Outstanding dues of Power Utilities payable to Central Public Sector Undertakings: What does the data reveal?

Ashish Gupta, Observer Research Foundation

Regions Outstanding Dues INR Million Unrecovered subsidy INR Million[1] Performance & Ratings[2] Can they afford renewable energy? Government Role
Select state power utilities having highest outstanding dues


Gujarat Utilities: 2.6

Goa Utilities: 47.4

Madhya Pradesh Utilities: 44.6

Gujarat: 3,720

Goa: Nil


Madhya Pradesh: 37,615

Gujarat: A+


Goa: Not Known

Madhya Pradesh: B

Total Western Region 2,643   Better than earlier Yes, they can. Government can balance the tariffs through additional subsidy and demand side management.
Select state power utilities having highest outstanding dues


Assam Utilities: 3,121.3

Meghalaya Utilities: 3,023.7

Tripura Utilities: 576.9

Mizoram Utilities: 458

Assam: 2,833.6

Meghalaya: 707.1

Tripura: 806.8

Mizoram: 1,442.9

Assam: B


Meghalaya: C+


Tripura: C+


Mizoram: Not Known

Total North Eastern Region 7,734   Bad Tariffs are very low in the North Eastern Region. Doubtful, whether the utilities can absorb additional green power. To increase proliferation, the funding needs to be provided from the central budget.
Select state power utilities having highest outstanding dues Tamil Nadu Utilities: 4,678.4

Andhra Pradesh Utilities: 2,453.9


Karnataka Utilities: 1,683.2

Pondicherry Utilities: 991.8

Tamil Nadu: 85,842.9

Andhra Pradesh: 68,524.6

Karnataka: 2,715

Pondicherry: 445.1

Tamil Nadu: B


Andhra Pradesh: B+


Karnataka: B+ & B

Pondicherry: Not Known

Total Southern Region 11,193.9   Bad  These utilities are already somewhat green. Any increment in the obligation will increase financial burden on the utilities. Government must urge private players to invest in green power with minimal subsidy support.
Select state power utilities having highest outstanding dues Jammu & Kashmir Utilities: 24,327.9

Delhi Utilities: 10,957.5

Rajasthan Utilities: 10,534.6

Uttar Pradesh Utilities: 7,472.5

Jammu & Kashmir: 19,717

Delhi: Not Known

Rajasthan: 110,768

Uttar Pradesh: Nil

Jammu & Kashmir: Not Known

Delhi: Not Known

Rajasthan: C+


Uttar Pradesh: C

Total Northern Region 62,647   Worst  No, they cannot afford green power State governments having separate budget can contribute. But for policy goals the funding needs to be provided from the central budget.
Select state power utilities having highest outstanding dues Jharkhand Utilities: 81,118.3

Bihar Utilities: 1,867.9

Orissa Utilities: 215.7

Jharkhand: 4,569.9

Bihar: 19,284.2

Orissa: Not known

Jharkhand: C+


Bihar: B


Orissa: Not Known

Total Eastern Region 83,890   Worst No, they cannot afford. State government having separate budget can contribute. But for policy goals the funding needs to be provided from the central budget.

 Views are those of the author                    

Author can be contacted at ashishgupta@orfonline.org

[1] The Working of State Power Utilities and Electricity Department, 2011-12

[2] Ratings as per “State Distribution Utilities First Annual Integrated Rating”, March, 2013

Courtesy: Energy News Monitor | Volume XI; Issue 37



Monthly Power News Commentary: October – November 2017


The power ministry has engaged postmen for door-to-door survey to expedite the Saubhagya scheme for complete household electrification by December 2018. India Post through its network 173,000 outlets has begun collecting data on un-electrified households spread over three states of Odisha, Chhattisgarh and Madhya Pradesh. Similar initiatives are being launched in Assam and Jharkhand. The data for a total 175,000 villages in the five states is likely to be submitted in a month. The programme could be extended to other areas. The data is being uploaded online through a web portal and a mobile application by the postmen called ‘Gram Dak Sewaks’ by the postal department. The web portal and the application have been created and are being monitored by Rural Electrification Corp. The data will help the Central government in speedy assessment of project reports that will be submitted by states seeking grant under the Saubhagya Scheme. The Pradhan Mantri Sahaj Bijli Har Ghar Yojana –Saubhagya- launched in September with over ₹ 160 billion outlay for universal household electrification, will cover a total of 30 million—25 million households in rural areas and 5 million in urban areas. As per scheme, the states will have to submit detailed project reports to the Centre. Projects would be sanctioned based on the detailed project reports to be submitted by the states. The postal department will collect status of electrification of households and details of heads of the un-electrified households in villages.

