: Investigative Report from Dhanbad Coal Fields, available at http://sanhati.com/excerpted/3798/ accessed on 9 October 2014

[11] CHAKRABARTI, Prabhas Kumar, 2002. Investment Decisions in the Indian Public Sector. Northern Book Centre: New Delhi

[12] G L TANDON, 2010. Reflections on India’s Coal Sector, Extract from the 3rd J G Kumaramanglam Memorial Lecture. Padma Bhushan Late Shri Gulshan Lal Tandon was former Chairman CIL & NLC

[13] Money of the day, average exchange rate in 1974 as given by the Reserve Bank of India

[14] Government of India, 1976.  Fifth Five Year Plan

[15] Government of India, 1981.  Sixth Five Year Plan

[16] G L TANDON, 2010. Reflections on India’s Coal Sector, Extract from the 3rd J G Kumaramanglam Memorial Lecture. Padma Bhushan Late Shri Gulshan Lal Tandon was former Chairman CIL & NLC

[17] Ministry of Labour & Employment, Government of India, 2002. Report of the National Commission on Labour, pp 88

[18] PARAKH, P C, 2014. Crusader or Conspirator: Coalgate and Other Truths. Manas Publications: New Delhi, pp 88

[19] Ibid. pp 102-105, 131, 132, 134

[20] Ibid. pp 237

Part III

Part II of this essay that appeared in the ORF Energy News Monitor, Volume XI, Issue 17, offered glimpses of the coal sector just before and after nationalisation in the 1970s. Part III of the essay continues from there.   

The dramatic increase in coal production after nationalisation in the early 1970s had three major irreversible consequences in the context of India’s energy supply in general and the role of coal in energy supply in particular. The first is what we may call the carbonisation of India’s energy basket. In the 1960s coal and hydropower had roughly equal share in power generation. By the 1990s, coal’s share in power generation increased to roughly 70%. By most projections the share of coal in power generation is unlikely to change in the next two decades. Carbonisation of India’s energy basket is seen by many observers, especially those from industrialised countries, as a liability in the context of climate change.  Others, who are probably more aware of India’s socio-economic and socio-political choices and limitations, see carbonisation as the inevitable price that had (has) to be paid to offer a better life for millions of people. Irrespective of the validity of the arguments for and against coal, the dominance of a single fuel for power generation has increased India’s energy risks.  India is now vulnerable to disruptions in power generation on account of even small changes in the price of coal, policy on coal and the physical availability of coal.

The second is the technological shift towards opencast mining. As pointed out by Padma Bhushan late Shri G L Tandon, the dramatic shift towards open cast mining after nationalisation reduced the share of under-ground mining from 74% in 1975 to about 10% now.[1] Shri Tandon lamented that if well managed Western and Indian coal companies such as Bengal Coal Company, McNeill & Barry, Turner Morrison, Chanchani, Worah and others had been allowed to continue their operations independently, several decades of under-ground mining technology / experience may not have been lost. This shift has broader implications in the context of sustainable mining practices as well as the extent of accessible coal reserves available for the future.  A short digression into the past explains why this is unlikely to be reversed.

Compromise on scientific mining practices began almost 50 years prior to nationalisation when the urgency of World War I pushed demand for coal. As Subrahmanyam puts it, ‘even leading mining companies that were financially strong indulged in ‘slaughter mining’ and used up high quality metallurgical coal for burning in Railway and Marine engines.[2]  Lord Curzon commissioned a report by the British Mining engineer Treharns-Rees in 1918 to take stock of the situation. The report recommended compulsory stowing[3] to obviate dangers arising from ‘slaughter mining’ and the creation of a legally empowered authority to enforce it. The report also recommended that the large quantity of ‘unmarketable’ coal that was accumulating in the mines be used for pit-head power generation.[4] The Coalfields Committee endorsed these recommendations in 1920 but no action was taken.  One of the reasons was that just after war the coal market shifted from a seller’s to a buyer’s market.  When the seller was king ‘everything black including stones and rubbish was dug out and sold to the helpless consumer’.[5] The situation is not very different today. It is very common to see news items on the conflict between NTPC a big consumer of thermal coal and CIL over stone, muck and rubbish being loaded and sold as coal.[6] But when buyer became king after the end of the war, only coal desired by the customer in terms of quantity and quality was dug out.  Unrecovered coal was left behind in such a state that it could not be recovered at any time in the future.[7] This unrecoverable coal is burning even today and is often featured in western news papers as part of their coverage of third world resource and environmental tragedies.[8]

This raises two critical questions in the current context. The first is over how much recoverable coal reserves the country actually has, given that careless and unscientific mining practices have permanently lost some of the resources. The answer to this ranges from just 10 billion tonnes (BT) to over 100 BT. The wide range only tells us that it is not really known. The second is over the logic of compromising on the natural integrity of the coal mine to either allocate blocks to users or to auction them off. As pointed out by Partha Bhattacharya, former Chairman of CIL captive coal mining by consumers is not practised anywhere else in the world and is not optimal from economic, geological and ecological perspectives as it requires coal reserves to be artificially sub-divided.[9] With the unravelling of what is labelled as India’s ‘coal-gate’, narratives on how coal mining should be auctioned off to private parties who are the only saviours of the coal industry are emerging. If those who embrace this narrative care to look back at India’s very long history of coal mining, they would learn that the private sector which had the longest period of control over coal mining in India did not really do a better job in the context of conservation of resources, sustainable mining practices, labour safety and reform or even on prices. In fact many of legacy burdens that the coal sector shoulders today were creations of the private sector.

The third consequence of the dramatic increase in coal production in the 1970s follows from the first two and it is about the plight of the low cost casual labour that underwrote this increase. These impoverished masses are the collateral damage of the first two shifts described above and despite this they are not part of any discussion on coal in India, be it the high politics of energy security or the high finance of coal company listing. But the fact that they are important factors in the economics of India’s coal production cannot be ignored even if one is averse to people centric (‘leftist’) views. Suppression of wages for casual workers that contributes to making CIL a low cost coal producer has a long history stretching back to the early 1990s. The Noycee Committee appointed in 1925 in response to the loss of competitiveness of Indian coal in the global market concluded, presumably under the influence of the coal producers lobby, that the high Railway rates were to blame for the loss of competitiveness. As a solution it recommended that since Indian coal is not amenable to washing a Coal Grading Board would issue certificates of quality to exported coal.[10]

This introduced a layer of bureaucracy into the coal sector to assess coal quality, a mechanism that thrives even today.  The comment that ‘Indian coal workers were lazy and that the increase in wages granted a few months earlier had made them lazier leading to loss of competitiveness of Indian coal in the global market’ offered by a western owned coal producer to the Noycee Committee is an illuminative testimony of the disregard for labour in the coal sector.[11] As the coal industry consolidated and grew after the First World War, low cost labour continued to be seen as a substitute to investing in competitiveness enhancing technologies and scientific management practices. In 1939 when the Coal Mining Safety Act was passed World War II broke out and the rationale for reform was destroyed by the dramatic increase in demand for coal.  Coal pricing was brought under control in 1944 and prices were fixed by a committee consisting of private producers.  According to Subrahmanyam the upper limit to these prices was the ‘sky’.[12]  By the 1960s this changed into a form of cost plus method of price fixing which continues in slightly evolved form even today.  When the ceiling on prices was held high and the floor on costs were held low with poorly paid casual labour, a huge gap emerged in between that was padded with administrative, commercial and technical inefficiency. The controlled pricing regime also opened up opportunities for a grey market to be created for lower grade coals with secret discounts offered to consumers from the power generation to brick manufacturing sectors. Despite nationalisation in the 1970s, what we have today is just an extrapolation of the coal industry that had existed prior to nationalisation.  The point to note here is that the Indian coal industry is mounted on the backs of low cost casual labour which in turn is loaded with bricks of inefficiency to touch the ceiling that represents artificially high prices. Calls for reform, liberalisation and privatisation of the coal industry would do well to acknowledge that this path dependent set-up has ‘locked-in’ and institutionalised much of the inefficiencies. The tragedy is that all this has consequences on national welfare. As inefficiency packed costs are passed off to the end consumers of coal, we have uncompetitive prices for coal based outputs such as power generation notwithstanding the low cost labour at the bottom.  We cannot ‘make much in India’ unless this changes.

Returning to the quote from the Burrows Committee Report of 1936 where this essay started, ‘coal trade in India has been rather like a race in which profit (politics since the 1970s) has always come first with safety a poor second, sound methods ‘an also ran’ and national welfare a dead horse.’ Unless this list is reversed with national welfare coming first, sound methods coming second, safety third and profits coming last, someone could be writing the same story fifty years from now.

[1] TANDON, G L 2010. Reflections on India’s Coal Sector, Extract from the 3rd J G Kumaramanglam Memorial Lecture. Padma Bhushan Late Shri Gulshan Lal Tandon was former Chairman CIL & NLC

[2] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[3] Filling the voids created by extraction of coal with incombustible material

[4] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[5] Ibid.

[6] See for example story titled ‘CIL, NTPC go for arbitration over coal quality’ dated 22 February 2014, available at http://www.dnaindia.com/money/report-cil-ntpc-to-go-for-arbitration-over-coal-quality-1964109

[7] Ibid.

[8] See for example story titled ‘Living amidst the Fires’ by Wall Street Journal http://blogs.wsj.com/photojournal/2010/04/01/living-amid-the-fires/

[9] BHATTACHARYA, Partha, 2014. ‘Opportunities in a Crisis’, Indian Express, 29 September 2014

[10] SUBRAHMANYAM, K.V. 1968. Shades of Grey: The Annals of the Coal Industry. Economic & Political weekly, Vol 3, No 40, October 5, pp 1515-26

[11] Ibid.

[12] Ibid.

Concluded

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 16

Courtesy: Energy News Monitor | Volume XI; Issue 17

Courtesy: Energy News Monitor | Volume XI; Issue 18

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GAS PIPELINES EXPAND INTO NEW MARKETS

Monthly Gas News Commentary: December 2018

India

The Centre will initially spend ₹ 700 billion to spread gas pipelines across the country, and is working out plans to expand gas network to Myanmar through Bangladesh. The central government is promoting gas-based economy which needs a massive network of pipelines for transportation of natural gas to various corners of the country. India is planning to expand gas pipeline network to Myanmar through Bangladesh.

The ₹ 34 bn Bokaro-Angul gas pipeline will help pave the way for supply of natural gas for households, vehicles and industries across 11 districts of Odisha and Jharkhand, oil ministry said. The Bokaro–Angul section, part of the larger 2,650 km Jagdishpur–Haldia & Bokaro-Dhamra (JHBDPL) pipeline, popularly known as the Pradhan Mantri Urja Ganga project. The Bokaro–Angul section is being constructed by GAIL (India) Ltd and will have a total length of 667 km, of which 367 km will be in Odisha and 300 km in Jharkhand. It will cover five districts in Odisha — Angul, Sundargarh, Jharsuguda, Sambalpur and Debagarh — and six districts in Jharkhand — Bokaro, Ramgarh, Ranchi, Khunti, Gumla, Simdega. The project is scheduled to be completed by December 2020. The Pradhan Mantri Urja Ganga is slated to pass through Uttar Pradesh, Bihar, Jharkhand, West Bengal & Odisha. The pipeline is further being extended from Baruani in Bihar to Guwahati Assam with a length of 730 km. It is expected to act as a gateway for pipeline infrastructure in North East. PNGRB has already awarded the Geographical Areas for development of City Gas Distribution networks in these 11 districts to different entities and the Bokaro–Angul section will help expand the supply of natural gas to these areas. GAIL has already placed the order for line pipes for the section and delivery has commenced at the site. Work will be executed in five sections and five contractors have been engaged for the purpose. This year, Delhi and Mumbai crossed the one million mark in piped natural gas connections. Beyond the two cities, access to the fuel will grow further to 402 districts across 27 states and Union Territories, covering 70 percent of the country’s population, once the area under the tenth round of bidding is connected. This is a long way from 1857, the year of the great revolt against the Raj, when a British joint stock company called Oriental Gas Company started offering piped natural gas supplies in Calcutta (now Kolkata) for commercial and domestic purposes. After that, parts of Gujarat and Tripura also had piped gas networks, owing to the local availability of natural gas in these areas. In fact, BG, now merged with Shell globally, set up Gujarat Gas Company in 1980 to develop CGD networks in Surat and Bharuch. BG exited Gujarat Gas by offloading its stake to Gujarat State Petroleum Corp in 2013 and subsequently exited MGL, its joint venture with GAIL and the Maharashtra government. But such exits do not reflect the steady growth of the CGD business in India. Going forward, however, CGD providers may struggle to replicate Delhi and Mumbai’s numbers, principally because smaller cities may not have the same population sizes. Besides, the model that worked for these two cities evolved even before CGD rights were bid out. IGL, a joint venture of GAIL, BPCL and the Delhi government, has held the rights to the CGD network in Delhi since 1999, seven years before the legal framework for the business was laid out under the PNGRB Act in 2006. Prior to that, GAIL was managing gas supply business in Delhi. MGL, the BG-Shell joint venture till the multinational exited in 2018, also had equity participation from GAIL and the Maharashtra government. It was formed four years before IGL in 1995. The government plans to increase the share of natural gas to 15 percent in the overall fuel basket of the country. A major challenge for CGD players, however, is sourcing natural gas. For players like GAIL and Adani, which have access to natural gas and pipelines, it may be easier to supply gas to their subsidiaries. For Delhi and Mathura, there is the advantage of a Supreme Court order that gives them preference in natural gas allocation because of the fuel’s environmental benefits. Though use of bio gas as CNG for vehicles will improve gas availability for CGD networks, pricing and demand will continue to be the deciding factors.

With nearly 3,000 new compressed natural gas-run vehicles added on city roads every month, authorities at MNGL are concerned about meeting the growing demand. The company currently has 55 CNG stations in Pune. According to MNGL, at least 25 new CNG stations are required in the city to keep up with the rising demand. While the Pune Municipal Corp offered nine parcels of land to develop CNG stations, MNGL said that most plots are not feasible. According to MNGL, the CNG stations running at optimal capacities coupled with the long lines are also coming in the way of more conversions.

Top Indian gas importer Petronet LNG Ltd is looking to sign a deal in a year’s time to buy at least 1 mt of US natural gas annually for a period of up to 10 years, as it pushes to diversify its supply sources beyond the Middle East. As part of any deal, the firm could potentially take a stake in a US LNG project. Petronet currently runs a 15 mtpa LNG regasification site at Dahej in the western state of Gujarat and a 5 mtpa plant at Kochi in southern India. It has long-term deals to buy 10 mtpa of LNG, with 8.5 mtpa of that coming from Qatar’s RasGas. Petronet is in talks with various companies including Tellurian Inc about a potential US deal. Singh had said in November that Petronet and ONGC Videsh Ltd were jointly in talks to buy a stake in Tellurian’s proposed Driftwood project in Louisiana. Natural gas accounts for about 6.5 percent of India’s overall energy needs, far lower than the global average. The government wants to lift that to 15 percent in the next few years. A glut of natural gas in the US in the wake of the rapid development of shale fields there has kept benchmark US prices for LNG at almost half Asian levels. Petronet is in talks to invest in exploration and LNG projects in Qatar, as well as continuing to scout for opportunities in Bangladesh and Sri Lanka.

Petronet plans to invest ₹ 21 bn to expand its terminal capacity in Dahej, Gujarat, from 15 mtpa to 20 mtpa in the next two or three years. Of the total, ₹ 13 bn would be used to expand the Dahej terminal, while ₹800 crore will be spent on building LNG storage tanks. Petronet LNG, which built India’s first LNG receiving and regasification terminal at Dahej, operates another terminal in Kochi. The Kochi terminal has a capacity of 5 mtpa. The company is in the process of building a third terminal, at Gangavaram, Andhra Pradesh.

India is considering building emergency stockpiles of natural gas, on the lines of strategic oil reserves, to deal with supply disruption amid the country’s growing dependence on fuel and its import. The government wants domestic consumption of natural gas, a cleaner fossil fuel, to rise two-and-a-half times by 2030 and is encouraging big public and private investments in gas production, import, transport and distribution infrastructure. Local demand increased 5.5% between April and October to 35.1 billion cubic meters, increasing dependence on imports to 47% of total consumption from 44% a year earlier. The person is part of a panel formed by the petroleum and natural gas ministry to evaluate the need for strategic gas storage and prepare a plan to go about building and managing these. The panel has representatives from ONGC, GAIL and Oil Industry Development Board. Most heavy gas consuming countries already have natural gas storage in place, primarily for supply security. About 30% of gas storage capacity is in the US, a major producer and consumer of natural gas. Russia, Ukraine, Canada and Germany together account for another 40%. China, a late entrant to the game, too is fast building gas storage facilities. About three-fourths of underground gas storage is in depleted gas and oil fields while the balance is distributed between salt caverns and aquifers. The first storage in India could come up at a site connected to a pipeline. The reserve would store imported gas, which could be released when needed in the domestic market.

ONGC and OIL spent over ₹ 130 billion on 115 oil and gas discoveries which were taken away from them by the government for auctioning to private companies. The government took away so-called idle small and marginal discoveries of ONGC and OIL and auctioned them to private firms under DSF bid rounds. Under DSF bid round-1, 67 discoveries, mostly of ONGC, were auctioned, while in the second round, bids for which are due next month, another 48 finds are being auctioned. ONGC and OIL are not compensated for the amount they had spent on discoveries of these oil and gas reserves. Unlike state-owned firms, the private players are allowed pricing and marketing freedom to make these discoveries viable. ONGC and OIL have stated that they could not produce from the discoveries as they are uneconomically at current cap prices. Under DSF-I, 47 companies participated in the bidding process.

Rest of the World

China is expected to consume 270 bcm of gas in 2018. China’s capital will use as much as 130 mcm/day during the peak winter heating period. Beijing is now the world’s second largest gas-consuming city. China’s LNG imports hit record levels in November, customs data showed, with traders rushing to buy the fuel as households and businesses crank up their heating over the freezing winter months. LNG imports totalled 5.99 mt in November, up 48.5 percent from the same month last year, data from the General Administration of Customs showed. That surpassed the previous record of 5.18 mt hit in January this year. China has been pushing to switch parts of the country to gas for heating, shifting away from coal as it pushes to clean up its environment. For the first 11 months of 2018, LNG imports were up 43.6 percent from a year earlier to 47.52 mt, on track to beat 2017’s annual record of 38.13 mt. Meanwhile, Chinese exports of gasoline and diesel fell in November from the year before, the data showed, with local refiners reducing production as profit-margins fall. China exported 1.23 mt of diesel in November, down 37.5 percent year-on-year.