NTPC Ltd has decided to expedite its expansion plans of installing four super-critical units of 660 MW in two more power plants in UP ahead of 2019 Lok Sabha elections. NTPC confirmed that installation of at least one 660 MW units each in Meja (Allahabad) and Tanda (Ambedkarnagar) power plant will be completed in August and September next year. The Tanda power plant, which is totally owned by the NTPC, has a total installed capacity of 440 MW, while the Meja power plant is a new venture being jointly set by the NTPC in association with the state owned UP Rajya Vidyut Utpadan Nigam Ltd. The expansion plans of NTPC also fall in line with the Centre’s ambitious ‘Power For All’ scheme, envisaging round the clock to every household before 2019. Prime Minister Narendra Modi had pressed the accelerator in September by launching the ‘Saubhagya Scheme’ under which electricity connections would be provide to poor families free of cost. The 2000 MW Singrauli power project happens to be the flagship project of the NTPC in UP. Some commentators observed that providing power had now become the path to political power.

Bihar state energy department is to submit within a week a detailed project report to the Centre to seek ₹ 11 billion for providing household electricity connections under Saubhagya scheme that envisages payment of power installation charges to every household in 60:40 ratio by the Centre and state, respectively. The Pradhan Mantri Sahaj Bijli Har Ghar Yojana or Saubhagya scheme launched on September 25 aims at providing electricity connections to over 40 million families in rural and urban areas by December 2018. State energy department has already provided meter-based electricity supply to more than 1.3 million households till date under Mukhya Mantri Vidyut Sambandh Yojana, commonly known as Har Ghar Bijli scheme, launched in Bihar in 2015. The state has allocated ₹ 1,896 billion for providing electricity to 3.5 million APL households under the scheme. The beneficiaries under Har Ghar Bijli scheme are required to pay ₹ 2,200 in 10 easy instalments for electricity connection. However, Saubhagya scheme envisages payment of power installation charges to every household by the Centre and state in 60:40. The scheme also stipulates that Centre would pay 75% of the cost to those states which achieve the desired targets on or before time. Energy department said the state is most likely to be benefited by the incentive as it is set to achieve 100% electrification by December 2018.

UP government is taking slew of measures to improve power supply to the people of the state, counting on initiatives like trust billing system and e solution app. In trust billing system, consumer would be offered the facility of self-billing like filing of income tax return. However, its misuse would invite punitive action, including heavy penalty. Moreover, existing meters would be replaced by “smart meters” in order to monitor the power used by consumer. For ensuring proper roaster and adequate power supply in rural areas, monitoring of line loss in feeder system would be the priority. Encouraging results with the introduction of e. solution app, face-book, twitter, whatsapp and the introduction of toll free number (1912) are expected to become an added advantage to consumer. Import capacity of power has been enhanced from 8,100 MW to 10,000 MW but also the capacity of power been increased from 18,500 MW to 22,000 MW. Priority of the government is on recovery of arrears, providing 21 million new connections, electricity in 75 mazars, ensuring installation of meter in every house, upgrading the transformers and replacing old line with the new ones.

Maharashtra appealed to the farmers to clear their pending power dues without payment of any penalty under the ‘Mukhyamantri Krushi Sanjeevani Yojana’. There are around 4.1 million farmers whose electricity dues are pending. To avail the benefit of the scheme the farmers should pay their current bill immediately. If the bill is not cleared the government will issue order for disconnection. The consumers, whose dues are less than ₹ 30,000 will get the option of paying it in five instalments. The payment dates for this dues are in December 2017, March 2018, June 2018, September 2018 and December 2018. Those consumers whose electricity bill dues are over ₹ 30,000 will get an option to clear the same in 10 installments with a time span of 45 days between each instalment. The government is spending ₹ 6.50/kWh for supplying electricity to farmers, but it is charging merely ₹ 1.80/kWh from them. The present situation is that electricity bill of ₹ 192.72 billion is pending from the farmers. In the last three years not a single electricity connection of a farmer has been disconnected by the government. The government appealed to the farmers to pay their pending electricity bills as the government has to purchase electricity from power supply companies every day.

The farm sector in Telangana will get 24 hours free electricity from March-April next year. The authorities will supply uninterrupted power on an experimental basis across the state. This will continue for five to six days and based on the feedback, the Telangana State Transmission Corp (TS Transco) will take follow up action. Farmers in Telangana are currently getting nine hours free supply every day. The state had been supplying round-the-clock electricity to farmers in three districts on pilot basis. Rao instructed that all the arrangements for distribution and supply systems should be in place for 24-hour power to farmers by March-April 2018. Power generation and transmission corporations and distribution companies are making arrangements for the same. They have spent ₹ 120 billion to strengthen the distribution and supply systems.

Higher electricity demand coupled with supply constraints led to India recording a peak time power deficit of 2 percent in September – highest since April 2016 when the gap between demand and supply stood at 2.1 percent, according to ratings agency Ind-Ra. Ind-Ra said coal inventory levels at power plants declined in September due to a sudden rise in electricity generation from thermal plants amid limited coal output and supply. CIL’s production in September rose 10 percent year-on-year. However, the increase was lower on a month-on-month basis at 3 percent. CIL has increased its supplies to improve the coal situation at power plants. During the month, the growth in coal supply to power plants was 21 percent at 35.1 mt compared with 29.1 mt in September 2016.

NTPC does not want to acquire any stressed assets from private companies. Instead it wants to help banks that take them over for non-repayment of debt, run these stations in lieu of a service charge. NTPC had decided on taking over stressed assets a few years ago. However, it did not end up acquiring any such power units or plants from the private sector although a number of plants were up for grabs. Later the company, decided on taking over assets from state-owned power companies that were not running very well. Latest in NTPC’s list of acquisitions has been the Chhabra Thermal Power Plant from Rajasthan government.

Telangana is on its way to becoming a power surplus state with the construction of new plants to generate additional 13,752 MW. The government has fixed a target of increasing the installed generation capacity to 28,000 MW with an investment of ₹ 940 billion. When Telangana was created the installed capacity was 6,574 MW, a deficit of 2,700 MW. During the last three-and-half years additional 7,981 MW capacity was commissioned. When the state was formed there was severe crisis in power sector with two-to-nine-hour power cuts for domestic sector every day and two-day power holidays in a week for industries. Telangana has created new record in the country by supplying quality power free of cost for 24 hours to the agricultural sector. 25 percent of the power in the state is being utilised by agriculture pump sets. With the 24-hour supply to agriculture sector, the total power demand will increase to 11,000 MW and power utilities were ready to meet this demand. New lift irrigation projects also require 8,500 MW of power. The new power plants will meet the demand for lift irrigation projects and new industries being established in the state. The construction of 4,000 MW capacity Yadadri Ultra Mega Power Plant has started while 1,880 MW of power will be available by 2018 through the power plants which are under construction at Manuguru and Kothagudem. Another 1,600 MW power plant is under construction under aegis of NTPC Ltd. The per capita power consumption has increased from 1,200 units at the time of formation of the state to 1,505 units. This is higher than the national average of 1,122 units. The transmission and distribution systems were strengthened with an investment of ₹ 121.36 billion.

Load-shedding’s back, with sporadic unscheduled power cuts disrupting normal life in several parts of Bengaluru. Power-outage complaints came in from Indiranagar, Chamarajpet, Shantinagar, Rajajinagar, Nagarbhavi, Tatanagar, Malleswaram, Malathahalli, BTM Layout, Madiwala and Mathikere, among other areas. Bangalore Electricity Supply Company said the load-shedding is due to the shutdown of two units of the Raichur Thermal Power Station that normally functions on 4-5 units.

Long power cuts due to grid failure or a natural calamity can cause disruption in mobile telephony services in Delhi NCR any time as use of generator sets for powering towers has been banned till March 15, telecom infrastructure players said. The DPCC following a decision of Environment Pollution (Prevention and Control) Authority has imposed ban on generator sets running on petrol, kerosene or diesel till March 15, 2018. Telecom infrastructure industry body TAIPA said that though mobile towers are deployed with high-capacity batteries including fast charging to extend backup, these cannot run for long in case of long power outage due to grid failure or a natural calamity. TAIPA that as the DPCC has allowed use of generators for essential services such as hospital, railways, airports and elevators, mobile infrastructure should also be included in the list of essential services. TAIPA said that besides need to provide telecom services, telecom operators are required to comply with rules of Telecom Regulatory Authority of India to maintain round the clock network availability with 99.95 percent uptime. Under the new Quality of Service norms, effective October 1, telecom operators may face a maximum penalty of ₹100,000 for call drops which will now be measured at mobile tower level instead of telecom circle level.

IEX said the average spot power price rose by 66 percent to ₹ 4.08/kWh in October compared to the year-ago period, mainly due to supply side constraints. The average MCP for the month at ₹4.08/kWh was almost same as in September, 2017 and 66 percent higher over ₹ 2.46/kWh in October, 2016, the IEX said. According to the IEX, a total volume of 4,079 MU was cleared, almost same as trade volume of September and about 13 percent more over 3,609 MU traded in October, 2016. On a daily average basis about 132 MU were traded. With average daily sell bids at 169 MU against buy bids at 179 MU, the market largely remained a deficit market. The total sell bids during the month were 5,248 MU and the total buy bids were 5,535 MU.

India must move into a single power market for lowering tariffs and better performance by distribution companies, the Chief Economic Adviser to the Union finance ministry, said. In Bihar, there are about 100 power tariff slabs, including separate tariffs for day and night. Given the strength of cooperative federalism, a common market should be created for power sector to make electricity available at the same tariff across the country. Owing to availability of renewable power at lower cost on account of subsidies being given to the installations, discoms (distribution companies) reduce power purchase from thermal units. Though power comes under the concurrent list, states only manage the sector. Centre has powers to prevent discoms from levying cross subsidy. Regulators have to work out ways to introduce a common tariff for the country. The CEA recommended introduction of direct transfer of benefits to beneficiaries’ accounts in the power sector also.

A recent Supreme Court ruling that electricity regulators’ “inherent powers” are circumscribed and can’t be used “to deal with any matter which is otherwise specifically provided under the Electricity Act 2003,” would have implications for many delayed power projects wanting to extend the “tariff periods” under the existing PPAs, industry analysts said. The apex court, in an October 25 ruling, set aside the Gujarat Electricity Regulatory Commission’s order, which allowed a private generator — Solar Semiconductor Power Company — to extend the start of the tariff period from 2010, when the PPA was signed, to 2012, when it actually commenced operations. While the regulatory panel used the power under the Act to extend the tariff period — which would practically raise the tariffs, the court said that such decision, which has the effect of amending the PPA can be done only as per PPA’s own provisions, and not by invoking the regulator’s inherent power. Industry experts believe that the Supreme Court has raised its objections to arbitrary exercise of powers by regulators.