Several large LNG players have tried to offload their obligation to buy future cargoes from the US shedding excess commitments made years ago in the rush for new sources and commercial terms for the fuel. The sale of multi-year “strips” of LNG cargoes represent portfolio adjustments by the buyers rather than backlash against US gas, several Asian and Europe-based traders said. But it was a timely reminder that there is only so much US LNG, which can be more commercially attractive than gas from other regions, that the market can absorb, even as new investment is being prepared for more US export plants.

US LNG export capacity is on the brink of doubling in 2019, which will boost the super-cooled fuel’s influence on the US natural gas market, where volatility surged in 2018 after several years of slumber. LNG exports have been the fastest growing source of US natural gas demand since the country started ramping up exports in 2016, and is expected to expand deliveries in coming years as several more export terminals enter service. Its imprint is being felt in the US gas futures market, which in November experienced its longest stretch of extreme volatility in nine years due to demand, low inventories and unseasonably cold US weather. LNG currently accounts for just a small amount of overall domestic gas demand. But as the country opens more facilities for export to meet growing needs abroad, analysts said more ups and downs in prices are expected. The US is on track to export about a trillion cubic feet of LNG by year-end, or about 3 percent of overall US gas demand in 2018. But LNG exports are expected to rise to 5 percent of overall US gas demand in 2019 and to 10 percent in 2024, according to the US Energy Information Administration, boosting LNG’s potential to affect prices.

Implied volatility for US natural gas futures tumbled 40 percent an all-time high a month ago as weather forecasts for the rest of the year turned warmer, reducing the risk that the amount of gas in storage will run short this winter. The market worried the cold would cause consumers to burn more gas than usual for heat, forcing utilities to pull large amounts of the fuel from already depleted storage facilities.

Tellurian, which is developing a LNG export project on the US Gulf Coast, has signed a preliminary deal to supply LNG to commodities trader Vitol. The deal prices the LNG against Platt’s Japan Korea Marker, the first time the daily assessment of spot LNG prices in northern Asia has been used for a long-term offtake agreement, according to S&P Global Platts. In the US, such long-term deals, critical to the financing of export terminals, are priced against the US Henry Hub gas price. Most deals elsewhere are priced against oil, while some are priced against other natural gas hubs. The MoU is Tellurian’s first preliminary offtake deal for its Driftwood LNG project. An MoU usually leads to a binding Sales and Purchasing Agreement. Vitol aims to buy 1.5 mtpa of LNG from Driftwood for 15 years once operations begin. The export terminal in Louisiana aims to have a capacity of 27.6 mtpa and to start operations by 2023. Tellurian had previously said it was in talks with about 25 prospective customers including Total, General Electric and Bechtel, which has a $15.2 billion contract to build the LNG terminal.

US oil major Exxon Mobil Corp has withdrawn its WCC LNG export terminal in Canada from the environmental assessment process, it said, signaling that the project has been shelved. The decision to pare its LNG project portfolio follows the go-ahead of a giant Royal Dutch Shell-led project in British Columbia, and Exxon’s focus on LNG projects in Asia, the Middle East and the US. Global LNG demand is expected to double to 550 mtpa by 2030, as countries like China move away from coal to cleaner fuels. The top import market for LNG is northeast Asia. Exxon Mobil Corp and the world’s top miner BHP Billiton said they approved development of the West Barracouta gas field in the Gippsland Basin in Australia, to bring fresh gas to Australian domestic markets. Exxon said the project, located off the shore of the state of Victoria, is part of its continuing investment in the Gippsland Basin, an area rich in oil and gas. BHP will invest about A$200 million ($144.36 million) in the gas field, the miner said. Rising natural gas prices has become a political issue in Australia as households and manufacturers complain of higher costs, especially in the country’s more populous east coast. The Gippsland Basin joint venture continues to supply about 40 percent of east coast Australian domestic gas demand, Exxon said, adding that front-end engineering design work for the project was completed and key contracts awarded.

Russian gas giant Gazprom said it had begun operations at a third and final unit at its Bovanenkovo gas field on the Arctic Yamal peninsula, allowing it to boost natural gas production. Gazprom said it had increased the capacity of the Ukhta-Torzhok gas pipeline, aimed at facilitating Russian gas exports to northern Europe, including via the Nord Stream pipeline. Gazprom plans to export record-high natural gas volumes of 200 bcm to Europe this year. The company said that with the launch of the final unit, Bovanenkovo will reach a projected capacity of 115 bcm of gas per year. The gas field with reserves of just under 5 trillion cubic meters – on par with global annual gas demand – is key to the company’s efforts to tap new deposits, apart from its traditional producing region of Western Siberia. Last year, it produced 82.8 bcm of gas.

Russia’s largest non-state natural gas producer Novatek will start producing LNG on the shore of the Baltic Sea in February, the contractor, Atomtekhenergo, said. Novatek, along with Gazprombank, is building an LNG plant and terminal in the Baltic Sea port of Vysotsk with a capacity of 660,000 tonnes of the frozen gas per year. The plant’s capacity could be expanded to 800,000 tonnes in 2021. Novatek is the main owner of Russia’s largest LNG project, Yamal LNG, with produces gas at the rate of 16.5 mtpa.

Australia overtook Qatar as the world’s largest exporter of LNG for the first time in November, Refinitiv Eikon data showed. In November, Australia loaded 6.5 mt of LNG for exports while Qatar exported over 6.2 mt the data showed. Qatar plans to boost its LNG capacity by early 2024 to 110 mtpa up from its current production of 77 mtpa by adding a fourth LNG production line. Qatar, which exports around 600,000 barrels per day of crude oil, said it would leave the OPEC to focus on gas. Wood Mackenzie analyst Nicholas Browne said the drop in Qatari LNG exports in November was due to maintenance, making Australia’s time at the top limited. However, Australia’s hold on the top spot could be fairly short as LNG exports are being blamed for rising domestic gas prices, which has become a political issue in the country. The oil companies that Qatar selects to expand its north field natural gas reservoir will be announced in mid-2019. Qatar plans to build four additional LNG gas trains in mid-2019.

Iraq needs at least two years to boost the country’s gas production to stop importing Iranian gas used to feed its power stations. Iraq’s gas output is expected to reach 1.3 mcf/d by the end of 2020, an increase of 400 mcf/d from current levels. The US said that Iraq can continue to import natural gas and energy supplies from Iran for a period of 45 days as long as Iraq does not pay Iran in US dollars. Sanctions on Tehran’s oil sector took effect on 5 November. The expected rise in gas production would come from two new projects, including a $367 million deal with General Electric reached in April to process natural gas extracted alongside crude oil at two fields in southern Iraq. The project is expected to start producing 160 mcf/d in two years, Abdul Ghani said. Iraq is expected to sign another deal in early 2019 to build the Artawi gas plant in the south which is planned to produce around 300 mcf/d by end 2019. Iraq’s gas development plans have long focused on BGC, a $17 billion joint venture between Royal Dutch Shell, state-run South Gas Company and Mitsubishi. Iraq is seeking to reach gas production of around 2000 mcf/d by the end of 2023, including 1.43 mcf/d from the Basra Gas Co. and additional 500 mcf/d from other future projects in the south. South Gas Co is still in talks with US energy company Orion Gas Processors over the economic and technical aspects of a final deal to capture and process 100 million to 150 mcf/d of natural gas extracted from Nahr Bin Omar southern oilfield. Iraq signed a Memorandum of Understanding with the US company to build facilities to capture the gas from the field located in southern Iraq and to transform it into usable fuels.

Israel, Greece and Cyprus will sign an agreement early next year to build a pipeline to carry natural gas from the eastern Mediterranean to Europe, while the United States pledged its support for the ambitious project. The $7 billion project, expected to take six or seven years to complete, promises to reshape the region as an energy provider and dent Russia’s dominance over the European energy market. Israel has been developing natural gas fields off its Mediterranean coast for the past decade. Its “Tamar” field already is operational, while the larger “Leviathan” field is expected to be operational next year. While most of its gas is used domestically, it has signed export deals with Egypt and Jordan and has its eyes on the larger European market. The proposed pipeline would allow Israel and Cyprus to export their recently discovered offshore reserves to Italy and eventually to the rest of Europe. Greece, which would act as a conduit for the gas to the continent, could also use the pipeline to convey any hydrocarbons potentially found in its own waters.

A line to connect a planned German terminal for LNG in Brunsbuettel to the bigger gas grid needs to be build by the project company, not the gas grid operator, Germany’s network regulator Bundesnetzagentur (BnetzA) said. The regulator, following the completion of its €6.9 billion ($7.9 billion) gas network expansion plan for 2018-2028, said the move did not preempt a decision on whether the planned terminal was needed or could be realised. German LNG Terminal, a joint venture of gas network operator Gasunie, tank storage provider Oiltanking, and storage tank company Vopak, plans to make an investment decision on the Brunsbuettel terminal next year.

Poland’s dominant gas firm PGNiG said that it had finalised a 20-year deal for deliveries of LNG from the US to Poland’s terminal in the Baltic Sea. PGNiG said that annual supplies of 2 million tonnes of LNG, which will be delivered free-on-board, will start no sooner than 2023 when the Port Arthur production facility in Texas will be completed. The contract is the result of an agreement PGNiG signed with US. Port Arthur in June. Poland has increased supplies of LNG in the past few years in order to reduce its reliance on Russian gas. Poland consumes around 17 bcm of gas annually and more than half of it comes from Russia’s Gazprom under a long-term deal which expires in 2022 and which Warsaw does not plan to extend.

Energy group Uniper entered agreements with Japanese shipping group Mitsui OSK Lines to handle potential deliveries of LNG into Germany. Discussions about LNG have flared up recently as the German government wants to diversify away from pipeline gas arriving from Russia, Norway and the Netherlands. Suppliers, most notably Qatar and the US have expressed interest. In its efforts, Uniper is banking on Wilhelmshaven – which is close to its storage facilities – as the site for a German LNG terminal and has previously said that it was in talks with interested parties to build a FSRU. Uniper said that Mitsui intended to own, operate and fund the FSRU, which has a planned send-out capacity of 10 bcm/year and LNG storage capacity of 263,000 cubic meters. The unit could be in operation as early as the second half of 2022, Uniper said. Uniper said it also entered into a binding transportation agreement with Mitsui, under which the group will provide Uniper with 180,000 cubic meters of LNG shipping capacity from December 2020. It will use the capacity partly to optimize LNG volumes from Freeport in the US, the company said.

The French government said it had asked utility Engie to take hedging positions to ensure gas prices do not rise until June next year. Unlike power prices, which typically move once a year, gas prices move every month in France and are set using a formula that takes into account production costs. Many French governments have postponed tariff increases to protect consumers and their own approval ratings in the past, but legally the government has no authority to set prices. The environment ministry said it wanted to ensure Engie’s gas prices do not change until June 2019 but gave no explanation on the new timeframe of the requested price freeze.

BP in Trinidad and Tobago gave the go-ahead to two new gas developments, Cassia compression and Matapal, offshore Trinidad, it said. BP will build a new platform, Cassia C, and first gas from the facility is expected in the third quarter of 2021. Matapal will be a three-well subsea tie-back to the Juniper platform. With production capacity of 400 million standard cubic feet of gas per day, first gas from Matapal is expected in 2022, BP said.

Royal Dutch Shell said it would expand the Shearwater gas hub in the British North Sea, its seventh project to get the green light in the aging basin this year. The project, a joint venture with Exxon Mobil and BP, will include a modification of the Shearwater platform to allow production and processing of wet gas as well as the construction of a 37 kilometre pipeline from the Fulmar Gas Line to Shearwater, Shell said. The pipeline installation, which will enable wet gas to flow into the Shell Esso Gas and Associated Liquids pipeline, is scheduled for 2019, while the platform expansion is scheduled for the following year, according to Shell. At peak production, the wet gas export capacity of the Shearwater hub is expected to be around 400 million standard cubic feet of gas a day, or roughly 70,000 barrels of oil equivalent per day.

Pakistan LNG said commodity traders Trafigura and Gunvor had made the lowest bids in a tender to supply three cargoes of LNG between late January and late February. It said Trafigura made the lowest bid to supply a cargo on 21-22 January at 14.4 percent of Brent crude oil prices, Gunvor’s bid for the 3-4 February cargo was at 15.8 percent and Trafigura again bid the lowest for 21-22 February at 14.8 percent. Vitol Bahrain had bid to supply two cargoes but at higher prices, according to a Pakistan LNG commercial evaluation document. BB Energy had sent in bidding documents but they did not technically qualify. The prices, expressed in the document as crude oil slope or the numerical percentage of Brent crude price, are a valuable pointer for the opaque spot LNG market. A cargo priced at 14.4 percent of Brent is about $8.66/mmBtu. Spot Asian LNG prices for January were heard at $9.80/mmBtu although they have since fallen to closer to the $9.00/mmBtu mark. Pakistan LNG launched a tender for the three cargoes in November, the first for LNG since June.

A South Korea-based company has proposed building a terminal on Australia’s east coast to import LNG the fifth proposal for such a project in the world’s No.2 LNG exporter. The proposals have come after three new LNG export plants on the east coast have sucked gas out of the southeastern market and nearly tripled wholesale gas prices in places such as Sydney over the past two years. EPIK, a newly-formed LNG FSRU project development company, said it had signed an agreement with the Port of Newcastle to do preliminary work on a proposed FSRU that it estimated would cost up to $430 million, including onshore infrastructure.

Tokyo Gas Co has signed a joint development agreement with Philippines’ First Gen Corp to build and operate a LNG receiving terminal in the Philippines, its first foray into energy infrastructure development in Southeast Asian country. The Philippines in October had short-listed three different groups of companies, including the Tokyo Gas partnership with First Gen, to build and operate its first LNG import terminal. First Gen, which owns about 60 percent of the gas-fired power plants in the Philippines, is the biggest natural gas user in the country, Tokyo Gas said.

Bulgaria plans to set up a state-owned company by the end of the year to operate a natural gas bourse, with liquidity secured through an agreement with Austria’s natural gas trading hub. Petkova said Sofia will sign a memorandum for cooperation with the Vienna-based CEGH as it pushes forward with plans for a gas trading hub in the Black Sea city of Varna. CEGH is a trading platform for the central European Baumgarten hub, the arrival point for Russian gas flowing into Europe via Ukraine and through the Nord Stream pipeline across the Baltic Sea. The new company will be a unit of state-owned gas network operator Bulgartransgaz, Petkova said. Bulgartransgaz plans to seek binding bids from shippers by 16 January for a new link to transport gas from its border with Turkey in the south-east to Serbia in the west, which will carry mainly Russian natural gas to central Europe.

Norway’s Equinor is ready to start talks with Tanzania on developing a LNG project based on a deepwater offshore discovery, the company said. Tanzanian President John Magufuli has asked his government to proceed with negotiations to set out the commercial and fiscal framework for the LNG project, Equinor, a majority state-owned energy company formerly known as Statoil, said. Tanzania said in 2014 that a planned LNG export plant could cost up to $30 billion. Royal Dutch Shell, which operates deepwater Blocks 1 and 4, adjacent to Equinor’s Block 2, previously sought to develop the LNG project in partnership with Equinor and Exxon Mobil.

Energy company Eni aims to start output of natural gas from its offshore Merakes project in Indonesia in 2021. Initial production at Merakes would be 155 mcf/d rising to a forecast peak output of 391 mcf/d. Eni said in April it had obtained approval for plans to pipe natural gas from Merakes to the Bontang LNG processing facility in East Kalimantan. The amendment would be first time a conventional cost-recovery production-sharing contract in Indonesia is converted to use the gross split scheme. Merakes project has an estimated 814 bcf of natural gas reserves and an economic lifetime of around nine years.

Gas production at the earthquake-prone Groningen field will drop by at least 75 percent in the next five years, ahead of schedule towards the projected end of extraction. The Dutch government decided this year to shut down in 2030 what was once Europe’s largest natural gas field because decades of extraction had caused dozens of earthquakes each year, damaging thousands of homes and buildings. Production will drop below 5 bcm/year from 2023, the Dutch government said, as measures to reduce demand for Groningen gas are working better than planned. Demand for Groningen gas will be reduced by building extra capacity to convert high-caloric foreign gas to the low-caloric gas needed for the Dutch network, and by cutting exports to Germany.

km: kilometre, CGD: city gas distribution, PNGRB: Petroleum and Natural Gas Regulatory Board, BPCL: Bharat Petroleum Corp Ltd, BG: British Gas, MGL: Mumbai Gas Ltd, IGL: Indraprastha Gas Ltd, CNG: compressed natural gas, MNGL: Maharashtra Natural Gas Ltd, mt: million tonnes, LNG: liquefied natural gas, US: United States, mtpa: million tonnes per annum, ONGC: Oil and Natural Gas Corp, OIL: Oil India Ltd, DSF: Discovered Small Field, bcm: billion cubic meters, mcm: million cubic meters, MoU: Memorandum of Understanding, mcf/d: million cubic feet per day, bcf: billion cubic feet,  FSRU: Floating Storage and Regasification Unit, mmBtu: million metric British thermal units, CEGH: Central European Gas Hub

Courtesy: Energy News Monitor | Volume XV; Issue 30

UJJWALA YOJANA INCREASES SUBSIDY BILL

Monthly Oil News Commentary: November – December 2018

India

According to the government, nine out of 10 Indian homes now use cleaner cooking gas according to the government. State oil companies, pushed by the oil ministry, have added record 100 million consumers since April 2015, expanding the active consumer base by two-thirds. This has increased access to cooking gas, or LPG to 89% of the country’s households by October end, a sharp jump from 56.2% on 1 April 2015. A subsidy for fresh LPG connection to poor families helped fuel demand. Rural areas still have untapped potential with more than half of all consumers, or about 136 million residing in urban areas. India has a total of 249 million active customers, of which 229 million receive subsidy. Those with double cylinders comprise barely half of the consumer universe—one reason why new customers do not entirely give up polluting fuels as they are forced to fall back on their traditional fuel while refill is on way. Companies are beefing up distribution infrastructure, which has been slow to expand compared with the consumer base, becoming another hurdle in smooth delivery of services. Northern states have the highest 99.9% LPG coverage ratio, with Punjab (136%) and Delhi (126%) leading the table. Chandigarh, Haryana, Himachal Pradesh, J&K, and Uttarakhand have recorded more than 100% subscription while Uttar Pradesh (89.7%) and Rajasthan (95.4%) have lower coverage. The government calculates LPG coverage ratio by factoring in the number of subscribers and the current population, which is estimated by adding certain growth rate to 2011 census figures. Due to increased migration, some of the states like Delhi and Punjab end up having population that’s higher than the estimates, resulting in an LPG coverage ratio of more than 100%. Overall, Goa has the highest coverage ratio of 139%. Telangana, Puducherry, Kerala and Mizoram are other states with higher than 100% coverage. Southern states together have a coverage of 99.7% while western states have 81.9%. With 74.6% coverage, the eastern states are at the bottom of the pile although they have come a long way from their traditionally poor access to clean energy. The worst among major states are Jharkhand (65.4%), Bihar (67%) and Odisha (66.9%). In Gujarat too, the LPG coverage ratio is 66.6% but that’s more because the state is already well connected to the alternative piped natural gas. Most north-eastern states have less than 80% coverage.  Over 60,000 households in six districts of Himachal Pradesh will be supplied LPG through pipeline. The Indian Oil-Adani Gas Private Ltd would develop city gas distribution network in Sirmaur, Solan and Shimla districts, while Bharat Gas Resources Limited in Bilaspur, Hamirpur and Una.

The reality of the LPG scheme appears to differ from the government narrative.  Sky rocketing LPG prices are leaving a big dent in the monthly budget of households in the city and the beneficiaries under the central government’s visionary Ujjwala scheme are finding it difficult to purchase the cylinders at ₹ 1,000, which is beyond their affordability. LPG price is a main concern of many during the winter season as consumption is higher than summer months mainly for heating water. A daily labourer with daily wage of ₹ 500 finds LPG cylinder too expensive, so they have started cooking on firewood again. Many houses have started rethinking their daily cooking plans to save LPG. An LPG dealer said that the Ujjwala scheme is a failure at least as far as Madurai is concerned as the beneficiaries do not buy cylinders even once in three months. Also, under the scheme they get the subsidy only for six months, after which the subsidy is accounted towards the cost of the stove, regulator, gas tube and other accessories, though it is initially made to look like they are given the connection for free. Mix-ups in the bank accounts and Adhaar linking are also affecting these people.

For its part, busting rumours that LPG cylinder prices are likely to be hiked to ₹ 1,000/cylinder, the petroleum ministry said domestic LPG cylinder rates are likely to be reduced in the coming days. It said because of a fall in international fuel prices, domestic LPG prices are also likely to fall down in the coming days. At present, subsidised LPG costs ₹ 507 in Delhi and non-subsidised ₹ 942/cylinder. LPG prices are revised at the beginning of each month but for the month of November, the price hike came twice — by ₹ 2.94 and then ₹ 2. The rates of non-subsidised LPG cylinders have been increased by ₹ 60 in Delhi already and for the sixth consecutive time in as many months. The government absorbs any increase in international prices of LPG as subsidy. Only a subsequent increase, if any, on GST is passed on to the consumers. Rates of LPG cylinders differ by a few rupees from state to state because of transportation cost and local taxes. The government subsidises only 12 cylinders of 14.2 kilogram each per household in a year by transferring the subsidy amount directly into the bank accounts of LPG consumers.

The government’s expenditure on petroleum subsidy in the first six months of the current financial year crossed 83 percent of the budgeted allocation of ₹ 249.33 billion for the fiscal, fresh data published by the oil ministry’s statistical arm data showed. This mostly includes under-recovery on LPG and Kerosene apart from natural gas subsidy for northeast. The total subsidy expenditure went up 82.10 percent to ₹ 206.72 billion during the first six months (April-September) of the current financial year, as compared to an expenditure of ₹ 113.52 billion incurred in the corresponding period a year ago. The government had budgeted for an overall petroleum subsidy of ₹ 249.33 billion for financial year 2018-2019, a mere 1.93 percent increase over Revised Estimate of ₹ 244.60 allocated for 2017-2018. The budgeted petroleum subsidy for 2018-2019 should be around ₹ 450-500 billion considering Brent crude price at $70 per barrel for the year and an exchange rate of ₹ 65 against the dollar. The budgeted petroleum subsidy could fall short by around ₹ 200-250 billion.

India’s monthly petroleum products consumption dropped 1.7 percent to 17,273 in November primarily due to a decline in usage of LPG, Diesel, Kerosene and Petcoke, data from PPAC showed. LPG consumption, which had been recording growth for 62 straight months, declined for the first time in November. It dropped 7.34 percent to 1,842 tonne during the month as compared to 1,988 tonne recorded in November 2017, data from PPAC showed. Consumption of cooking gas has been buoyant over the past few years mainly due to increased LPG penetration under PMUY. According to the PMUY, OMCs have distributed 58.4 million LPG connections under the scheme. LPG penetration in the country has gone up to 88.5 percent in 2018 as compared to 56.2 percent in 2015, according to data.

ONGC’s $1.7 billion work package, one of the biggest deep sea contracts offered in recent years, for its largest offshore block has perked up a listless global oilfield services industry and is likely to see fabrication of crucial underwater kits in the country for the first time. The state-run explorer has awarded the contract, its single-largest ever, to a consortium of BGHE (Baker Hughes, a GE company), McDermott International and LTHE (L&T Hydrocarbon Engineering) for block KG-DWN-98/2 off the Andhra coast. The block has the potential to reduce India’s import dependence for oil and gas by 10 percent. India currently imports 82 percent of oil need and 45 percent of gas requirement. ONGC expects to start producing gas by December 2019 and oil by March 2021. Total peak gas production rate is projected at 16 million cubic meters per day and peak oil output is pegged at 80,000 barrels a day.

Nagaland government and the Lotha Hoho, the apex body of Lotha Nagas, have signed an MoU to amend the Nagaland Petroleum and Natural Gas Regulations and Rules, 2012 with certain terms and conditions. The main oil belt of Nagaland is situated in the Lotha Naga areas. The State Assembly had enacted the Nagaland Petroleum and Natural Gas Regulations and Rules, 2012. However, around three years after it was enacted the Kohima bench of Gauhati High Court issued a stay order against the permit given to MOGPL following a PIL filed by the Lotha Hoho. The PIL raised issues involving “controversial” MOGPL which bagged the lucrative oil zones in Wokha district. Other issues included the fixing of eight percent royalty in addition to other Excise tax by the State Government on the plea of sharing the revenue with non-oil bearing districts. According to the Nagaland Petroleum and Natural Gas Regulations and Rules, 2012, the State Government set up the Nagaland Petroleum and Natural Gas Regulations and Rules Board to monitor all activities related to oil and natural mining.

India’s crude oil imports in October rose to their highest level in at least more than seven years, data from the PPAC of the oil ministry showed. Crude imports in October climbed 10.5 percent from a year earlier to 21.02 mt the highest monthly import figure in PPAC data going back to April 2011. Imports rose as many refiners resumed purchases after maintenance of units. In October, India’s oil imports from Africa surged to more than a three-year high. In India, the world’s third-largest consumer, oil imports typically rise from October due to higher fuel demand in the festival season and as industrial activity picks up after months of monsoon rains. India is among the eight countries to have received a waiver from the US to continue crude oil imports from Iran without penalty after sanctions were reimposed on Tehran. India’s oil imports from Iran fell by about 12 percent to about 466,000 bpd in October. The country’s overall purchases from Iran in the April-October period, the first seven months of the current fiscal year, rose 34 percent. Meanwhile, imports of oil products declined nearly 20 percent and exports fell more than 4 percent, the data showed.

Indian oil refiner HPCL will buy Iranian crude in January after a gap of six months, with the nation’s overall purchases from Tehran at 9 million barrels in the month. The US in early November granted India a six-month waiver from sanctions against Iran’s oil exports. Under the agreement, New Delhi must restrict its Iran oil purchases to 1.25 million tonnes, or 9 million barrels. As part of the deal, HPCL will lift 1 million barrels of Iranian crude oil in January, one source with knowledge of the matter said, asking not to be named due to the political sensitivity of Iran sanctions. It was unclear whether HPCL would continue to buy Iranian oil on a regular basis during the waiver period. HPCL had halted Iranian oil purchases in July after its insurance company refused to provide coverage for the crude because of US sanctions, although its chairman said last month that HPCL may resume buying Iranian oil under sanctions waivers. IOC, the country’s top refiner, will lift 5 million barrels of Iranian oil in January compared to 6 million this month, while MRPL will buy 3 million barrels. Some of India’s oil imports from Iran will be paid for in rupee under a payment mechanism with Indian state-owned UCO Bank.

RIL is looking at expanding the production capacity of it’s SEZ refinery at Gujarat’s Jamnagar to 41 mtpa from the present 35.2 mtpa. RIL’s current refinery complex in Jamnagar has a cumulative capacity to process 68.2 mtpa of crude oil. After expansion, RIL’s total crude oil processing capability would increase to 74 mtpa, overtaking IOC’s cumulative capability of 69.2 mtpa. RIL had increased the SEZ refinery’s capacity to 35.2 mtpa in financial year 2017-2018 from 27 mtpa in financial year 2016-2017. According to oil ministry’s committee on refinery expansion report, India is projected to increase its total oil refining capacity by 76 percent to 438.65 mtpa by 2030 from the current 249.4 mtpa. According to the report, IOC is expected to increase its refining capacity to 116.5 mtpa by 2030, ONGC is expected to increase its capacity to 62.9 mtpa, Nayara Energy (erstwhile Essar Oil) to 45 mtpa, and RIL’s cumulative refining capacity to 98.2 mtpa.

IOC the country’s largest fuel retailer, said it has invited entrepreneurs to set-up 27,000 petrol pumps pan India. The retailer said that the eligibility norms have been relaxed this time and availability of suitable land at the advertised location or stretch was the most important requirement. However, applicants without land can also apply on a condition that when called by IOC they should be able to offer land. In a bid to cement their market leadership and expand their footprint in other geographical areas of the country, oil firms had invited applications last month to set-up 55,649 retail outlets in 30 states and union territories in the country. Out of these, about 27,000 petrol pump dealerships have been offered by IOC followed by 15,802 dealerships by BPCL and 12,865 by HPCL.

Petrol and diesel may soon again become cheaper in Delhi as compared to adjoining cities of Uttar Pradesh as ad valorem duty structure has translated into a bigger reduction in daily prices in the national capital. While petrol and diesel traditionally have been cheaper in Delhi than most states in the country, due to lower local sales tax or VAT the 5 October cut in the VAT by BJP-ruled states led to fuel being available at cheaper rates in places such as Ghaziabad and Noida — the Uttar Pradesh towns that adjoin the national capital. However, the difference that had peaked to over ₹ 3/litre in case of petrol and about ₹ 2.3/litre in diesel on 5 October, has now come down to just ₹ 0.44-0.57/litre in petrol and about ₹ 1/litre in diesel, an analysis of the daily price revision notification issued by state-owned oil firms showed. Petrol prices in Delhi stood at ₹ 71.72/litre as compared to ₹ 71.15/litre in Ghaziabad and ₹ 71.28/litre in Noida. A litre of diesel in the national capital is priced at ₹ 66.39 as opposed to ₹ 65.31 in Ghaziabad and ₹ 65.44 in Noida. The Union government slashed the petrol and diesel price by ₹ 2.50/litre by reducing excise duty and asking state-owned oil firms to bear subsidy. This was matched by several states which reduced local sales tax. BJP-ruled Uttar Pradesh too followed suit. Prior to the cut, it levied 26.80 percent or ₹ 16.74/litre, whichever is higher as VAT on petrol and 17.48 percent or ₹ 9.41/litre on diesel. Petrol price had touched a record high of ₹ 84/litre in Delhi and ₹ 91.34/litre in Mumbai on October 4. Diesel on that day had peaked to an all-time high of ₹ 75.45/litre in Delhi and ₹ 80.10/litre in Mumbai. Many states including Maharashtra matched that with a reduction in local sales tax.

India’s Vedanta Resources wants US oilfield services companies to set up consortia to help develop the 41 blocks in India acquired this year by its Cairn Oil & Gas unit. The company won 41 of the 55 blocks auctioned under India’s first licensing round for small discovered fields earlier this year. It expects the blocks will eventually produce 500,000 barrels per day of oil equivalent. Vedanta hopes to speed up development of the blocks by getting the oilfield firms to organise consortia that would deliver integrated services.

Maharashtra has put on hold the process to buy land for the country’s biggest oil refinery that state-run oil companies are building with Saudi Aramco after strong opposition from farmers. The $44 billion refinery was seen as a game changer for both parties – offering India steady fuel supplies and meeting Saudi Arabia’s need to secure regular buyers for its oil. But thousands of farmers are refusing to surrender land, fearing it could damage a region famed for its Alphonso mangoes, vast cashew plantations and fishing hamlets that boast bountiful catches of seafood. Ratnagiri Refinery & Petrochemicals Ltd, a joint venture between IOC, HPCL and BPCL, has said suggestions the refinery would damage the environment were baseless.

A wave of shutdowns will hit Indian state-owned refineries next year as the country prepares for cleaner fuels from April 2020, in moves that could temporarily dent oil demand and push up imports of refined fuels. India, the world’s third-biggest oil importer and consumer, has surplus refining capacity and rarely imports gasoil and gasoline. State refiners – IOC, BPCL, HPCL and MRPL – account for about 60 percent of the country’s nearly 5 million barrels per day capacity. The refiners will have to shut gasoil- and gasoline-making units at their plants for 15 to 45 days to churn out Euro VI-compliant fuels from January 2020 to be able to sell them from April of that year.

OMCs have offered setting up maximum number of fuel retail outlets through dealerships in Uttar Pradesh (9,370), Maharashtra (6,765), Karnataka (5,024), Gujarat (4,450) and Haryana (3,370), according to information provided by the OMCs on Petrol Pump Dealer Chayan website.  The website houses the details of state-wise distribution of pumps to be set up under the latest mega drive by the oil firms to expand fuel dispensing facilities. Other states where sizeable number of retail outlets has been offered include Bihar (2,951), Tamil Nadu (2,951), Andhra Pradesh (2,815), Odisha (2,636), West Bengal (2,242), Jharkhand (1,905), Kerala (1,730) and Assam (1,026). In a bid to cement their market leadership and expand their footprint in other geographical areas of the country, the oil firms had invited applications to set-up 55,649 retail outlets in 30 states and Union Territories in the country. Of this, 26,982 have been offered by IOC followed by 15,802 dealerships by Bharat Petroleum Corp and 12,865 dealerships offered by Hindustan Petroleum Corp. India currently has 63,674 petrol and diesel retail outlets. The three government-owned OMCs account for 90 percent of these. Among private players, Nayara Energy tops the list with 4,895 retail outlets followed by RIL with 1,400 and Royal Dutch Shell with 116 retail outlets. According to the oil ministry, most of the petrol and diesel retail outlets are currently present in Uttar Pradesh (7,473), Maharashtra (5,970), Tamil Nadu (5,388), Rajasthan (4,476), Karnataka (4,214), Gujarat (4,025), Madhya Pradesh (3,711), Punjab (3,427), Haryana (2,862), Telangana (2,626), Bihar (2,695), West Bengal (2,333) and Kerala (2,100). India has added around 17,481 petrol and diesel retail outlets in the past six years across the country, growing at an average annual rate of 5.61 percent.

The state government has decided to phase out all diesel autos older than 10 years from Gurgaon as per the directions of the Supreme Court. The apex court had in last month ordered the transport departments of Delhi and surrounding NCR cities to act tough against polluting vehicles by prohibiting plying of more than 15-year-old petrol and 10-year-old diesel vehicles. Of all the diesel autos in Gurgaon that provide last-mile connectivity, some 687 are 10 years old.

Rest of the World

The global oil market could move into deficit sooner than expected thanks to OPEC’s output agreement with Russia and to Canada’s decision to cut supply, the IEA said. The Paris-based IEA kept its 2019 forecast for global oil demand growth at 1.4 mn bpd unchanged from its projection last month, and said it expected growth of 1.3 million bpd this year. Uncertainty over the global economy stemming from US-China trade tensions could undermine oil consumption next year, as growth in supply gathers pace. The OPEC agreed with Russia, Oman and other producers to cut oil output by 1.2 million bpd from January to stem a build-up in unused inventories of fuel. The decision by the government of Canada’s Alberta province to force oil producers to curtail supply will bring the largest reduction to crude output next year, the IEA said. Alberta crude and oil sands output will drop by 325,000 bpd from January to force down vast inventories that built up because of pipeline capacity constraints.

Russian President Vladimir Putin said he had no concrete figures on possible oil output cuts, though his country would continue with its contribution to reducing global production. Russia, one of the world’s major crude producing nations, has been bargaining with OPEC’s leader, Saudi Arabia, over the timing and volume of any reduction. OPEC and its allies will be meeting amid concerns over a slowing global economy and rising oil supplies from the US. Oil prices had their weakest month in more than 10 years in November, losing more than 20 percent as global supply has outstripped demand. Losses were limited, however, on hopes of a production cut agreement.

Iran has no plans to reduce its oil production, but will remain a member of OPEC. OPEC and its Russia-led allies agreed in Vienna to slash oil production by more than the market expected in a bid to shore up prices despite pressure from US President Donald Trump to reduce the price of crude. Oman will be cutting oil output by 2 percent from January for an initial period of six months, according to a letter sent to customers of Omani oil by the country’s oil and gas ministry. OPEC and its Russia-led allies agreed to slash oil production by more than the market had expected despite pressure from US President Donald Trump to reduce the price of crude.

Malaysia will extend its oil production cuts by another six months after the agreement between OPEC and other oil producers to reduce global supply ends this year. OPEC and non-OPEC producers agreed at a meeting in Vienna to a new level of production cuts from January to June 2019, setting it at 1.2 million barrels per day from the current rate of 1.8 million barrels per day. Malaysia is not an OPEC member. In 2016, via its state-owned oil company Petroliam Nasional Berhad, Malaysia announced that it would cut oil output by 20,000 barrels per day as part of its commitment to reduce supply following an agreement between the OPEC and non-OPEC producers. The initial agreement, led by Russia, was later extended for another year till the end of 2018.

Iraq has increased production at its southern Halfaya oilfield by 100,000 bpd to a total of 370,000 bpd. Halfaya, operated by PetroChina, is Maysan province’s largest field. Production rose after the completion of a new oil processing facility. Increasing production from Halfaya had raised the company’s overall output to around 510,000 bpd. The new crude facility, which has a capacity to process 200,000 bpd of crude oil, will help further boost output from Halfaya to reach 470,000 bpd in the first quarter of 2019.