In an unprecedented step, the Karnataka government has overruled a regulatory order that had reduced the tariff the state discom would pay for wind energy projects for which PPAs were signed before this fiscal year. The state has invoked special provisions under Section 108 of the Electricity Act to veto the decision of the KERC — largely an autonomous body — to insist that developers whose PPAs were signed before March 31 this year, should be paid ₹ 4.50/kWh and not ₹ 3.74/kWh as the KERC had laid down. The regulatory order had jeopardised many wind projects.

Three-fourths of LED bulbs sold in India’s $1 billion market were found non-compliant with government’s consumer safety standards, market research firm Nielsen said in a survey. The report, based on a study of 200 electrical retail outlets across major cities like Mumbai, Hyderabad, Ahmedabad and New Delhi in July, found the products to be spurious and riskier, with the highest number of violations in the national capital. In August, the BIS had ordered LED makers to register their products with BIS for safety checks, in a market where smuggling of Chinese products is rampant. The findings showed that 48 percent of LED bulb brands had no mention of manufacturer’s address and 31 percent did not have a manufacturer’s name.

Kerala state electricity board has approached the state power regulatory authority, seeking permission to recoup close to ₹ 750 million from consumers as power surcharge. The power surcharge is demanded for the additional liability of ₹ 746 million the board had incurred for purchasing an additional 3,632 million units of power to meet the demands during the first quarter of the financial year 2017-18, that is, from April 2017 to June 2017. As per the provisions in the electricity act and the regulations issued by the KSERC, the power utility KSEBL can approach the commission, seeking approval for recouping the additional expense on power purchase from consumers. As per KSERC (terms and conditions for determination of tariff) Regulations, 2014 KSEBL is eligible to recover the additional liability on account of variation in actual fuel cost over approved level through fuel surcharge at the rates approved by the commission. The board has also sought commission’s approval for the purchase of 61.5501 million units power from BSES, Kochi.

The Punjab government has ordered an audit of all PPAs signed between the previous SAD-BJP regime and private power companies.  It is alleged that the previous government had signed PPAs with private thermal plants at unreasonably higher rates. After reviewing all the agreements, the government would endeavour to rationalize power tariffs soon. The current government blamed the previous state government for the recent power tariff hike in the state. The SAD-BJP government had signed a tripartite MoU with the central government and Punjab State Power Corp Ltd to hike tariff every year in the state. As per the UDAY MoU, the previous government agreed to a 5% hike in power tariff for 2016-17 and 9% for 2017-18. Punjab was paying fixed charges at ₹ 1.35/kWh to Talwandi Sabo plant, ₹ 1.50/kWh to Rajpura plant and ₹ 1.93/kWh to Goindwal Sahib plant. However, fixed charges for Mundra thermal plant in Gujarat were ₹ 0.90/kWh and for Sasan thermal plant in Madhya Pradesh was ₹ 0.17/kWh only. Power tariff in the state during the previous regime of the Congress government from 2002 to 2007 was raised by 22.51% (average 4.5% per year. The SAD-BJP had effected a hike of 77.33% (average 7.73% per year) during their decade long tenure.

MSEDCL consumers need not fear about paying surcharge to recover cost of extra power purchase done in the past three months to mitigate load-shedding. Calculations done by MSEDCL show that the average rate of extra power purchase was ₹ 3.89/kWh, which is well within the cap of ₹ 4/kWh imposed by Maharashtra Electricity Regulatory Commission. MSEDCL was forced to go for extra power purchase because its power suppliers, including MAHAGENCO, were not supplying contracted quantum due to coal shortage. The acute shortage of fuel had hit private as well as state-run plants. In order to prevent heavy burden on consumers, MSEDCL had preferred load-shedding in high-loss areas in August and September instead of buying power at exorbitant rates. From October, it started buying 1,450 MW on short-term basis, which ended load-shedding. This power purchase was reduced as soon as availability from regular sources increased. Nevertheless, power experts have flayed MSEDCL for load-shedding. According to them, the company should have foreseen the situation and arranged power accordingly.

In a major relief to power consumers in the state, the Odisha Electricity Regulatory Commission rejected the petitions filed by OHPC and OPGC on power tariff hike and kept the power tariff rate unchanged in the state. Both OHPC and OPGC had moved the OERC seeking a hike in power tariff. They sought an average hike of ₹ 2/kWh. However, the petition filed by the Grid Corp of Odisha (Gridco), the bulk power supplier to the consumers, is yet to be heard by the commission. The power generating bodies had filed the review petitions four months after the power tariff was increased by ₹ 0.10/kWh on March 23. A high-level panel will look at possible checks on foreign firms investing in the Indian power sector, a move aimed at preventing cyberattacks on the electricity grid. This comes about two months after the eastern electricity grid suffered a malware attack, allegedly from China. Overseas firms eyeing investments in power plants in the country may have to undergo security clearances and may be mandated to employ majority Indian nationals including at top managerial positions. Most private power generators prefer Chinese power equipment that comes with cheaper line of credit. Chinese firms such as Dongfang Electric Corporation, Harbin Electric International Company and Shanghai Electric have bagged a chunk of equipment orders from Indian power developers in the past. Restricting foreign stake in power companies is a bad idea. Experts said that India must take steps that further its energy security goals, and should focus on making it possible for Indian companies to become competitive. Security checks make sense, especially given the vulnerability of power systems to outside attack. Rather than a diktat on hiring local workers and executives, the focus should be to invest in their training and skilling.