Iran has set the official selling price of its Iranian Light grade for its Asian buyers at 30 cents above the Platts Oman/Dubai average for January, $1 lower than the previous month, a price document showed. The producer has cut prices for the other three crude grades it sells to Asia. The price cuts were in line with Saudi crude price adjustments for January, keeping Iranian oil prices at the largest discounts in more than a decade against Saudi grades for a third consecutive month since November when US sanctions on Iran started. China’s Iranian oil imports are set to rebound in December after two state-owned refiners in the world’s largest oil importer began using the nation’s waiver from US sanctions on Iran while Japanese and South Korean buyers are preparing to resume loadings in January.

Saudi Crown Prince Mohammed bin Salman and Bahraini King Hamad bin Isa Al Khalifa opened a new oil pipeline between the two countries. The pipeline connects Saudi oil processing facilities at Abqaiq with the Bahrain Petroleum Company refinery in Bahrain, with a flow that currently reaches 220,000 barrels per day, and a transport capacity of up to 350,000 barrels per day.

Gulf states which depend heavily on energy exports for most of their revenues should brace for a long period of low oil prices and subdued economic growth, experts warned. Signs of an “economic war” between the US and China, the world’s largest economies, and an expected global economic slowdown starting next year will dampen demand for oil, the experts said. The six member nations of the GCC earn more than 80 percent of their revenues from energy. The GCC states — Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates — have lost hundreds of billions of dollars in oil revenues since crude prices crashed in mid-2014. Oil prices later rebounded after OPEC and non-OPEC producers reduced their production. But they slid again when producers boosted output to compensate for expected losses from Iran because of the re-imposition of US sanctions. Economic growth in the GCC region was still dependent on oil price movements. Unemployment rate among Arab youths is 30 percent and higher among females, adding that growth is not producing enough jobs. OPEC and non-OPEC producers decided to cut production by 1.2 million barrels a day from January to shore up prices, which some analysts warned would hit economic growth.

Libya’s NOC has declared force majeure on operations at El Sharara oilfield, it said. NOC said that oil production from Libya’s biggest oilfield will only restart after “alternative security arrangements are put in place”. The NOC declared force majeure on exports from the 315,000 barrels per day oilfield located in the south of the North African country after the field was earlier seized by a local militia group. NOC said the shutdown would result in a production loss of 315,000 bpd at its biggest oilfield, and an additional loss of 73,000 bpd at the El Feel oilfield. Production at the Zawiya refinery was also at risk due to its dependence on crude oil supply from Sharara, NOC said.

Colombia has canceled two auctions of rights to explore for oil in dozens of areas of the Andean nation and plans to relaunch bidding early next year, the government said. The Sinu-San Jacinto round of bidding on 15 blocks in northern Colombia was scrapped after interested companies withdrew, and a round known as the Permanent Competitive Procedure was canceled because of a judicial ruling, the National Hydrocarbons Agency said. It plans to relaunch bidding in February. Colombia last held auctions in 2012 and 2014, when it awarded 76 blocks. The government subsequently held off further auctions because of low international oil prices. Colombia needs to boost foreign investment to revive its stagnant crude and gas production. The nation has 1.78 billion barrels of reserves, equivalent to about 5.7 years of consumption but wants to increase that to at least 10 years of consumption. It produces some 860,000 bpd of crude, half for export. The government expects to increase output to 900,000 barrels of oil equivalent a day this year.

The Norwegian government has postponed a decision on whether to mandate the construction of an oil processing terminal near the Arctic tip of northern Europe until the third quarter of next year, it said. If built, the onshore Veidnes terminal would receive crude via a pipeline from Equinor’s offshore Johan Castberg oilfield, which is expected to start producing in late 2022. Equinor originally ditched plans for an onshore terminal in order to save costs, preferring instead to load oil on to crude tankers at the field before exporting it to global markets. The energy ministry said further studies were needed into the project, which is supported by labour unions. Environmentalists, however, oppose both the oilfield and the proposed terminal.

Angola’s state oil company Sonangol and Exxon Mobil signed a Memorandum of Understanding for oil exploration in the country’s Namibe basin, the two firms said. Angola, Africa’s second-largest crude producer, is facing a steep output decline unless it can revive exploration in what was once one of the world’s most exciting offshore prospects. Sonangol is negotiating contracts for new blocks with oil majors and Angola plans to hold an auction next year, the first tender for exploration rights since 2011. The memorandum paves the way for the parties to start contract negotiations for new oil concessions, part of the state firm’s strategy to strengthen the search for new oil activities and discovery of new reserves. The new field of exploration can be viewed as the resurgence of oil activity in the country. The signs of fresh exploration in Angola comes after a period of near-paralysis due to a lack of drilling success, a slump in oil prices and a deteriorating relationship between Sonangol and the oil majors. Oil accounts for 95 percent of Angola’s exports and around 70 percent of government revenues.

Hess Corp said it expects oil and gas output to grow more than 10 percent a year compounded through 2025, touting development of its Bakken shale and offshore Guyana projects. The company projects higher margins will drive compound annual cash flow growth of 20 percent through 2025, it said. Hess shrugged off a recent dip in oil prices and said it was moving from growth and investment mode to where its major assets will start producing free cash flow. Hess boosted the production forecast for its Bakken shale field in North Dakota to 200,000 boepd by 2021, from 175,000 boepd. The shale acreage, the jewel in the crown of the company’s onshore production, will produce $5 billion in free cash flow between 2019 and 2025.

US gasoline prices at the pump fell to the cheapest in about a year-and-a-half, driven lower by sagging crude oil prices and excess supply of the fuel, market participants said. Gasoline futures on the New York Mercantile Exchange RBc1 were the lowest seasonally since 2015. Prices have changed course from earlier this year, when they hit seasonal four-year highs. Plummeting oil futures have helped deflate gas prices. Crude has plunged about 30 percent since October as global supply has surged and demand growth has weakened. Further, analyst said excess supply of gasoline in the US has depressed prices. US refiners have been encouraged to run at high rates to take advantage of strong diesel margins. However, in the process they have over produced gasoline and driven up those inventories.

Kazakhstan’s central bank has trimmed its forecast for the country’s oil output in 2019 and said it expects Brent crude oil to average $60 a barrel next year. The bank said that it expects the country to produce 91 mt of oil next year, down from its previous estimate of 93 mt and taking into account scheduled maintenance work at oilfields. It reduced its forecast for oil production this year to 90 mt from 91 mt. The new forecasts would still be above forecasts in the government’s budget for oil production of 87 mt this year and 88 mt in 2019.

Argentina’s state-controlled energy company YPF and Malaysia’s Petronas are forming a joint venture to invest $2.3 billion over the next four years in the country’s Vaca Muerta shale oil fields, the president’s office announced. The Belgium-sized Vaca Muerta deposit, located in western Argentina, is regarded as having the world’s second-largest shale gas and fourth-largest shale oil deposits. The companies’ objective is to reach a production equivalent of 60,000 barrels a day by 2022, it said. Total investment could reach $7 billion within 20 years, it said.

Exxon Mobil and Chevron are seeking to sell their stakes in Azerbaijan’s largest oilfield, marking the retreat of the US majors from the former Soviet state after 25 years as they re-focus on domestic production. Exxon is hoping to raise up to $2 billion from the sale of its 6.8 percent in the ACG field in the Caspian Sea. Rival Chevron said it had also decided to launch the sale of its 9.57 percent stake in ACG as well as its 8.9 percent interest in the Baku-Tbilisi-Ceyhan pipeline. For both companies, the sale would mark the end of a 25-year involvement. Exxon and Chevron were among five US oil companies that helped create Azerbaijan’s current oil industry soon after the collapse of the Soviet Union, and acquiring a stake in ACG in 1994. The ACG fields still account for the lion’s share of Azeri oil output. They produced around three quarters of overall Azeri crude output, or nearly 600,000 barrels per day, in the first half of 2018.

Exxon Mobil Corp and its partners expect the large Stabroek oil block offshore Guyana to contain 25 percent more recoverable oil than previously estimated, the companies said. Exxon and Hess Corp said more than 5 billion barrels of oil equivalent could be recovered from the Stabroek block, which is part of one of the biggest oil discoveries in the world in the last decade. The companies had previously estimated 4 billion barrels of oil equivalent could be recovered from the block.

Top Chinese oil and gas firm PetroChina is aiming to raise the annual crude oil output to 3 million tonnes in 2021 at a newly discovered oilfield in the remote northwestern Xinjiang region, triple this year’s estimated rate. Mahu, in the Junggar basin, is named as one of the largest discovery in China after more than a decade of work. PetroChina is keen to boost output at Mahu to 5 mt in 2025. One of the recently drilled wells, Mahu-015, produced 405.6 cubic metres of oil and 36,000 cubic metres of natural gas a day in test production. China’s top two onshore producers Sinopec and PetroChina are speeding up exploration and production from major shale oil and gas formations in the country’s western regions to boost domestic output. China’s crude oil output rose 0.3 percent on year to 16.09 mt or 3.79 mn bpd the second year-on-year increase recorded this year.

A top aide to Brazilian president-elect said the new government would adopt concession contracts for lucrative pre-salt oil auctions, raising concerns that talks to change the regime would drag and derail much-needed investment. There was no final decision yet on what contracts the new administration would offer in the highly prized deep water oil tenders. Investors are eager to win a bigger slice of Brazil’s oil prize, but the shift away from an increasingly successful production sharing auction regime also raises concerns that any changes would require lengthy discussions in Congress, raising uncertainty and causing investment to dry up.

South Africa will invest $1 billion in South Sudan’s oil sector, including in the construction of a refinery. South Sudan exports its crude through a pipeline that goes to a port in neighbouring Sudan to the north. South Sudan is producing 135,000 bpd from 130,000 bpd in August.

Venezuela’s state-run oil firm PDVSA has begun talks with shipping firms to set up a second ship-to-ship operation off the country’s eastern coast in an effort to increase sagging crude exports. PDVSA this year began sea-borne oil transfers off its western coast, mainly to move crude and fuel oil to Asia, after its ports clogged with tankers waiting to load and its Caribbean terminals faced seizure. PDVSA’s ship-to-ship activity has expanded recently, but not enough to expedite operations at its main oil port of Jose, according to Refinitiv Eikon data. The country’s crude exports fell 21 percent to an average 1.126 mn bpd between January and October, according to data. At the end of the first half, PDVSA’s contractual obligations totaled 2.19 mn bpd.

Equinor and Global Petro Storage have entered into a long-term agreement to build and operate a terminal and storage facility for LPG in Malaysia, the Norwegian company said. Oil and gas firm Equinor will bring LPG to the terminal at Port Klang, expected to start operating in mid-2021, to sell into Malaysia and other Asian markets including Bangladesh, the Philippines, India, Indonesia and Vietnam, it said. Equinor plans to source the LPG from the North Sea, North Africa, the Middle East and Australia. The 135,000 cubic metre-capacity terminal could handle 1.5 mt of LPG per year, the company said. Equinor said its operations already account for around 10 percent of global waterborne LPG volumes. As part of the agreement, Equinor will have an option to acquire a share of the new storage facility and terminal, of which it will be the only user. The IEA said in March it expected demand for petrochemical feedstock including LPG to rise over the coming years, driven by demand for products from fertilisers to plastics and beauty products.

LPG: liquefied petroleum gas, GST: Goods and Services Tax, PPAC: Petroleum Planning and Analysis Cell, PMUY: Pradhan Mantri Ujjwala Yojana, OMCs: Oil Marketing Companies, ONGC: Oil and Natural Gas Corp, MoU: Memorandum of Understanding, MOGPL: Metropolitan Oil and Gas Private Ltd, PIL: public interest litigation, US: United States, HPCL: Hindustan Petroleum Corp Ltd, IOC: Indian Oil Corp, MRPL: Mangalore Refinery and Petrochemicals Ltd, RIL: Reliance Industries Ltd, bpd: barrels per day, mt: million tonnes, SEZ: Special Economic Zone, mtpa: million tonnes per annum, BPCL: Bharat Petroleum Corp Ltd, VAT: Value Added Tax, BJP: Bharatiya Janata Party, NCR: national capital region, OPEC: Organization of the Petroleum Exporting Countries, IEA: International Energy Agency, GCC: Gulf Cooperation Council, NOC: National Oil Corp, boepd: barrels of oil equivalent per day, ACG: Azeri-Chirag-Gunashli

Courtesy: Energy News Monitor | Volume XV; Issue 29

RENEWABLE GROWTH UNABATED BY POWER SECTOR WOES

Monthly Non-Fossil Fuels News Commentary: November – December 2018

India

The World Bank praised India’s success in renewable energy auctions that delivered record-setting low prices for solar power and said that the number of countries with strong policy frameworks for sustainable energy more than tripled — from 17 to 59 — in the eight years till 2017. Many of the world’s largest energy-consuming countries significantly improved their renewable energy regulations since 2010, said the World Bank’s report — Regulatory Indicators for Sustainable Energy 2018, charting global progress on sustainable energy policies. While countries continue to be focused on clean energy policies for electricity, policies to decarbonize heating and transportation, which account for 80 percent of global energy use, continued to be overlooked. The report contained a warning that without accelerated adoption of good policies and strong enforcement, the world’s climate goals and Sustainable Development Goal 7 were at risk. By last year, 84 percent of countries had a legal framework in place to support renewable energy deployment, while 95 percent allowed the private sector to own and operate renewable energy projects.

India has become the largest market globally for auction of new renewable energy generation projects and the second-largest destination attracting clean energy investments. These are the findings of the latest Climatescope 2018 report by BNEF. India has secured second place in the global ranking driven by its policy thrust towards renewables and increasing investments in the clean energy sector. The country is the second-largest renewable energy investment market among all Climatescope countries, attracting $9.4 billion in new investments in 2017. Renewable energy installations in India exceeded those by coal power plants for the first time in 2017 as the country moved closer towards its target to install 175 GW of renewables by 2022. India’s installed power generating capacity stood at 346 GW in June 2018, with renewables (excluding large hydro) accounting for 71 GW. With coal taking a share of almost 60 percent, challenges with domestic coal supply are resulting in increased coal imports. However, the government has reduced its coal capacity target for 2027 by 11 GW to 238 GW as the country seeks to replace coal with renewables through auctions. The report said India’s renewable auctions market is the largest in the world and auctioned capacity has ramped up by 68 percent since 2017.

India currently has renewable energy projects of 46,500 MW capacity in the pipeline for capacity addition. This includes projects which are currently under construction and those likely to be offered for bidding soon. India has made a commitment to the world that by 2030, 40 percent of its electric power generation capacity would come from non-fossil fuels and it will install 175 GW of renewable energy capacity by 2022, the MNRE said. The target includes 100 GW of solar, 60 GW of wind and 10 GW of small hydro power. The government expects to overachieve the 175 GW renewable energy target on the back of new schemes for floating solar power, awarding manufacturing-linked solar projects and offshore wind energy projects.

India has declared the trajectory of bidding 60 GW capacity of solar energy and 20 GW capacity of wind energy by March 2020, leaving two years’ time for execution of projects, the MNRE said. A total of about 73.35 GW renewable energy capacity has been installed in the country as of October, 2018, from all renewable energy sources. This includes about 34.98 GW from wind, 24.33 GW from solar, 4.5 GW from small hydro power, and 9.54 GW from bio-power. Further, projects worth 46.75 GW capacity have been bid out under installation. According to the Paris accord on climate change, India had pledged that by 2030 40 percent of installed power generation capacity shall be based on clean sources. And determined that 175 GW of renewable energy capacity to be installed by 2022. This includes 100 GW from solar, 60 GW from wind, 10 GW from bio-power and 5 GW from small hydro power. India has fifth global position for overall installed renewable energy capacity, fourth position for wind power and fifth position for solar power. The country registered lowest ever solar tariffs in India of ₹ 2.44/kWh in reverse auctions carried out by the SECI in May 2017, for 200 MW and again in July, 2018, for 600 MW.

SECI has decided to continue with the solar panel manufacturing-linked power project tender despite only one bid. It had invited tender for setting up 3 GW of solar panel manufacturing, along with 10 GW of power plant. The bid was submitted by NYSE-listed Azure Power to set up 600 MW of manufacturing as well as 2,000 MW of power project. The bidding happened after being extended for six times, owing to lack of bidders. Major players shied away from the bidding citing lack of funding push from the Centre, thereby reducing viability of solar manufacturing in India. Earlier, the industry had expressed reservations over the tender.

The MNRE is preparing a database to identify the land available for solar and wind energy projects in the country. Plans are on to introduce location-specific bids to strengthen transmission facilities. MNRE officials visited states, including, Gujarat, Telangana, Andhra Pradesh, Madhya Pradesh, etc. and are in the process of doing the assessment in Tamil Nadu and Karnataka. Knowing the availability of land and the potential for renewable energy in the location would help in better bids and improve confidence in investors. The prices, discovered through the solar and wind power auctions, are globally competitive. The apprehensions that these projects would not be viable have been proved wrong. The offshore energy project near Thoothukudi, Tamil Nadu, is facing protests from the local fishermen. The state should take steps to allay the apprehensions of the fishermen, and help the ministry proceed further.

The MNRE will approach the Union cabinet in the next 30-45 days seeking approval for the solar rooftop scheme SRISTI or Sustainable Rooftop Implementation for Solar Transfiguration of India. The scheme, part of the larger grid-connected RTS power programme, aims to bring discoms to the forefront in the implementation of rooftop solar projects by providing them financial support which will be linked to their performance in facilitating the deployment of RTS. The second phase of the original solar rooftop scheme is designed to boost the adoption of rooftop in the residential space and would use the network of distribution companies. The government has set a target to install 40,000 MW of rooftop solar power capacity by 2022. India added new rooftop solar capacity of 1,538 MW in the current Financial year between April and September 2018, which is around 75 percent above the previous year. The scheme aims to also bridge the knowledge gap that exists related to the agencies to be approached, installation of plant equipment and the long-term benefits of solar rooftop. The scheme is being proposed to streamline the system by making the discoms and its local offices as the nodal points for implementation of the programme.

The NABARD signed an agreement with GCF to infuse $100 million into the project designed to unlock private sector initiatives for the creation of rooftop solar power capacity across India. The $250 million project, to be executed by Tata Cleantech Capital Ltd, will receive the GCF support through NABARD, which is the National Implementing Entity for the UNFCCC-promoted Fund that supports the efforts of developing countries to respond to the challenge of climate change, the bank said. The agreement with GCF was signed at an event held on the side-lines of ongoing COP24 in Katowice, Poland, it said. Notably, India, which hosts International Solar Alliance, has an ambitious vision of creating 100 GW solar power capacity it said. NABARD has been financing solar power projects and installations in various other programmes as well.

The latest approval of GST claims for solar power developers by CERC is a major positive development but timely payments by the off-takers remains crucial, according to research and ratings agency ICRA. Around 10.9 GW of solar power capacity has been commissioned between July 2017 and September 2018, with most of the projects being awarded prior to July 2017. Considering 75 percent of the capacity commissioned during this period to be under the competitive bidding regime awarded prior to July 2017, the one-time compensation towards GST impact to be paid by discoms to solar developers is estimated at ₹ 20 bn on all India level. CERC issued an order in October 2018 approving the claims raised by solar power developers related to the impact of the introduction of GST on the capital cost of solar power projects. The regulator has approved the claims under a change in law provision allowing the relief which is required to be recovered as a one-time payment on GST front from the off-takers.

NTPC Ltd said it has won 85 MW of solar capacity in a reverse auction held by the UP government. NTPC participated in the 550 MW tender floated by Uttar Pradesh New and Renewable Energy Development Agency for grid-connected solar projects. In the reverse auction held on 3 December 2018, NTPC participated for 85 MW solar capacities and has won the entire capacity bid by it, at a levelised tariff of ₹ 3.02/unit, applicable for 25 years, the company said. The above 85 MW of solar projects shall be set up by NTPC and shall add to the installed capacity of NTPC, the company said.

To avail the benefits of the Central government’s flexible-generation scheme, NTPC has called for tenders from 1,000 MW of existing solar and wind generation plants to supply power to the company for one year. The ceiling tariff for the reverse auction for choosing solar/wind power plant has been kept at ₹ 2.67/unit. The power ministry, in April this year, had allowed thermal power gencos the flexibility of using renewable energy sources to meet their contractual generation obligations. The new mechanism allows thermal gencos to set up renewable power plants at their existing power stations, or anywhere else, thus allowing discoms to meet their renewable purchase obligations through existing PPAs. The scheme was seen to allow companies such as NTPC to avail of the benefits of this policy, given that some of the power stations located far from pithead have an energy charge higher than ₹ 3/unit.  The minimum offered capacity of a solar/wind power plant will have to be 50 MW and in multiples of 10 MW thereafter, NTPC said. Only renewable power plants having inter-state transmission system connectivity shall be eligible for selection, it said. Industry experts are sceptical about the expected response to the invitation, since most of the large wind/power plants are built after signing PPAs through government nodal agencies.

India’s Shapoorji Pallonji Group In the country’s first solar-wind hybrid auction conducted by the SECI has yielded the lowest highly competitive tariff of less than ₹ 2.70/kWh, the government said. The government has embarked on the development of non-conventional renewable energy sources, while the first round of auctions for floating solar projects had successfully discovered tariffs as low as ₹ 3.22/kWh. India’s first large-scale floating solar project is on its way with Shapoorji Pallonji winning the first block in Solar Energy Corp of India’s auction of 150 MW of such projects on the Rihand Dam, along the UP-Madhya Pradesh border. Shapoorji Pallonji won the reverse auction for 50 MW quoting a tariff of ₹ 3.29/kWh. The remaining 100 MW will also be shortly auctioned in blocks of 50 MW. Since then, solar tariffs have fallen dramatically, with those of ground mounted projects dropping to ₹ 2.50-3.50/kWh. In UP, where solar radiation is not as strong as in states like Rajasthan, the average tariff has been more than ₹ 3/kWh. The Rihand floating projects will not have any such issues, and they can use the same transmission facilities as the hydropower station of the dam. Shapoorji Pallonji Group plans to seek about $1 billion by bringing outside investors into its solar unit, as it embarks on a series of asset sales across the 153-year-old conglomerate to reduce debt. The group will sell as much as 30 percent in the solar engineering arm of Sterling & Wilson Pvt. The funds would be raised through a pre-listing stake sale followed by a public offering. The solar unit, which provides engineering, procurement and construction services, will generate ₹ 95 billion of revenue for the year ended March 2019. The business is now building its presence in the United States and Australia, where the market potential may be about $10 billion for solar contracts.

Users of Yamuna expressway may have to pay more toll as the YEIDA has decided to set up solar lights on the 165 km stretch connecting Greater Noida to Agra and recover the cost from them. The cost of the project is nearly ₹ 940 mn which will be met by increasing the toll tax. Jaypee Infratech, the concessionaire will install lights on the entire stretch. Jaypee has agreed to the project and requested YEIDA to revise the toll to recover the project cost. Once approved, Authority will facilitate in opening an escrow account to ensure the money is invested properly in the project implementation. The project will be completed by 31 March 2019.

A generous commissioning deadline for solar projects provided by the UP government in its latest auction has resulted in surprisingly low winning tariffs. The offer of 550 MW of projects by the UP New and Renewable Energy Development Agency attracted bids between ₹ 3.04 and ₹ 3.08/kWh. NTPC, the lowest bidder, quoted ₹ 3.04/kWh to win 85 MW. The bids were lower than the winning tariff of ₹ 3.17/kWh at the auction in October, which itself was fairly low, considering that UP’s power distribution companies are in poor financial health. Solar radiation in UP is also low compared with that in Rajasthan, Gujarat and Andhra Pradesh. Solar tariffs have been rising ever since the finance ministry imposed safeguard duty of 25% on imported solar panels and modules for a year from end-July in an effort to support local manufacturing. The duty will be lowered to 20% for the next six months and to 15% for another six months. More than 90% of the solar panels used in Indian projects are imported because local manufacturers cannot match those in China and Malaysia on price. The UP agency has set a project commissioning deadline of 21 months from the date of signing of the power purchase agreement. Most such deadlines vary between 13 and 21 months. UP’s July auction of 1,000 MW at the height of the confusion over impending safeguard duty had seen winning tariffs of ₹ 3.48-3.55/kWh. The auction was later cancelled, without any official reason assigned.

The EEREM centre, Delhi government’s nodal agency for rooftop solar projects, launched a tender for setting up 35 MW grid-connected rooftop solar projects in the capital under the Mukhyamantri Solar Power Program. The tender invites e-bids for installation of rooftop solar projects across residential, social and institutional sectors to be developed in eight parts under both CAPEX and RESCO models. Of the tendered capacity, 10 MW will be developed under the CAPEX mode and remaining 25 MW under RESCO. The government has appointed IPGCL to oversee the proceedings of the tender and project execution on behalf of EEREM. Under the RESCO model, a developer finances, installs, operates and maintains the rooftop solar power plant on the consumer’s roof. The developer signs a PPA with the rooftop owner. The rooftop owners consume the electricity generated from the solar plant for which they have to pay a pre-decided tariff that includes the Operation and Maintenance cost to the RESCO developer on a monthly-basis for the tenure of agreement. The government is offering incentives to the developers and consumers. The developers will be eligible for a subsidy at the rate of 30 percent calculated at L1 project cost or the MNRE benchmark cost, whichever is lower under the CAPEX model, and fixed subsidy according to the MNRE benchmark cost for the RESCO Model, only after acceptance of the project by IPGCL. Delhi government is also giving a generation-based incentive of ₹ 2/kWh on solar generation for a five-year period to residential consumers under the scheme.

To incentivise production of solar power in the state, the Goa government has proposed a 50% subsidy for small prosumers (consumers and producers of solar power) as an amendment to the Goa State Solar Energy Policy, 2017. Instead of granting an interest-free loan that would be recovered in instalments from small prosumers, the government proposes to provide a 50% subsidy on capital costs to prosumers in the residential, institutional and social sector categories that have solar plants with a capacity of up to 100 kW. If the amendment is allowed, the Centre will bear 30% of the subsidy’s cost and the state, 20%. Also, such a subsidy will be released to the prosumer only six months after the solar power project is connected to the grid. A single-window clearance portal for grid-connected rooftop solar installations has already been readied for consumers in Goa, but is yet to be launched.

After the success of a pilot project, the Maharashtra government plans to extend the agricultural solar feeder scheme in the rest of the state. The pilot project of the scheme was introduced last year in two places in Ralegan Siddhi in Ahmednagar and Kolambi in Yawatmal. Under this programme, the farmers are supplied power during the day with the help of solar generation.

Surat, which aims at becoming the first solar city of the country, will have 25 MW of installed capacity of solar power by February 2019. It already has 15 MW of installed capacity of solar power and tops the chart in the country. In all, 4,000 solar panels of different capacities were installed in the city which produce 15 MW of solar power. The city administration had received 4,500 applications from residents and commercial establishments in the first phase until 24 September. It received another 1,000 applications in the second phase that began from 24 September and ends next year in the same month. The MNRE has increased subsidy on solar panels to encourage use of clean energy. The Energy and Resources Institute had carried out a survey 18 months ago and it found that Surat had a potential to generate about 418 MW of solar energy from panels installed on rooftops. Rooftops of houses in the city can generate 179 MW, commercial establishments 210 MW, educational and health organizations 23 MW and government offices 6 MW of solar power. Solar panels on SMC buildings already help produce 5 MW of solar power. Surat expects to produced 50 MW of solar power by September 2019.

The PSPCL is going to set up a 60-65 MW paddy straw-based power plant at the cost of ₹ 1.50 bn. PSPCL’s BoD in a meeting cleared the proposal for the project at the Guru Nanak Dev Thermal Power plant in Bathinda. It will be one of the largest straw-based plants and around 4 lakh tonne paddy straw would be used annually to generate electricity. So far, straw-based power plants of up to 45 MW capacity are operational. The BoD cleared another proposal to set up 100 MW solar power plant was also cleared. The proposals have been sent to the state government for final approval.

With the deadline for installing rooftop solar power plants at residential properties in Chandigarh expired on 17 November, only 50% of households have applied for the same. The Chandigarh administration, in a notification issued on 18 May 2016, had made installation of rooftop solar power plants mandatory in residential houses measuring 500 square yards and above and group housing societies. There are around 10,000 such houses in different parts of the city, including sectors 8 (417 houses), 11 (493 houses), 33 (643 houses), 35 (419 houses) and 36 (417 houses). However, till date only 50% of these households have applied for installing solar plants. Earlier the deadline was set for 6 May that was later extended to 17 November. The CREST said those who had applied would have to install solar plants within six months. The UT administration will hold a meeting in this regard where it would decide the future course of action. Meanwhile, those who have not applied for solar power plant installation, will be issued notice by the UT estate office. The Union government had in 2008 selected Chandigarh to be developed as a model solar city with a target of generating 69 MW of solar energy by the year 2022 through net and gross metering. The CREST has only managed to install a solar power plant with a capacity of 24 MW in last six years. It will have to ensure generation of 45 MW within four years to meet the goal.

GAIL (India) Ltd might be interested in buying some of the wind assets of debt-laden IL&FS but has yet to have any discussion on the matter. GAIL would not consider buying the entire wind energy assets of IL&FS unless offered at a steep discount. IL&FS has an installed wind energy capacity of 775.2 MW, while GAIL, which wants to expand its renewable energy portfolio, owns 128 MW.

Solar power generation has gone up significantly in Kochi with many big firms switching over to solar energy. Kochi Metro, Cochin University of Science and Technology, Government Medical College, Ernakulam are some of the big institutions installing solar plants. Moreover, a majority of the 10,000 applicants who have registered with the KSEB’s Soura rooftop solar power plant project are from Kochi. The medical college is all set to commission a 153 KW solar power plant. According to KSEB, registrations as part of the Soura project is going on. Under the Soura project, the KSEB is planning to generate 1,000 MW of energy in the next couple of years. The KSEB would install the panel in the residential premises of consumers. The consumers can bear the cost or the KSEB would spent the amount, which should be paid back in instalments along with the electricity bills.

UP government will give subsidy up to 70% for solar pumps for irrigation purpose to the farmers under a state government scheme. Solar energy-driven pump set is an emerging alternative of electrical and diesel pump systems in farm irrigation. Under the solar pump voltaic irrigation pump scheme 10,000 units will be given to farmers at a subsidised rate during 2018-19 on the basis of first come first serve basis. Government of India will take necessary measures and encourage state governments to put in place a mechanism that state run power utilities purchase surplus solar power at reasonably remunerative rates from farmers using solar pumps for irrigation. Solar Pumps are a boon to the electricity, banking, water and agriculture sectors, solar power pump makers said.

The Maharashtra government plans to give 5 horsepower solar agricultural pumps worth ₹ 350,000 at a subsidised rate of ₹ 20,000 and 3 horsepower pumps costing ₹ 150,000 at ₹ 15,000 to farmers. He said the state government had set a target of distributing 100,000 solar pumps of which 10,000 had already been given out. Another 25,000 solar pumps will be provided to farmers in the next three months.

The authorities in Jammu and Kashmir have dewatered one of the tunnels of the KHEP for laying of cable to Gurez valley in Bandipora district. The task of dewatering the 650-metre-long Adit-1 tunnel of the KHEP started on 19 November is complete. The district administration took a risk during winters to dewater the Adit tunnel of KHEP so that it could be used to lay BSNL cables, which was the only option left to connect the habitations of Kanzalwan, Bagtore, Izmarg and adjoinning villages. Hindustan Construction Company said it was a difficult task to dewater the tunnel, that too in chilling cold, but the logistical support by the deputy commissioner made the task easier for them as the task was completed in record 21 days.

NHPC Ltd has bagged debt-laden Lanco’s 500 MW Teesta hydro power project under insolvency proceedings for a tentative value of ₹ 9 bn. NHPC is expected to complete the takeover in the next three to four months and can finish the project in three to four years as its construction is almost 50 percent complete. However, the company said this would be subject to final approval by the NCLT. Lanco Teesta Hydro Power is building a 500 MW (125 MWX4) hydropower project on the Teesta river in Sikkim. As per the procedure, the NCLT would call for objections on the deal before approving it. Once approved by the NCLT, NHPC would seek approval of the Public Investment Board and the Cabinet Committee on Economic Affairs. NHPC has installed generation capacity of 7071 MW while 3800 MW is under construction.

The power ministry has sought Cabinet approval for a policy change categorising large hydro projects as renewable energy sources. Currently, only hydro projects under 25 MW are identified as renewable energy. Apart from helping the country attain the target of having 175 GW renewable capacity by 2022, the renewable energy tag would help hydro power get a priority over thermal electricity while being dispatched to the consumers. The hydro sector would also get additional leg-up as the states can fulfil their mandatory renewable purchase obligations by buying electricity from these power plants. The power ministry note seeks the Cabinet approval for introducing a separate ‘hydropower purchase obligation’ category. To reduce hydro power tariffs, the ministry wants the cabinet to approve, modify existing norms and not let the host states receive free power from hydro power plants till five years from commissioning. As per existing provisions, developers have to contribute 12% free power to state governments.

Hydro power in India is likely to see a boost with projects of close to 10 GW to either restart or commence construction. Along with this, the Centre is moving a policy for promoting hydro power, which aims at reducing the cost of construction. The policy is likely to do away with any requirement for creating irrigation facilities, allied assets or any social infrastructure in order to bring down costs. Government said hydro power would be promoted and incentivised as peaking power. Peaking power is the power supply that meets the sudden increase in demand or supply shortage. While coal is used as base load, solar and wind power have intermittent supply. India has added more than 20 GW of solar and 15 GW of wind in the past five years. Uttarakhand, which decided to forgo 4 GW of hydro projects following ecological issues, and the Supreme Court directive to stop constructing dams, had sought financial support from the Centre.

Himachal Pradesh government has allotted the 780MW Jangi-Thopan-Powari hydro electric project in Kinnaur district to SJVN Ltd on build, own, operate and transfer (BOOT) basis for a period of 70 years. SJVN has necessary infrastructure and that the current installed generation capacity of SJVN is 2,003.2 MW (comprising of 1,912 MW hydro, 85.6 MW wind power and 5.6 MW solar power). SJVN is in the process of implementing various projects, which are in different stages of development, which on completion would add an additional 4,018 MW of capacity. Projects with a potential of 1,572 MW generation capacity are under construction, 1,848 MW under pre-construction and investment approval and 598 MW capacity is in the investigation stage. SJVN had earlier implemented 1,500 MW Nathpa Jhakri hydro power station in Himachal Pradesh. It is also executing hydro projects in Nepal, Bhutan and Uttarakhand.

BHEL has dispatched its 40th Nuclear Steam Generator to the NPCIL. The Steam Generator, to be installed in NPCIL’s Rajasthan Atomic Power Project, was flagged off on 1 December 2018 from BHEL’s Trichy plant. The first stage of the indigenous nuclear power program of the country has attained maturity with 18 operating PHWRs. Twelve PHWRs accounting for 74% of the Nuclear Power capacity are equipped with BHEL-supplied Steam Turbine Generator sets (10 units of 220 MW each and two units of 540 MW).

The warming of the Indian Ocean due to global climate change may be causing a slow decline in India’s wind power potential, according to a study. India, the third largest emitter of greenhouse gases behind China and the US, is investing billions in wind power and has set the ambitious goal to double its capacity in the next five years, researchers from the Harvard John A Paulson School of Engineering and Applied Sciences, said. The majority of wind turbines are being built in southern and western India to best capture the winds of the summer Indian monsoon, the seasonal weather pattern then brings heavy rains and winds to the subcontinent. The study, published in the journal Science Advances, found that the Indian monsoon is weakening as a result of warming waters in the Indian Ocean, leading to a steady decline in wind-generated power. The research calculated the wind power potential in India over the past four decades and found that trends in wind power are tied to the strength of the Indian Summer Monsoon. In fact, 63 percent of the annual energy production from wind in India comes from the monsoon winds of spring and summer, researchers said. Over the past 40 years, that energy potential has declined about 13 percent, suggesting that as the monsoon weakened, wind power systems installed during this time became less productive, researchers said. Western India, including the Rajasthan and Maharashtra states, where investment in wind power is the highest, has seen the steepest decline over that time period, researchers said. However, other regions, particularly in eastern India, saw smaller or no decline, researchers said. The researchers aim to explore what will happen to wind power potential in India in the future, using projections from climate models.

Rest of the World

California became the first state in the nation to require homes built in 2020 and later be solar powered, following a vote by the Building Standards Commission. The unanimous action finalises a previous vote by the Energy Commission and fulfils a decade-old goal to make the state reliant on cleaner energy. Homebuilders have been preparing for years to meet a proposed requirement that all new homes be “net-zero” meaning they would produce enough solar power to offset all electricity and natural gas consumed over the course of a year.