Power tariffs are set to go up in Punjab with the regulator PSERC announcing a 9.33 percent hike in electricity rates for 2017-18. The hike will be implemented with effect from April 1 this year. However, increase in electricity charges will be recovered from consumers in instalments over a period of nine months, PSERC said. The consolidated gap of Punjab State Power Corp Ltd was worked out at ₹ 25.22 billion against power utility’s proposal of ₹ 115.75 billion. The hike in power tariff was announced after a gap of three years. The Commission this year decided to introduce a two-part tariff structure in the new tariff order for all categories except for agriculture sector. For industrial sector, the power tariff has been increased by 8.50 percent to 12 percent while for commercial category, the electricity rates have been jacked up by 8 percent to 11 percent.

The government plans to give electricity consumers the freedom to choose the supplier by enacting a new law that will bring the long-awaited system similar to mobile number portability. It plans to table the necessary bill in the winter session of Parliament that begins in the third week of November, although it has faced resistance from states. Several state distribution companies are keen to protect their monopolistic position, without which consumers can shift to the suppliers they trust. The new bill will usher in competition, which analysts say will attract investors apart from giving consumers reliable supply at affordable rates and reducing losses. The proposal, to separate electricity supply and network maintenance services and introduce multiple licensees for a single area by amending the Electricity Act 2003, has been in works for last many years. The proposal is similar to mobile number portability where consumers can switch to a telecom operator of their choice. Currently, the power distribution utilities are responsible for operating and maintaining distribution system in their licensed areas. Segregation of the network maintenance and electricity distribution businesses is seen as an important reform for improvement in quality of electricity supply services. Earlier the government had planned specific timelines for opening up the retail electricity sector.

Rest of the World

A deal to merge the British retail power businesses owned by SSE and Germany’s Innogy could pave the way for more industry consolidation as pressures mount on the big suppliers in an increasingly crowded market. SSE and Innogy said they planned to join forces in Britain to create a company with $14 billion (£10.7 billion) in sales, which would reduce the country’s “Big Six” energy providers to five if the deal is approved by competition authorities. The new company would be the second largest player in Britain’s retail power market with a 23 percent market share, behind Centrica’s British Gas which has 27 percent.

CNPC has launched a national power company to buy and sell electricity at lower prices, taking advantage of Beijing’s push to liberalize the country’s power markets. CPEEC will primarily source electricity from the wholesale market for CNPC and will also eventually sell power to external customers. CNPC consumes as much as 60 billion kWh each year. That is equivalent to the amount of power that Qatar and Denmark consumed combined in 2014. CPEEC unifies different regional units that CNPC set up to market power in some provinces that have launched power trading platforms. The National Development and Reform Commission has approved the platforms in 13 provinces and the city of Beijing during the past year. In October, CPEEC’s Guangxi branch signed a contract to buy power in the long-term and monthly power markets for CNPC’s Guangxi subsidiary in 2018, CNPC said.

A unit of China’s Shanghai Electric Group Co Ltd is near closing a deal to take over a power transmission project in southern Brazil owned by a subsidiary of Eletrobras (Centrais Eletricas Brasileiras SA). The project in Rio Grande do Sul state requires roughly 3.3 billion reais ($1.0 billion) in investment and had originally been awarded to the Eletrobras unit Eletrosul (Eletrosul Centrais Eletricas SA). Eletrobras said that the companies had reached a non-binding agreement. The deal follows a spree of Chinese acquisitions in the Brazilian power sector. State Grid Corp of China has become Brazil’s second largest electricity transmission company while China Three Gorges Corp is the country’s No. 2 private power generation firm, according to China’s embassy in Brasilia.

Swedish power group Vattenfall has created a new electricity networks business unit in the United Kingdom. The new subsidiary, Vattenfall Networks, is expected to start operations in 2018 and will support Vattenfall’s investments and expansion in the British electricity market. The British energy regulator Ofgem has granted the electricity distribution operating license for the company. This marks the first step for the establishment of a new independent power distribution network. Vattenfall already has experience in operating power networks and in particular smart meters.