China will aim to launch a new renewable power quota system before the end of the year, part of efforts to make better use of its renewable energy resources and reduce waste. The NDRC said in a new 2018-2020 plan for the clean electricity sector that it would work to cut renewable power wastage rates to 5 percent by 2020 from as high as 12 percent this year. The new quota system will set minimum renewable power consumption targets for each region. Companies covered by the scheme will receive renewable energy certificates when they buy renewable power and will be forced to buy additional certificates if they fail to reach their targets. The NDRC promised to create new mechanisms and price-setting policies, and would also implement a system that would force local governments to give renewable electricity sources priority access to the power market. According to a draft NEA proposal, the central government would start to set minimum targets of renewable energy consumption by region from 2019. Local authorities would monitor compliance by power companies and consumers, according to the draft. The draft outlines setting regional quotas based on their renewable energy resources, with hydropower-rich Sichuan province in southwest China required to bring renewables to 80 percent of total power consumption, compared with only 9.5 percent in coal-dependent Shandong province in the east. The quota system, opposed by traditional coal-fired power companies, has been under discussion for some time. The draft proposal follows two earlier drafts issued in March and September. The March version proposed a quota of 91 percent renewable power consumption in Sichuan and 8.5 percent in Shandong. The system aims to lower the rate of wasted renewable power by giving clean energy generators priority access to the grid. Power from wind, solar and hydropower plants is often lost because its intermittent nature makes it difficult to schedule without disrupting grid operations. The final quota for each region will be handed out in the first quarter of 2019 and the assessment of policy compliance will start from 1 January. The quota will be increased in 2020 when China looks to increase the portion of renewable energy use in its total energy mix, the NEA said. Beijing has set a national target to raise clean energy use to 15 percent by 2020 and 20 percent by 2030. It was at 13.8 percent in 2017.

Germany intends to increase energy production from wind and solar farms by a further 8 GW over the next three years as the government tries to compensate for its decision to abandon strict emissions targets. Chancellor Angela Merkel’s conservatives and their Social Democrat (SPD) junior coalition partners this year dropped plans to lower carbon dioxide emissions by 40 percent from 1990 levels by 2020. The decision was based on expectations that Germany would miss its national emissions target for 2020 without any additional measures because of strong economic growth and higher than expected immigration. The Bundestag lower house approved government plans to boost green energy production. For the past few years, Germany has been increasing power capacity from wind and solar by 5 GW each year. The 8 GW increase between 2019-2021 is additional to that. The government has set a new goal of increasing the share of renewable energy in Germany’s electricity consumption to 65 percent by 2030 from roughly a third last year.

Strong gusts evening helped Britain’s wind farms to produce a record amount of electricity, trade group Renewable UK said. Britain aims to increase its renewable output and close its coal-fired power plants by 2025 as part of efforts to meet climate targets. Overall wind generated 32.2 percent of the country’s electricity more than any other electricity source. The figure beat the previous record of 14.5 GW set on 9 November. The country’s renewable electricity capacity overtook that of fossil fuel generators such as gas and coal for the first time this year. The world’s largest offshore wind farm, Orsted’s Walney Extension, opened off the northwest coast of England in September.

Brazil’s latest policy to boost biofuels use has improved the outlook for ethanol production and should attract new investment in plants. Brazil is advancing with additional regulation for the policy, called RenovaBio and expected to be enacted in 2020, Lindenhayn said. RenovaBio will mandate fuel distributors to gradually increase the amount of biofuels they sell. The program aims to double the use of ethanol by 2030 from around 26 billion litres currently. The program also targets increases for other renewables such as biodiesel.

Finnish state-owned gas firm Gasum plans to expand the processing capacity of its biogas plant in the city of Turku, making it the second largest such facility in the country, the firm said. As a result of the expansion, which is scheduled to be completed by September 2019, the plant will be able to produce some 60 GWh of biogas annually, Gasum said. Increasing the production of biogas for use in business and transport is one of Finland’s energy and climate policy goals as it seeks to gradually phase out the use of coal. The plant is currently able to process about 75,000 tonnes of organic waste. From September 2019, its capacity will be as high as 110,000 tonnes. Gasum owns twelve biogas plants across Finland and expanded production in Sweden with the acquisition of Swedish Biogas International a year ago, a move that made it the biggest biogas producer in the Nordics.

Zambia is seeking proposals from potential developers of solar power projects with a combined 200 MW capacity as it tries to diversify its energy mix away from hydroelectric power. The 200 MW would be split into small projects, each with a maximum size of 20 MW. Zambia is heavily dependent on hydropower and faced electricity shortages following a drought in 2016, forcing Africa’s No.2 copper producer to ration power to its mines. Enel Green Power had started building five wind power projects in South Africa, which would add 700 MW of electricity to its output when completed in the next few years.

The EU regulators approved €600 million ($679 million) worth of French state aid for innovative solar power installations, saying it would support the bloc’s climate ambitions. The European Commission said that the scheme was aimed at adding 350 MW of additional capacity through small installations at ground level or on buildings that would be picked through tenders by the end of this year.

Malaysian state-owned oil and gas firm Petroliam Nasional Berhad (Petronas) has set up a new business within the group to make a push into renewable energy. Petronas has expressed interest over the last year to diversify into renewables amid low oil prices. Petronas will explore new business areas including new energy and that the company will assess opportunities in solar power. Petronas is the latest oil and gas major to look into the renewables space. Top oil companies including Royal Dutch Shell, BP and Total are investing more in cleaner energy sources such as solar and wind power and electric vehicle technology. IRENA said Southeast Asia is a potential hotspot for renewable energy, yet the region has not met expectations because it lacks policy frameworks that would encourage investment. Global renewable capacity, excluding hydro, has soared from under 100,000 MW in 2000 to more than 1 million MW in 2017, according to IRENA data.

France plans to triple its onshore wind power capacity by 2030 and multiply by five its solar power generation, enabling it to boost the share of renewables in its energy mix to 40 percent, according to the energy plan presented. The government would increase spending on renewables development to €8 billion ($9.05 billion) annually from 5 billion to take total spending to €71 billion between 2019 to 2028. Nuclear-dependent France has lagged behind other European nations with only around 20 percent of electricity consumption coming from renewables. France is on track to meet its target of 15 GW of installed wind power capacity by the end of the year, but installation of solar panels would likely fall short of the 10.2 GW target by the end of the year. The government would make sure power prices from renewables projects are kept low for consumers while developing more power interconnectors with European neighbours so as to always benefit from the least-cost power.

The EU’s progress towards increasing the use of renewable energy and improving energy efficiency is slowing, putting its ability to meet its 2020 and 2030 targets at risk, the EEA said. Rising energy consumption, particularly in transport, is to blame for the slowdown, the EEA said in an annual report on EU efforts on its renewables and energy efficiency targets. Renewable energy, such as wind and solar, accounted for a 17.4 percent share of gross final energy consumption in the EU last year, according to the EEA’s preliminary data, up from 17.0 percent in 2016. Preliminary EEA data for 2017 showed 20 member states were on track to reach their individual targets on renewable energy by 2020, a decline from 2016 when 25 countries were on track. On energy efficiency, both primary and final energy consumption were above the trajectory needed towards 2020. By the end of this year, member states must submit the first draft of their national energy and climate plans to help them achieve targets for 2030.

Norwegian gas system operator Gassco and Canadian energy firm Enbridge are working on reviving a 350 MW offshore wind project to boost power supply security at Norway’s Nyhamna gas processing plant, they said. The project, which would be the country’s first offshore wind farm, is called Havsul 1 and was fully licensed by Norwegian energy regulators in 2009 before being abandoned in 2012 due to profitability concerns and insufficient subsidies. Initially Havsul 1 was part of a larger plan to construct three offshore wind farms, with around 1,500 MW capacity, but Norway’s regulator rejected the other farms.

French energy group EDF and Nawah Energy have signed a deal to operate and maintain the delayed Barakah power plant, which will be the first nuclear energy plant in the Arab world. The $24.4 billion Barakah power plant in the United Arab Emirates is the world’s largest nuclear project under construction but has been marred by delays related to training issues. The plant was originally expected to begin operations in 2017. EDF and Nawah said that their deal, a 10-year commitment, would help Barakah prepare for operations of the first of its four 1,400 MW units. Earlier this year, the Barakah plant was due to open in 2019. France aims to reduce the share of electricity produced by nuclear reactors to 50 percent from 75 percent now by 2035. The French government has long outlined plans to shrink the country’s reliance on nuclear energy to 50 percent, though the deadline for that goal had remained less clear. A long-awaited government update on France’s long-term energy strategy is expected to be released later this month, setting out in greater detail how it will cut the share of nuclear in its power generation.

Poland expects its first nuclear power plant to start operating after 2030 as the country aims to cut its use of coal in producing electricity. The east European country, which hosts global climate talks in December, generates around 80 percent of its electricity from coal in outdated power plants, many of which will have to close in the coming decade. Poland has considered building a nuclear power plant for years, but has yet to take a binding decision on the project. Poland would talk with France, the United States, Japan and South Korea about nuclear technologies. The energy ministry is expected to publish Poland’s long-term energy policy by the end of the year, likely at the UN climate conference in Katowice, the heart of the coal industry in the south of the country. 25 GW or 44 percent of Poland’s installed power capacity in 2030 will be based on coal while the remaining energy sources will be wind, some photovoltaic and gas. In its draft energy strategy to 2040, a document keenly awaited by market players and analysts, the ministry said the first planned nuclear power plant will have a capacity of 1-1.5 GW. Ultimately the ministry expects Poland to have a total of 6-9 GW of nuclear power by 2043, which will account for around 10 percent of power generation. Poland has considered building a nuclear power plant for years, but the government has yet to take a binding decision on the project. Poland plans to reduce carbon emissions by 30 percent by 2030 as compared to 1990, the ministry said. The most polluting lignite coal will almost disappear by 2040 with a growing share of photovoltaic and wind farms. Poland already has onshore wind farms and its first offshore ones are expected to be built after 2025. Warsaw and Washington signed a declaration on enhanced energy security cooperation, including nuclear power. Poland wants to finance the power plant project on its own, said foreign capital might be necessary because the investment is costly. A nuclear program might cost in the region of 70-75 billion zlotys ($19.94 billion).

Russia signed a new nuclear cooperation agreement with Argentina, which is already negotiating with China about building nuclear reactors. State-owned Russian reactor builder Rosatom said that the two countries had signed a “strategic document” confirming their partnership in nuclear energy at the G20 summit in Buenos Aires. The deal is not a contract to build nuclear reactors, but a framework agreement like ones Russia has signed with many countries. Such agreements do not always lead to firm contracts and are often reconfirmed every few years. Russia has signed earlier nuclear agreements with Argentina, most recently in 2015. The South American country already has three reactors – two German-built, one Canadian-built – which together generate about five percent of its electricity and have combined capacity of 1.6 GW, World Nuclear Association data show. Rosatom said the new agreement outlined the development of large and small reactors in Argentina, possible joint projects in third-world countries and the possibility of jointly operating Russian floating nuclear plants. At home, China has 45 nuclear reactors in operation and about 15 under construction and it wants to build reactors abroad, but it lags way behind Russia in nuclear export.

Bulgaria plans to open a tender to pick a strategic investor for its revived Belene nuclear power project on the Danube and to pick a winner by the end of 2019. China’s CNNC, France’s Framatome – a unit of EDF – and Korea Hydro & Nuclear Power Co have expressed interest in the project to build two 1,000 MW nuclear reactors at Belene. An invitation to become a strategic investor would also be extended to Russia’s Rosatom. Bulgaria plans to keep a blocking stake in the venture.  Bulgaria has been sitting on unused nuclear equipment since paying Rosatom more than €620 million ($712 million) for scrapping the project six years ago. Bulgaria will not commit more public funds to Belene, or extend state or corporate guarantees or offer investors power supply contracts at preferential rates.

MNRE: Ministry of New and Renewable Energy, MW: megawatt, GW: gigawatt, kW: kilowatt,  kWh: kilowatt hour, GWh: gigawatt hour, BNEF: Bloomberg New Energy Finance,  SECI: Solar Energy Corp of India, RTS: Rooftop Solar, discoms: distribution companies, NABARD: National Bank for Agriculture and Rural Development, GCF: Green Climate Fund, UNFCCC: United Nations Framework Convention on Climate Change, GST: Goods and Services Tax, CERC: Central Electricity Regulatory Commission, UP: Uttar Pradesh, gencos: generation companies, PPAs: power purchase agreements, YEIDA: Yamuna Expressway Industrial Development Authority, km: kilometre, EEREM: Energy Efficiency & Renewable Energy Management, CAPEX: capital expenditure, RESCO: renewable energy service company, IPGCL: Indraprastha Power Generation Company Ltd, PSPCL: Punjab State Power Corp Ltd, BoD: Board of Directors, CREST: Chandigarh Renewal Energy, Science and Technology Promotion Society, UT: Union Territory, IL&FS  : Infrastructure Leasing and Financial Services, KSEB: Kerala State Electricity Board, KHEP: Kishanganga Hydro Electric Project, NCLT: National Company Law Tribunal, BHEL: Bharat Heavy Electricals Ltd, NPCIL: Nuclear Power Corp of India Ltd, PHWRs: Pressurised Heavy Water Reactors, US: United States, NDRC: National Development and Reform Commission, NEA: National Energy Administration, UK: United Kingdom, EU: European Union, IRENA: International Renewable Energy Agency, EEA: European Environment Agency, UN: United Nations, CNNC: China National Nuclear Corp

Courtesy: Energy News Monitor | Volume XV; Issue 28

OPTIMISM OVER REVIVAL IN POWER DEMAND

Monthly Power News Commentary: November – December 2018

India

Trade volumes rose 19 percent at the IEX in the first six months of this financial year. This was aided by a pan-India 6.2 percent increase in electricity generation during the period. In all, 28,584 million units of power were traded between 1 April and 30 September, counting both the day-ahead and term-ahead markets. Total volume trade on IEX went up 34 percent, to 33,705 million units in the period. During the period, the market was congestion-free on most days. Volume curtailment due to congestion was only 0.6 percent.

Buoyed by a good response for the first tender of mid-term (3 years) PPA auction, the power ministry will bring its second round for 2,500 MW capacities to give relief to stressed power assets. A PPA is a prerequisite for getting coal supplies for power plants. Power sector is facing stress due to coal shortage and other issues. Many power projects are starving for coal in the absence of PPAs. The government’s scheme to auction 2,500 MW medium-term PPAs evoked good response and PPAs for 1,900 MW capacities were signed under the scheme last month. The power ministry in April 2018 had issued guidelines for a pilot scheme to facilitate aggregation of procurement of power (2,500 MW for 3 years) from commissioned coal-based power plants through competitive bidding. The power procuring distribution companies were Telangana and Tamil Nadu for 550 MW each, West Bengal and Bihar for 200 MW each. Haryana consented to sign for 400 MW.

Led by revival in electricity demand, Vedanta recorded a 19 percent rise in its commercial power sales during July-September quarter. Total power sales from all generating units during the period stood at 3,514 million units as against 2,950 million units in the comparable period of last fiscal year. Vedanta’s coal-fired generating unit at Jharsuguda of 600 MW and HZL unit were the key drivers of power sales. The Jharsuguda power station logged 35 percent year-on-year growth in power sales in Q2FY19 after a tepid performance in the last fiscal year. HZL’s power sales were up 29 percent in the period under review, according to an investor presentation by Vedanta. Total power generation capacity by Vedanta-owned units stands at 9,000 MW. Of this, 5,100 MW is meant for captive consumption and the rest for commercial sales.

Residents and commercial establishments, particularly those in rural areas across the state, will have to pay higher electricity bills from next year if a proposal as per the ARR petition of the Jharkhand Bijli Vitaran Nigam Ltd, the state owned power distribution company, is passed next year. The last time power tariffs were hiked was on 1 May, this year. As per the ARR petition, power tariffs for Kutir Jyoti or tribal beneficiaries below poverty line presently being fixed at Rs 4.40/kWh has been proposed to be hiked to Rs 6 /kWh, a jump of over 36 percent. Similarly fixed charges now at Rs 20/month has been proposed to be hiked to Rs 75/month. For other rural consumers, power tariff has been proposed to be hiked from the present Rs 4.75/kWh and a fixed charge of Rs 35/month, to Rs 6//kWh, with an enhanced fixed charge of Rs 75/month. For urban domestic consumers, the present tariff of Rs 5.50 /kWh has been proposed to be hiked to Rs 6.00 /kWh with no change in fixed charge of Rs 75 /month. Similarly for commercial establishments located in rural areas, the power tariff, standing at Rs 5.25 /kWh and a fixed charge of Rs 60 has been proposed to be hiked to Rs 7 /kWh and a fixed charge of Rs 225/month. For commercial establishments located in urban areas, the present tariff of ` 6.00/kWh has been proposed to be hiked to Rs 7.00 /kWh with no change in fixed charge of Rs 225/month.

Uttar Haryana Bijli Vitran Nigam said that they would provide a list of electricity defaulters to village Sarpanches and zila parishad members, as part of a new campaign to be launched in Jind district. He said that nearly Rs 15 bn is pending from unpaid electricity bills by more than 100,000 consumers in the district. Consumers can take advantage of the Bijli Niptan Yojna and pay in instalments and that interest on the pending bill would be waived off. The deadline for the scheme is 31 December. The government’s focus is on providing electricity connection to every household in the country under the Saubhagya scheme instead of achieving a set of numbers. It is said that household electrification has led to an increase in aggregate, technical and commercial losses of power distribution utilities. 21 million households have already connected and eight states have achieved 100 percent saturation (in household electrification)– Madhya Pradesh, Tripura, Bihar, Jammu & Kashmir, Mizoram, Sikkim, Telangana and West Bengal.  States that are close to achieving 100 percent household electrification are Maharashtra, Uttrakhand, Himachal Pradesh, Arunachal Pradesh and Chhattisgarh. Some states were already 100 percent electrified, inlcuding Gujarat, Goa, Andhra Pradesh, Tamil Nadu, Kerala, Punjab and the Union Territories.

In a relief to power consumers ahead of the general elections 2019, power discoms in Andhra Pradesh made it clear that there will be no increase in electricity tariff for the next year financial year 2019-20. Farmers will get seven hours of free power supply a day. The no-hike proposal comes in the wake of assurance by the state government that it will bear the additional financial burden in the form of subsidy to discoms. Charging stations for electric vehicles will get power at a reduced tariff.