A state-run Bangladeshi power generation company has signed a deal with Germany’s Siemens AG to boost its electricity production by more than 20 percent to help support the country’s economic development. North-West Power Generation Company Ltd of Bangladesh said the project would be implemented in three phases and completed by 2021. It aims to produce 3,600 MW of electricity. The project will be set up in Payra of southern Patuakhali district, 320 kilometre (200 miles) from Dhaka and from there power will be transmitted to the capital. At present Bangladesh has only 12.68 trillion cubic feet of gas and it will be exhausted by 2030 if no new gas fields are discovered and the consumption rate remains at the present level. At present Bangladesh has the theoretical capacity to produce power of up to 15,000 MW but it produces a maximum of 10,000 MW. It cannot produce to the optimum level of capacity due to a lack of natural gas and the fact that some plants need upgrade work. About 81 percent people of 160 million population in Bangladesh have access to power.

MW: Megawatt, kWh: kilowatt hour, Ind-Ra: India Ratings and Research, UP: Uttar Pradesh, APL: above poverty line, CIL: Coal India Ltd, mt: million tonnes, DPCC: Delhi Pollution Control Committee, IEX: Indian Energy Exchange, MU: million unit, CEA: Central Electricity Authority, PPAs: power purchase agreements, discom: distribution company, KERC  Karnataka Electricity Regulatory Commission, MCP: Market Clearing Price, LED: light emitting diode, BIS: Bureau of Indian Standards, SAD: Shiromani Akali Dal, BJP: Bharatiya Janata Party, TAIPA: Tower and Infrastructure Providers Association, KSERC: Kerala State Electricity Regulatory Commission, KSEBL: Kerala State Electricity Board Ltd, MoU: Memorandum of Understanding, UDAY: Ujwal Discom Assurance Yojana, MSEDCL: Maharashtra State Electricity Distribution Company Ltd, MAHAGENCO: Maharashtra State Power Generation Company, OHPC: Odisha Hydro Power Corp, OPGC: Odisha Power Generation Corp, PSERC: Punjab State Electricity Regulatory Commission, CNPC: China National Petroleum Corp, CPEEC: China Petroleum Electric Energy Company Ltd

Courtesy: Energy News Monitor | Volume XIV; Issue 24

Monthly Coal News Commentary: October – November 2017


Amid complaints from thermal power plants over inadequate supply of fuel, CIL reported that it has produced 278.01 mt during the April to October period, but missed the target by five percent. The miner, which has a target to produce 292.77 mt during the period, achieved a 1.6 percent growth in production from 273.57 mt produced in the same period last year, its provisional data showed. According to data, CIL produced 46.14 mt in October only, missing the production target of 49.47 mt for the month by seven percent. The Central Electricity Authority’s latest data showed coal stocks available with power plants stands now at an average of six days while 22 plants have very low stocks positions. CIL said the company is “pushing hard” to meet the 600 mt production target for fiscal 2017-18 and the one billion tonne production mark for 2019-20. In October only, its off-take was at 48.28 mt, as against the target of 48.14 mt. The power ministry said coal situation at power plants is “much better” and dry fuel stocks have started building up at the stations. The number of plants facing acute coal shortage has come down. The coal ministry earlier had blamed power producers for low stocks of dry fuel at their plants. A power plant is classified as super critical if coal stock is less than of four days. If a plant has stock for four to seven days, it is termed critical. As many as 295 coal-based power plants have got more time of two to four years to meet strict new environment norms which were to be implemented by December 2017. Despite efforts of state and central governments, the coal stock position in power plants of the state remains alarming. Not a single power plant in the state that supplies power to MSEDCL has adequate coal stock. Any disruption at the mines or in railways will see return of load shedding. Ideally, a plant should have over 14 days’ coal stock to ensure that generation is not affected even if there is a major disruption at mines or in railway traffic. Among MSEDCL’s suppliers, Parli plant of MAHAGENCO has the maximum stock equivalent to 9.5 days of its daily coal consumption. In order to avoid load shedding in the state, MAHAGENCO is generating at full capacity unmindful of the stock. However, any reduction in supply due to a variety of reasons will force the company to reduce production.

In the backdrop of robust demand for coal, the government has asked CIL to ramp up the production and dispatch to 2 mt/day against around 1.6 mt at present. The direction to CIL comes at a time when the power plants in the country have low fuel stocks. The dispatch of coal to the power sector in the month of August has been 14.4 percent higher compared to the same month last year, and 22 percent higher in September as against the same month last year. In view of increased demand for coal the government has also asked CIL to liquidate its stock at pithead and bring it down to nil from present 30 mt. In order to liquidate the old stock CIL is dispatching vigorously. Rajasthan Urja Vikas Nigam had said power generation at thermal power stations has reduced by 2,700 MW due to shortage of coal, forcing it to resort to load shedding in the state.

The coal ministry has drafted a coal supply augmentation plan to supply 730,000 tonne of fuel on a priority basis to multiple states in a bid to tackle shortages at thermal power plants. As per the plan, it has been decided to supply 220,000 tonne coal to Uttar Pradesh, 129,000 tonne coal to Madhya Pradesh, 56,000 tonne to Gujarat, 52,000 tonne to Rajasthan, 187,000 tonne to Maharashtra and 84,000 tonne coal to Tamil Nadu on a daily basis. Many states have recently complained of coal shortages leading to disrupted power supply. Following a review meeting last month, the ministry had decided to increase coal loading through railway rakes to 250 rakes per day by CIL of which 225 rakes per day were to be supplied to the power sector. Heavy rain this month in the coal belt areas of the eastern parts of the country which had an impact on production at CIL subsidiaries BCCL, ECL, MCL, and CCL. The overall loading of railway rakes stood at 214.6 per day in the current calendar year so far, 4 percent higher than the loading during the same period last year. In October, the average loading has increased to 209 rakes per day as compared to 173 rakes in October last year. Also, the power sector’s share in coal loading has grown to 94.6 percent in the current month as compared to 82.8 percent in October 2016. The power ministry had said it is coordinating with its coal and railways counterparts to address the issue of temporary shortages due to the rise in demand for thermal power.