Delhi BSES discoms expect peak hour electricity demand to scale upto 4,800 MW this winter and plan to buy short-term power from spot market in case of contingency. The discoms will resort to electricity banking and backdown techniques to dispose surplus electricity. Last year, winter electricity demand had peaked at 4511 MW. The peak winter power demand in BRPL and BYPL areas had reached 1,888 MW and 1,136 MW, respectively, during last winter. This year, it is expected to reach 1,950 MW and 1,225 MW for BRPL and BYPL respectively, it said. BSES discoms will bank surplus power with hilly states, which need additional power during the winter months. This banked power will be available during the summer months. BRPL will bank between 300-400 MW with states like Himachal Pradesh, Meghalaya, Manipur and Jammu and Kashmir. BYPL will return around 200 MW to states like Himachal Pradesh, from whom it had taken the quantum during the summer-months.

Just three months after it began operations, Adani Energy is drawing flak from consumers whose bills have shot up to unprecedented levels. Some consumers claim their bills for September and October have shot up by as much as 100 percent. Previously known as Reliance Energy, the Mumbai distribution company of Reliance Infrastructure, was acquired by the Adani Group earlier this year. The distribution company has been maintaining that the spike in bills was caused by a change in the weather condition, which in turn reportedly led to a change in the consumption pattern. According to consumer groups and analysts, an average tariff hike approved ranges from 2-8 percent depending on the distribution circle as well as the consumer category. However, the hike could be even more pronounced after April 2020. The protests has prompted Adani Electricity to set up a 24×7 helpline that has promised a response to all the queries related to billing within 24 hours. The company has also organised several camps to respond to queries related to billing.

The Uttar Pradesh Cabinet approved selection of Adani Transmission and Power Grid Corp for setting up transmission networks for evacuation of power from two thermal power projects —2×660 MW Obra-C project and 2×660 MW Jawaharpur project. Both these projects, which have been awarded through the tariff-based competitive bidding process, will bring an investment of Rs 14 bn in the state. Both the transmission projects are being primarily constructed to establish transmission system for evacuation of power from the projects once they are ready. Two 400 kV sub-stations are also being built. While the Obra-C project will also involve setting up of a 400 kV sub-station in Badaun, the Jawaharpur project will have a 400 kV sub-station in Firozabad.

The World Bank will extend $310 million loan for Jharkhand Power System Improvement Project to provide reliable, quality, and affordable 24×7 electricity in the state. An agreement in this regard was signed between the Centre, Jharkhand government and World Bank. The project will help bring in modern technology solutions such as automated sub-stations, and network analysis and planning tools to provide reliable power supply and enhance customer satisfaction. The project is part of the government’s power for all programme launched in 2014. The plan envisages addition of over 4.5 GW generation capacities by 2022 through a mix of private and public-sector investments. As per data from Jharkhand Distribution Company, more than 80 percent of people in the state have access to electricity. The per capita consumption of electricity in Jharkhand at 552 kilowatt hour at the end of 2015-16 is roughly half of the national average.

The PSPCL earned Rs 9.75 bn up to 31 October this fiscal by selling over 1,800 million units of surplus power to discoms of other states. The additional revenue may have come as a relief for the power discom as the state government is yet to pay for subsidies offered to various categories of consumers. The PSPCL is also yet to get a payment of over Rs 12 bn for outstanding power bills of various government departments. The power corporation sold the surplus power at an average cost of Rs 5.4 /kWh in the open exchange from June to October. However, with fall in prices at the open exchange, the corporation has switched to power-banking arrangements to bring down fixed charges that it has to pay for installed power-generation capacity of IPPs. Under power banking, a state’s discom supplies power to the power company of another state free of cost and then takes free supply from that company during its peak season. Power demand had dropped to 5,000 MW during the day and 3,000 MW during the night in Punjab. The demand in peak month, June, was 13,000 MW. The PSPCL has to buy power from IPPs or pay them fixed charges against the installed capacity. At present, it is selling 1,600 MW of surplus power to Andhra Pradesh, Maharashtra, Uttarakhand, and Jammu and Kashmir to topple the fall in power prices in the open exchange.

Rest of the World

French independent power vendors association ANODE is considering making a legal challenge to a government freeze on state-owned EDF’s electricity prices, it said. ANODE president Fabien Chone said the proposed freeze on EDF’s regulated tariffs threatens the survival of some of its members. These operators all compete against EDF, which has an 80 percent share of the retail power market. The government should lower power taxes or introduce support measures for ANODE’s members, it said. From 15 December to 1 March the government would organize a nationwide debate on energy and that power and gas prices would not increase in the meantime. Retail services specialist Colombus Consulting expects French power prices to rise by between 2 percent and 8 percent next year. Even at 5 percent, it would be the highest increase in years.

A nationwide strike reduced French electricity production by 5.5 GW, mostly at state-controlled utility EDF’s nuclear, coal and hydro power plants, power grid operator RTE said. The energy branch of France’s CGT union had called the strike in protest over stalled wage negotiations and a possible government-led restructuring of EDF. The RTE said electricity generation was reduced at EDF-operated Paluel 1, Chinon 1 and St. Laurent 1 nuclear reactors. Power output had also been reduced to zero at EDF’s Cordemais 4 and 5 coal-fired plants, while an ongoing strike at the Havre 4 coal power plant that began on 27 October was extended by 24 hours until 14 November, the RTE said. Electricity generation was reduced by around 1,950 MW at EDF’s hydro power stations across France, the RTE said.

An unspecified number of power stations in Germany will be shut down by 2022 in agreement with their operators, according to a draft document from a government commission tasked with creating a roadmap for phasing out coal. The document said agreement with the operators should happen on the basis of contracts which include rules for possible compensation for operators. It said finances needed to be set aside for the recommended measures and there would not be a levy on the electricity price.

Britain must halt a back-up power scheme aimed at avoiding electricity shortages pending a further investigation by EU regulators, an EU court ruled, which sent shares in UK energy companies tumbling. The judgment by the EU’s General Court annuls a decision by the European Commission, which had said Britain’s so-called power capacity market was compatible with EU state aid rules. Britain began power capacity auctions in 2014, offering to pay providers for making supplies available at short notice, and so avoid shortages that might occur as coal plants close and low prices dissuade investors from building new power plants. National Grid said it has been asked to postpone indefinitely upcoming auctions for capacity to be delivered in the winter of 2022/23 and a nearer-term one for 2019/20.

Russia may delay until March the official launch of its power stations in Crimea, the stations’ engineering firm said, the latest hitch to the plants where Russia is accused of installing German-designed electricity turbines in contravention of sanctions. Russia began building two power stations on Crimea to provide electricity to the peninsula which it annexed from Ukraine in 2014, but the facilities became embroiled in a row over sanctions. The company, Tekhnopromeksport, said the first stage of the power stations will be ready by the end of this year, but that it had requested that the launch of the second phase be delayed until to March.

South Africa faces more power cuts, electricity utility Eskom warned as it sought to prevent the collapse of its power grid in a test for reforms. Eskom implemented a fifth day of controlled power cuts, putting more strain on an economy already mired in recession only months before a national election. Eskom, which is battling a severe financial crisis, coal shortages and breakdowns of its power plants, said it would cut up to 2,000 MW power from the grid. Reforming Eskom has been hampered by fiscal constraints in a blow to the plan to woo investors who can help grow the economy ahead of an election likely to be held in May next year. Prolonged power cuts would likely hurt economic growth in the first quarter of 2019, although a slowdown in manufacturing over the Christmas period will buy Eskom some time.

South African power utility Eskom cut 1,000 MW of electricity from the strained national power grid after high unplanned outages, the company said. Eskom had implemented stage 1 controlled power cuts that shed up to 1,000 MW from the grid. The power cuts are implemented to prevent the grid from being overwhelmed after unplanned outages. Eskom, which supplies more than 90 percent of South Africa’s power, warned of potential outages amid low coal inventories after a major supplier cut supplies and sought insolvency protection.

Power-hungry Vietnam, one of Asia’s fastest-growing economies and a production hub for global companies such as Samsung Electronics, needs to raise up to $150 billion by 2030 to develop its energy sector, according to World Bank. Vietnam has been struggling to develop its energy industry due to a lack of state funds. The Southeast Asian country’s hydropower potential has almost been fully exploited, oil and gas reserves are running low, and Vietnam recently went from a net exporter to net importer of coal. Electricity demand in Vietnam will grow by about 8 percent a year for the next decade. Vietnam plans to more than triple the amount of electricity it produces from renewable sources and push for a 26 percent increase in household solar energy usage by 2030. Vietnam has not been able to reduce its reliance on coal energy, which will account for 53 percent of all energy generated in the country by 2030, according to its trade ministry.

Niger is on track to nearly double power production in the next six years, a development that could boost industry in one of the world’s poorest countries. The government is in talks with three Chinese companies to develop a 200 MW coal-fired power plant in the centre of the country by 2024. The government also plans to open a 7 MW solar power plant by the end of the year, and another in 2020 with about 20 MW of capacity. The three projects in total would in six years add 227 MW of power to a grid that now supplies about 250 MW.

China’s power generation rose 7.2 percent year-on-year in the first 10 months of 2018. In October alone, China generated 533 billion kWh of power, up 4.8 percent year on year, faster than the 4.6-percent growth in September, according to the National Bureau of Statistics. The average daily power generation reached 17.2 billion kWh, edging down from 18.3 billion kWh in September. In the January-October period, new energy power generation accounted for 10.2 percent of the total power generation.

With drive to boost power generation, Nigerian government and key international donor agencies are finalising arrangements to sign a $956 million (N347.362 billion) deal for three key transmission projects for the TCN within the last 18 days of November. A report obtained on the proceeding of a meeting held by TCN and officials of the donor agencies indicates that the EU, JICA and the AFD – French Development Agency are expected to endorse the projects. The Federal Executive Council on its part this month will give approval for the execution of the World Bank funded projects. A breakdown of the report mentioned the project to be the Nigeria Electricity Transmission Access Project. It is valued at $486 mn and is being financed by the World Bank. The $200 mn Lagos/Ogun Transmission Project is the second on the list and is being financed by JICA while the Northern Corridor Transmission Project has funding of $245 mn and €25 million by AFD and the EU.

IEX: Indian Energy Exchange, PPAs: power purchase agreements, MW: megawatt, GW: gigawatt, HZL: Hindustan Zinc Ltd,  FY: Financial Year, ARR: Annual Revenue Requirement, kWh: kilowatt hour, discoms: distribution companies, BRPL: BSES Rajdhani Power Ltd, BYPL: BSES Yamuna Power Ltd, kV: kilovolt, PSPCL: Punjab State Power Corp Ltd, IPPs: independent power producers, EU: European Union, UK: United Kingdom, TCN: Transmission Company of Nigeria, JICA: Japanese International Cooperation Agency

Courtesy: Energy News Monitor | Volume XV; Issue 27

Diesel Price Deregulation: Who did it and Why it matters

Lydia Powell, Observer Research Foundation

The political answer to the question ‘who deregulated diesel prices in India?’ would be ‘the bold new government which is committed to economic reform’. All news papers and television media channels have faithfully followed this line in reporting the story (see this week’s news items).  But those who have tracked the long and hard journey of petroleum product price de-regulation in India would know that it was the dramatic fall in global crude prices that de-regulated diesel prices in India. The much maligned former Prime Minister of India initiated the process of diesel price deregulation years ago. He boldly called for rationalisation of energy prices even at unfortunate moments when global crude oil prices were unfavorable.[1] But for his efforts towards phased increase in diesel prices, deregulation of diesel prices last week would have been more difficult.  In fact, the move to ‘deregulate’ prices may have increased rather than decreased diesel prices notwithstanding the fall in global crude prices. No rational Government would have missed the opportunity for deregulation that the global market has offered.

Once we accept that it is the global crude markets rather than government determination that has facilitated deregulation, we should also acknowledge that the market can take away, with the same ease, the opportunity it is presenting now. What we need to worry about is whether we are prepared for such a moment. We are told by experts (see some of this week’s international news items) that the moment is not far away.

Global crude oil prices have fallen by over 20% since June this year to touch a two year low. We can choose from a wide range of reasons to explain this fall. We can start at the lower end with conspiracy theories that say that the United States and Saudi Arabia have colluded to keep oil prices low (by increasing/maintaining supply) to bring down Putin and his support for Syria. Or we can start at the upper end with explanations that argue that we are beginning to see the collapse of the debt bubble that fed, not just investment in oil production but also demand for oil and oil based products. This explanation would imply that we may be looking at the beginning of the end of oil demand and supply growth. Alternatively we can also depend on more down to earth explanations based on straightforward short term supply and demand data.

Crude oil production in the United States in September 2014 was 8.7 million barrels per day (mbpd), the highest since 1986 and just over 1.2 mbpd short of the peak production volume of 10.04 mbpd achieved in November 1970.[2] The US Energy Information Administration (EIA) expects world oil and other liquids supply to increase by 1.6 mbpd in 2014 with most of the increase coming from non-OPEC countries. On the other hand global consumption which averaged 90.4 mbpd in 2013 is projected to grow by about 1.0 mbpd in 2014 compared to 1.3 mbpd in 2013.[3]  Most of the growth in consumption is expected outside OECD countries with China alone accounting for 370,000 bpd growth in consumption. Projections for consumption growth by the International Energy Agency (IEA) are lower at about 700,000 bpd in 2014.[4] Overall global demand for 2014 has been lowered by 200,000 bpd by IEA to 92.4 mbpd on account of lower expectations on growth. On the other hand, supply for 2014 is expected to increase by 910,000 bpd to 93.8 mbpd.[5] The EIA puts 2014 supply at 91.76 mbpd and demand at 91.47 mbpd.[6] When supply exceeds demand, it is generally expected that OPEC in general and Saudi Arabia in particular would cut production to lift prices. John Kemp of Reuters offers a convincing explanation as to why Saudi Arabia has not acted according to this expectation. He argues that the Kingdom has no choice but to allow prices to drop below $90/bbl or even $ 80/bbl to curb shale drilling and investment in high cost production outside the OPEC.[7] High priced oil not only facilitates growth in shale production but it also encourages ‘conservation, efficiency and substitution’ as Kemp puts it.  Kemp argues that allowing prices to fall is not a choice but a necessity as that will facilitate slower growth in shale and bigger increases in demand.  The best cure for low prices is apparently lower prices.

Others blame the unwinding of a large speculative bubble that started developing after the financial crisis for the fall in crude prices. As pointed out by Jesse Colombo of Forbes, loose monetary policy encouraged large speculators to bet on hard assets like oil. The bubble was punctured by commercial hedgers who are seen to be more informed over physical supply and demand conditions.[8] Some also point out that oil prices were brought down by the end of the commodity super cycle that lasted for 12 years with China’s slow down.[9] The super cycle doubled investments, boosted production of oil and gas and doubled prices.

The fall in oil prices, if sustained, is expected to reduce the annual growth of India’s energy import bill from over 14% to less than 1.6% this year.[10]  Going by the starry eyed reporting of the Economic Times ‘at a stroke the Prime Minister knocked $6.5 billion off the Government’s energy subsidy bill and handed a 6% discount on prices to truckers and drivers’. But this happy situation is unlikely to last very long. According to commentary by CSIS, an American Think Tank, the developments that drove the fall in crude prices carry seeds of future trouble.  Under-investment in oil & gas production, instability in resource rich countries dependent on oil & gas revenue, delay/deterring of investment in shale drilling are all likely. All this could bring prices back to earlier levels above $100/bbl.[11] But experts like Fereidun Fesharaki, Chairman of Facts Global Energy prices are more pessimistic (or optimistic as some would see it) on oil prices. According to him, prices could drop to $60/bbl by the end of 2014 before they go up to $80/bbl sometime in 2015.[12]

This leads to the possibility of unravelling debt driving down oil prices. This would signal the beginning of the end of economic growth as some extreme pessimists predict. When global economic growth is in terminal decline, the price of oil must fall. Consequently consumption will fall and carbon emissions will reduce. Unfortunately no one, not even climate alarmists and renewable energy enthusiasts are likely to celebrate.  The macho emperors of South Asia will not be an exception as their clock of bold reforms will be blown away by falling economic growth rates. As Fesharaki often points out, as far as oil prices are concerned there is a floor and there is a ceiling and breaking of either is not good news for anyone!

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 19

[1] See for example article titled ‘Prime Minister Manmohan Singh Pitches for Rationalisation of Energy Prices’ in Economic Times dated & January 2013

[2] http://www.eia.gov/forecasts/steo/pdf/steo_full.pdf

[3] Ibid.

[4] http://www.iea.org/oilmarketreport/omrpublic/

[5] http://www.iea.org/oilmarketreport/omrpublic/

[6] http://www.eia.gov/forecasts/steo/pdf/steo_full.pdf

[7] KEMP, John, 2014. The Saudi Oil Enigma, Reuters Column, 13 October 2014 available at http://www.reuters.com/article/2014/10/14/saudi-oil-kemp-idUSL6N0S83DZ20141014

[8] COLOMBO, Jesse, 2014. 9 Reasons Why Oil Prices May be Headed for  Bust’, Forbes 6 September 2014 available at http://www.forbes.com/sites/jessecolombo/2014/06/09/9-reasons-why-oil-prices-may-be-headed-for-a-bust/

[9] SIM, Glen, 2014. Goldman Forecasts Lower Commodity Prices as Cycle Ends, Bloomberg, 16 July 2014 available at http://www.bloomberg.com/news/2014-07-16/goldman-sees-lower-commodity-prices-over-five-years-on-supplies.html

[10] Crisil, 2014. Falling Crude, LNG, Coal Prices huge positive for India, Press Release, 21 August 2014,

[11] VERRASTRO, Frank A, GOLDSTEIN, Lawrence & CARUSO, Guy, 2014. Oil Markets: Trouble Ahead, Trouble Behind’ CSIS Commentary, 10 October 2014

[12] Australian Business Review, 2014. Soft oil prices threaten Australian LNG, 21 October 2014 available at http://www.theaustralian.com.au/business/mining-energy/soft-oil-prices-threaten-australian-lng/story-e6frg9df-1227096843128?nk=46325603641de82df08b400e1aa5c91e

 

COAL SUPPLY CRITICAL TO POWER SUPPLY DESPITE RE PUSH

Monthly Coal News Commentary: November 2018

India

That a large part of NTPC Ltd’s reported under-recoveries of Rs 2.10 billion in Q2FY19 was due to unavailability of coal exacerbated the coal supply crisis in the country. The company had reported Rs 14 billion of under-recovery in FY18, of which Rs 8 billion was due to coal shortage. The company’s net profit slipped 1.1% year-on-year to Rs 24.17 billion in the quarter. Fuel stock at NTPC’s power plants remains low with current coal stock of 3.7 mt from a high of 6.9 mt. In the first half of FY19, NTPC’s under-recovery due to coal shortage at 2,320 MW Mouda plant, 2,000 MW Simhadri station and 2,400 MW Kudgi unit was Rs 1.56 billion, Rs 780 million and Rs 250 million respectively. NTPC had received 168.5 mt coal in FY18, which includes 0.32 mt of imports. Requirement for FY19 is estimated to be 196.3 mt. NTPC has already extracted 2.5 mt coal from Pakri Barwadih mine in the first six months of FY19, against the annual production target of 6.3 mt. Additionally, 4,000 tonne have been produced from the Dulanga mine, which expects to produce 1.7 mt in FY19. NTPC has also floated a tender to import 2.5 mt of coal, but the state-owned company risks being seen as an import driver as the country desperately tries to cut import bills amid the rupee devaluation. India’s coal import went up from 171 mt in FY14 to 208 mt in FY18.