From a comfortable position, the Tamil Nadu power situation has suddenly turned precarious due to hot and humid weather this time of the year. Coal shortage and shutdown of unit 2 of Kudankulam along with a unit in Vallur plant have disrupted supply, which had been smooth until a month or two ago. Residents in Chennai have been complaining of unscheduled outages. Wind power generation has ground to a halt and there is coal stock only for three days for the state’s thermal power units against the normal stock position of 30 days. Unit one of Kudankulam is functioning only at 50% capacity.  Despite both the units being commissioned two years ago, the nuclear units at Kudankulam reactor have not touched maximum capacity generation of 1000 MW each. The unit 2 will generate power continuously, provided there is no problem for three months. From February next year, the unit will be shut down for annual maintenance.

Fuel supply to power stations from CIL’s mines has risen 17% in September to 32 mt from 27.4 mt in the year-ago period as the government scrambled to meet spike in demand as a result of thermal power stations stepping up operations to meet shortfall from other sources. According to the coal ministry, CIL’s supplies to power stations was 6.8% higher at 205.5 mt in the April-September period than the previous corresponding period. CIL is the anchor source for coal, accounting for 80% of supplies. The Dhanbad-Chandrapura railway line was shut on safety fears just when CIL was in the middle of reducing its pithead stocks by pulling back production. Next, unprecedented rains hit Central Coalfields Ltd production.

Electricity generator MAHAGENCO said the coal stock situation is improving in Maharashtra as the companies supplying the fuel to it have overcome the monsoon calamities. Since September, due to untimely rains and shortage of coal stock with MAHAGENCO, the power production declined resulting in state distribution company Mahadiscom resorting to load shedding for almost 8-10 hours. It said the situation improved especially after a high level joint meeting. Through these measures, MAHAGENCO is in a position to increase its power generation by 800-1000 MW per day in comparison with that in previous month. Load shedding had started in Maharashtra in September due to coal shortage in thermal plants supplying power to Mahadiscom.

Two of the biggest states in the country, Rajasthan and Maharashtra, have around 40 percent of their generation capacity under outage due to coal shortage. Data with the Central Electricity Authority says of the installed 32,973 MW in Maharashtra, 13,555 MW is under outage. In Rajasthan, 4,865 MW of the installed 11,114 MW is shut down. Barring a few under maintenance, major power plants in these states have mentioned “coal shortage” as the reason for the shutdown of the generating unit. In Rajasthan, a 250 MW unit at Chhabra, 600 MW at Kalisindh, two units of 110 MW each at Kota, 693 MW at Surtagarh and 600 MW at the Kawai TPS have indicated coal shortage on the CEA website for outage. The TPS in Maharashtra which are shut due to coal shortage are Chandrapur (720 MW), Khaparkheda (420 MW), Koradi (210 MW), Paras (2×250 MW), Amravati (3×70 MW), GMR Warora (2×300 MW), Mauda (2×500 MW) and Solapur (600 MW). Neither state’s energy secretary responded to calls or SMS sent to them for comment on the coal supply shortage. Coal stocks at power plants across the country have declined to a point where they can meet the requirement for an average of only five days. The average was six days a week before.

Karnataka has asked the Centre to ensure adequate supply of coal and early allocation of a coal block situated in Odisha to meet the severe fuel shortage being faced by power units in his state. Earlier, Rajasthan Urja Vikas Nigam had said that power generation at thermal power stations has reduced by 2,700 MW due to shortage of coal, forcing it to resort to load shedding in the state.

Karnataka is said to be missing an opportunity to reduce cost of power by 84 paise per unit by ignoring the railway ministry’s advice to discontinue the practice of transporting half of the coal supplies to Raichur power station by rail-cum-sea route and move the entire fuel supplies by rail. Karnataka is losing the opportunity to reduce coal cost by ` 1,200 per tonne by sticking to the rail-cum-sea route even after augmentation of rail capacity. Karnataka had sought additional coal from the Centre and urged it to allot a captive mine in Odisha. Raichur power station is supplied coal from Mahanadi Coalfields Ltd mines in Odisha’s Talcher district. The company also supplies fuel to power stations in other southern states. Because of limited capacity in southern rail routes, these states were traditionally advised to move part of coal through the costlier rail-cum-sea route, involving movement from Talcher through Paradip and Krishnapatnam ports in Odisha and Andhra Pradesh, respectively. Under pressure from the Karnataka government for moving 100% supplies through rail, the Railway Board in 2014 relented and agreed to move half the supplies through rail, which is cheaper. Karnataka government has said power stations in Bellary and Raichur districts are facing shortage and have coal stock of less than a day. Besides MCL, WCL and SCCL are the main suppliers. During the first six months of this fiscal, both MCL and SCCL have met their supply commitments of 2,670,000 tonnes, but WCL has supplied about 49% of the allocated 1,163,000 tonne of coal.