CIL said it produced 306.24 mt of coal in the first seven months of the ongoing fiscal, registering an increase of 10 percent as compared to the year-ago period. In the April-October period of 2017-18, the company’s coal production was 278.03 mt, CIL said. CIL supplied 22.2 mt more coal to the power sector during the period under review as compared to the corresponding year-ago seven months, it said. Rake loading to power sector grew 8.2 percent during April-October 2018. The company as whole liquidated 34.57 mt of its pit-head stock during the first seven months, as the stock pile stood at around 21 mt by October-end. Overall offtake during the reported period was 340.81 mt, clocking 7.4 percent growth as compared to 317.28 mt in the year-ago seven months, it said. CIL accounts for over 80 percent of domestic coal output.

CIL is ready to renew its 5 mt offer of additional coal to NTPC, which could not lift any quantity after it was offered the fuel with a 30-day deadline. NTPC said transporting the coal was a big hurdle. However, the company may not be able to keep the offer open for long as the coal that has been made available will deteriorate in quality with time or may catch fire. NTPC was offered coal after its stocks dipped sharply. It was offered 1.5 mt from Central Coalfields, 0.5 mt from Bharat Coking Coal and 0.5 mt from Northern Coalfields among others. NTPC said the company had to arrange for road transportation of the coal from pit head to railways’ loading facilities.

CIL has relaxed the norms for “mine-specific coal supply” policy, which would ease availability of the dry fuel to consumers having less than 1 mt of requirement per annum. The move would benefit a large number of the mining major’s linked small consumers, the company said. The policy was conceived in 2011 to enable the consumer to benefit from assured supply from a preferred source, and gain from reduction in logistic costs. However, the old policy was applicable to consumers having a minimum requirement of 1 mt of coal per annum. Further, the mine from which the coal was sourced had to have a capacity of 2.5 mtpa. The relaxed norms brings down the eligibility from 2.5 mtpa production capacity to 1 mtpa.

CIL aims to raise output from its troubled Rajmahal mine in Jharkhand to 60,000 tonnes a day by March 2019, having resolved land-acquisition related problems which had crimped production to 20,000 tonnes per day. Coal from the Rajmahal mine helps NTPC run close to 4,200 MW of power generation plants in eastern India, which supply power to Bihar, Jharkhand and West Bengal, and also to northern India including Delhi and Uttar Pradesh. NTPC’s generation capacities were faced with depleting coal stocks and lower power generation as supplies from Rajmahal dwindled. Reserves at Rajmahal within the land acquired by CIL were almost exhausted and required expansion to keep production levels intact. However, land acquisition at two villages – Bansbiha and Taljhari—spanning 160 hectares, adjacent to the existing project turned out to be a lengthy process, as sorting out ownership issues resulted in inordinate delay. It led to drastic fall in supplies and stocks at the coalfield, as well as at two critical power plants in the region—at Farakka and Kahalgaon. At present, CIL is using 15 goods trains to transport coal from the Rajmahal mine to power stations in the region. One goods train can load up to 3,500 tonnes of coal. CIL is sending five loaded goods trains from West Bengal’s Ranigunj coalfields to augment supplies at power stations.

Reduced e-auction offerings CIL have contributed to an increase of one-and-a-half times in coal prices in the past year. This is twice as much as the increase in international rates. Analysts said the other factors were increased demand for coal from power plants and non-availability from regular channels for non-power companies, including captive power plants. Between April and September this year, CIL offered 37 mt of coal through its e-auction platform, 19 percent less than that in the year-ago period. This increased its average realisation 50 percent to Rs 2,491/tonne during the period. Despite offering less coal, the company saw a near 21 percent increase in its income from e-auction to Rs 92 billion during the period from Rs 76.52 billion in the year-ago period, as prices shot up owing to lower availability.

India is projected to overtake Australia and the US in early 2020s to become the world’s second-largest coal producer in energy terms behind China, IEA has said in its latest World Energy Outlook 2018 report. India is estimated to produce 955 Mtce in 2040 as compared to 395 Mtce produced in 2017, growing at an annual rate of 3.9 percent, the report said. Also, the report projects that India will become the largest coal importer, overtaking China through 2020s. The country’s coal imports are expected to reach 285 Mtce in 2040 from 172 Mtce in 2017. It said India has set ambitious targets for domestic coal production but imports nonetheless rise, especially for coking coal as domestic resources are insufficient to meet growing demand from the iron and steel industries. Under the IEA’s New Policies Scenario, cumulative capital spending in the coal supply chain is estimated to amount to $1 trillion up to 2040, with an annual average capital spending of $43 billion per year. Coal’s share in India’s electricity generation is expected to go down to 48 percent in 2040 from 74 percent in 2017. In the meantime, share of renewable energy in the country’s electricity generation is expected to go up to 38 percent in 2040 from 16 percent in 2017. According to IEA’s analysis, there are a number of potential bottlenecks in India which could affect the pace of coal production capacity expansion and the delivery of adequate quantities to various users. The report states that despite an overhaul of the coal allocation system, as of April 2018, more than 50 mt of coal is stockpiled at mines awaiting transportation, leading to imports.

India’s coal imports rose by 7.9 percent to 134.46 mt in the first seven months of the current fiscal, according to mjunction services. The country imported 124.57 mt of coal in the corresponding period of previous fiscal. However, there was a 6.8 percent drop in coal and coke imports in October as compared to 19.77 mt imported during the same month last financial year. Coal and coke imports during October through 31 major and non-major ports are estimated to have increased by 3.55 percent over September in the ongoing financial year. The government had earlier said that during 2017-18, coal imports increased to 208.27 mt due to increase in demand by consuming sectors.

Niti Aayog plans to come out with a policy prescription on how India should meet its demand for coal in domestic power and non-power sectors to cut imports of the fossil fuel over the next 10 years. The government’s policy think tank has invited bids for research/ study on linking coal production and consumption requirements in the country based on which the Aayog is expected to draft a comprehensive policy. The study/research will be funded under the research scheme of the Aayog. The moves comes as India battles frequent coal supply issues for domestic power generation. Coal-based power plants account for more than half of the country’s power generation capacity. This would be a comprehensive policy for production and consumption of coal in the country within the framework of the National Energy Policy which is being worked out by the NDA government since 2015.

Indian Railways allotted at least 4,300 goods trains or rakes in the past 12-15 months on instruction from CIL for supplying about 17 mt of coal to the state-run miner’s non-power consumers including captive power plants, that were never loaded by CIL and the allotted rakes remain pending. The estimated value of this coal is at least Rs 22 billion and a portion of this has been already deposited in advance with CIL. Of late, CIL has stopped asking for additional rakes since it is not in a position to clear the entire backlog which touched 5400 a month ago as coal scarcity continues at power houses. At present, the largest number of pending rakes are from CIL subsidiary South Eastern Coalfields, at around 2,200, followed by Mahanadi Coalfields at around 1,000.

Captive power producers coming from sectors like aluminium, steel and copper have been complaining the issue of coal supply to run their plants. Supply of coal is a long standing issue for the captive power producers who unlike the independent power producers don’t produce it for commercial purpose. In the monsoon requirement shot up and coal production could not keep pace. The Union Coal Minister urged CIL to pledge self-sufficiency in production to eliminate import of the dry fuel, and look at reviving the 1 bt output aim.

GIDC proposes to make a fresh attempt for coal blocks and is in the process of applying to the Union ministry of coal seeking allocation of a coal block, outside Goa, under the government route or captive route. The coal from these blocks shall be utilized for generation of power for industries in the state, GIDC said. According to GIDC, the Union ministry wrote to the state government a few months ago informing that new coal blocks were in the process of being allocated to states and state government corporations. This July, the coal ministry issued directions to allocate 27 more coal mines including two coal mines for state governments or state-run corporations. An earlier attempt to source coal and then supply it to a private power company failed miserably in 2014 when the Supreme Court quashed the allocation of the Gare Pelma sector-III coal block in Chattishgarh, along with many others on the grounds that the allocations were done in an arbitrary, non-transparent manner and were against public interest. The block, which was allotted on 12 November 2008, was supposed to take care of the state’s power needs – both domestic and industrial – for five to 10 years. The Supreme Court’s decision to cancel the allocation poured cold water on GIDC’s dreams which had to relinquish the Gare Pelma sector-III coal block. In January this year, the NDA-led government at the Centre allotted 11 large coal blocks to three CIL subsidiaries, including five blocks which were de-allocated by the Supreme Court in 2014.

The West Bengal government is keen on entering commercial coal mining and intends to sell 25% to 30% of its output in the open market from the world’s second largest block allotted to the state earlier this year. Commercial sale is expected to provide economies of scale to the operation bringing down costs which, otherwise, are expected to be high due to difficult geological build of the block. During June this year, the Centre allotted Deocha Pachami to Bengal’s power generation company West Bengal Power Development Corp Ltd as a captive block. Preliminary estimates suggests it is may hold 2.1 billion tonnes of reserves. Operations of the block will be undertaken by Bengal Birbhum Coalfields, a special purpose vehicle floated for purpose. The Centre had earlier planned to allot the block to a number of states jointly but none, other than West Bengal, showed interest as preliminary production cost estimates turned out to be very high. The Centre finally awarded the block to West Bengal.

The GSI said it has found 44 new coal blocks in four states of Eastern India. Spread across West Bengal, Jharkhand, Bihar and Odisha, the estimated coal resource of these 44 new blocks is close to 25,000 mt GSI said. Of these 44, 15 coal blocks belong to West Bengal.

Rest of the World

China’s coal imports are set to slump in December as traders and utilities wind back purchases following signals from Beijing that it will stop clearing shipments until next year, trading companies and utilities said. Coal imports by the world’s top consumer of the material used for heating and steelmaking rose in the first 10 months of 2018 to 252 mt up 11 percent from a year ago and not far below last year’s total of 279 mt. However, domestic coal prices have eased in recent months, even as China enters its peak demand season over winter, with utilities sitting on record coal stocks amid a slowdown in electricity demand growth. China National Building Materials International, a major buyer of Indonesian and Australian coal, will stop buying foreign supplies in December for its utility clients, the company said. China has in the past imposed coal import restrictions, which has had the effect of increasing local prices by lowering competition. Earlier this year it banned smaller ports from receiving coal and it has also carried out strict inspections on low-quality coal.

China National Coal Group agreed supply deals for thermal coal with six state power utilities that totalled more than 500 mt to be delivered across five years starting from 2019, according to the NEA. Under the agreements, China National Coal Group will supply in 2019 more than 97 mt of coal to the six utilities, with volumes rising in each subsequent year of the deals, the NEA said. Prices for the 2019-2021 supplies will be adjusted monthly using 535 yuan ($77)/tonne as a base price, and prices for the 2021-2023 period will be negotiated between the contractual parties based on market trends.

Australia’s New Hope Corp Ltd will buy a further 10 percent stake in the Bengalla thermal coal mine in Hunter Valley, New South Wales from Japan’s Mitsui & Co Ltd for A$215 million ($155.7 million). New Hope will own up to an 80 percent interest in Bengalla. The mine contributed more than half of the company’s profit last year and is expected to continue producing for more than 20 years. The Mitsui transaction comes three months after Wesfarmers Ltd struck a deal to sell its stake in the Bengalla mine to New Hope, which held a 40 percent stake in the mine at the time. New Hope said Taiwan’s Taipower, which currently holds a 10 percent stake in the mine, will buy another 10 percent from Wesfarmers.

Germany should take care in closing coal-fired power plants to avoid disruption and spread risks evenly, power utility Uniper said. Uniper had proposed including hard coal plants in a security reserve of 2.7 GW of brown-coal fired capacity. A commission is working on a roadmap for phasing out coal as an energy source, similar to Germany’s plan to exit nuclear power. The commission by year-end is due to present its first proposals on enforcing further cuts to carbon emissions from the coal sector. Legal certainty up to 2030 for the operations of gas-fired plants will support investment in that sector and allow voluntary coal plant closure tenders.

Germany has postponed until February a decision on how fast Europe’s largest economy should phase out brown-coal-fired power plants and whether the government should compensate utilities as well as regions that could face job losses, the coal commission said. With brown coal mines the only truly domestic resource in a country reliant on energy imports, Germany faces wrangling over when to abandon coal-burning to meet ambitious climate goals by 2030, as it also wants to be free of nuclear energy by 2022. The German cabinet has appointed a 24-strong group, the coal commission, to find a compromise deal. It was expected to present an exit plan by the end of the year. Postponement of the decision could increase the chances for a broader acceptance of the coal exit plan.

Britain’s Banks Mining has won a high court challenge to the government’s decision to reject its application to develop a new coal mine in northeastern England, the company said. Northumberland County Council agreed last year that the mine’s developer, Banks Mining, a division of The Banks Group, could extract 3 mt of coal by cutting an open cast, or surface, mine near Druridge Bay, Highthorn. Supporters of the project had said it could bring much-needed jobs to the region, and help to reduce Britain’s reliance on coal imports. Britain plans to close all coal-fired power stations by 2025 unless they are fitted with technology to capture and store carbon dioxide emissions, as part of efforts to cut greenhouse gases by 80 percent from 1990 levels by 2050.

Slovakia will phase out subsidies for coal mines supplying one of the country’s most polluting power plants from 2023, sooner than expected. The Slovak government subsidises mining at the country’s only coal company, privately owned Hornonitrianske Bane Prievidza (HBP), paying around €100 million ($114 million) a year, which helps maintain thousands of jobs. The company produced 1.8 mt of brown coal last year, supplying the Novaky power plant in central Slovakia. The facility is operated by Slovenske Elektrarne, a utility co-owned by the state, Italy’s Enel and Czech energy group EPH. Slovenske Elektrarne said this year that extending the life of the 266 MW Novaky plant beyond 2023 would require significant investment. China will offer financial support to improve safety at coal mines in 2019-2020, the NDRC said. That comes after several fatal accidents at coal mine in the country. Coal mines facing a tough financial situation or actively enforcing capacity cuts will be given more financial support, the NDRC said.

Spanish utility Endesa plans to close two of its coal plants in Spain, representing around two-fifths of its coal-fired generating capacity in the country, the company said. As companies globally move towards a lower carbon economy, Endesa’s Italian parent company Enel, is phasing out coal-fired power plants and focusing on electricity grids, renewable energy and its retail business. Endesa’s coal capacity is currently much larger than peers Iberdrola and Naturgy, who respectively run 874 MW and 2,010 MW in Spain.

January-September 2018 coal exports were at 8.7 mt for Indonesian coal miner PT Bukit Asam, up from 6.2 mt in the same period of last year. Over the first nine months of this year, Bukit Asam produced 19.7 mt of coal, up from 16.9 mt in the same period in 2017. Indonesia’s Energy and Mineral Resources Ministry plans to revise rules on mining rights held by miners under Coal Contract of Work. Under proposed changes, miners can apply for extensions to mining rights between five years and one year before contracts expire. Existing rules only allow miners to apply for extensions between two years and six months before contracts expire.

South Africa’s cash-strapped power utility Eskom said the risk of nation-wide electricity outages had increased significantly due to a sharp fall in coal stockpiles at five of its power stations. Eskom said the power firm was using diesel generators to keep the power grid stable. In 2015 Eskom, whose total output of 45,000 MW accounts for 90 percent of electricity supply in the country, carried out controlled outages — known as load-shedding — as low cash flows and administrative issues affected operations. The power firm was also forced to cut power supplies for a few days in July due to a strike by some of its workers. Eskom said the main problem behind the latest threat to power supply were the coal power stations in Mpumalanga province, east of Johannesburg, supplied by commodities firm Tegeta Exploration and Resources, which has halted operations. Heavy rain forecast for coming months would affect coal supplies and quality, Eskom said.

Mongolia aims to complete a railway from its Tavan Tolgoi coal project to the Chinese border by 2021. The rail link from Tavan Tolgoi would have the capacity to deliver 30 mt of coal a year to China. Mongolia expects demand for high quality coking coal from China’s steel sector to increase, but many analysts in China believe steel production is nearing its peak and could start to fall. Tavan Tolgoi is the world’s largest undeveloped coking coal mine with 7.4 bt of estimated reserves. Mongolian coal would only be competitive in southern China, where more imports were required. Poland’s hard coal output in September fell to a record monthly low of 4.89 mt data from the Industrial Development Agency (ARP) showed. Monthly coal production has remained above 5 mt throughout 2018, and September’s output was down from 5.42 mt the previous month. However, Poland’s coal output has been shrinking for months because of the closure of some loss-making mines and reduced investment in an effort to reduce costs. The country has increased coal imports, mostly from Russia, to cover any shortfalls, though government policy is to reduce reliance on Russian supplies. Data showed that Poland’s 2018 coal imports from Russia are on track to be the highest ever.

The World Bank told Kosovo it would no longer support a planned 500 MW coal-fired power plant. Other Balkan countries rely on coal to produce power, with Serbia and Bosnia generating 70 percent and 60 percent respectively in ailing coal-fired plants, and both are in the process of adding new coal capacities. The two old power plants Kosova A and Kosova B are among Europe’s worst polluters. The government said the new plant, to replace Kosova A, would burn 40 percent less coal and release 20 times less emissions.

Greek power utility PPC will receive binding bids for three coal-fired plants and a license for a new one by the middle of next month. PPC, which is 51 percent state-owned, is selling the plants in northern and southern Greece after a European court ruled it had abused its dominant position in the coal market. The utility has shortlisted all six investors interested in the plants.

FY: Financial Year, mt: million tonnes, bt: billion tonnes,  MW: megawatt, GW: gigawatt, CIL: Coal India Ltd, mtpa: million tonnes per annum, US: United States, IEA: International Energy Agency, Mtce: Megatonne of coal equivalent, GIDC: Goa Industrial Development Corporation, GSI: Geological Survey of India, NEA: National Energy Administration, NDRC: National Development and Reform Commission, PPC: Public Power Corp

Courtesy: Energy News Monitor | Volume XV; Issue 26