Indian railways witnessed a growth of 5.76 percent in freight earnings to ` 81.39 billion in September after higher demand from power utilities jacked up coal loadings. Total freight earnings stood at ` 76.95 billion in the same month last year. In a review meeting of the coal sector, the coal ministry had issued a set of directions in a bid to ramp up coal supply. The ministry had decided to increase coal loading through railway rakes to 250 rakes per day by CIL of which 225 rakes per day were to be supplied to the power sector. Coal, which accounts for 47.54 percent of the national carrier’s freight basket, saw a growth of 3.13 percent over last fiscal year. The coal loading in September stood at 42.84 mt as compared with 39.71 mt in the same period, last year. Indian railways even surpassed its monthly target in September by 0.65 percent which stood at 42.19 mt. The national carrier’s freight loading target for the current financial year stands at 1,165 mt of which the target for coal amounts to 555 mt. Fresh power ministry data shows coal based thermal power generation grew 17 percent in August after hydro power generation dipped 12 percent and nuclear power generation dropped 36 percent over the corresponding month last year.

Gujarat’s tender to buy 1,000 MW of coal-based electricity received dismal response with only one company participating in the bid, that too with an offer to sell only 500 MW of power. State electricity department said that GMR Chattisgarh offered to sell power to the state under the ‘flexible utilisation of coal’ scheme. While the ceiling tariff for the reverse auction was kept at ` 2.82/kWh, GMR agreed to sell electricity at ` 2.81/kWh. The state is now awaiting the approval of the Gujarat Electricity Regulatory Commission to complete the deal. The tender under the ‘flexible utilisation of coal’ scheme, popularly known as ‘tolling’, were invited in August — the first of its kind after the Centre introduced the scheme in May 2016 to bring some respite to 28,000 MW of thermal power plants without regular fuel supply arrangements with Coal India. Under the mechanism, Gujarat will transfer the coal allocated to power generating stations owned by GSECL to more fuel-efficient private plants. Coal-powered GSECL plants’ power-sale price range between ` 2.92-5.42/kWh. GSECL has allocation from Korba coalfield in Chhattisgarh and Korea Rewa coal field in Madhya Pradesh in ratio of 80:20.

The power producers are now asking for a separate index for deciding the price of coal and its transportation, because, they are claiming, they pay more than what the indices work out. The cost of coal comprises several elements before it lands at the power unit. These include taxes imposed by states, the cess imposed by the Centre and states, the coal terminal surcharge, the busy season surcharge, and the development surcharge during various demand seasons. The clean energy cess is imposed to recover the cost of investment in renewable and environment projects. The tax and surcharges on transportation are done by the railways in accordance with rake availability and seasonal demand for coal and wagons for it.  The faulty coal and transportation price escalation index, where presently 49 percent of coal costs and 21 percent of fuel transportation costs are not covered, has been leading to under-recovery to the tune of ` 84 billion for 12,000 MW of installed generation capacity, the Association of Power Producers said. Cases on allowing such costs as pass through are pending in several courts and regulatory bodies. The power developers have asked for passing through of these charges under “change in law”. The National Tariff Policy, 2016, has laid down that any change in cost after a project has been awarded would come under the category of “change in law” and would be allowed to be passed through in the final cost of power. However, any change in power tariffs requires approval from either the state or the CERC. The CERC in an order of October last year had observed that the index for deciding the cost of coal and its transportation needed revision.

The twin projects of the proposed transportation of coal and nationalisation of six Goan rivers came under scathing criticism at several gram sabhas across the state, as members and elected panchayat representatives unanimously adopted resolutions to oppose them. Panchayats in Goa’s southern border in Loliem-Polem to Uguem in Sanguem in the east and Agarvaddo-Chopdem in the north opposed the nationalization of rivers. In some cases, like Agarvaddo, the members protested against only the nationalization but did not take up the issue of coal transportation. In Calangute, the gram sabha opposed the increase in coal handling at Mormugao and the transportation of coal as it will lead to pollution and respiratory diseases, as well as the nationalisation of rivers. Goa Against Coal said over 20 panchayats took up the twin issues at their gram sabhas and adopted resolutions, opposing the projects. The stakeholders expressed fears that nationalization of rivers would destroy the ecology in estuarine areas and displace traditional communities plying their occupations of fishing. The transportation of coal would cascade into a serious health issues, if the expansion proposals were taken up, they said.

According to the coal ministry, CIL would be taking up clean coal technologies like coal to liquid, coal to poly-chemicals and coal to methanol in a big way.  The coal ministry has fixed four priorities for CIL — quality, safety, environmental management and clean coal technologies. CIL would generate greater profits by better efficiency and larger volumes. Construction of washeries are to be accorded a high priority.

The coal ministry launched a mobile application to facilitate smooth despatch of coal by road transport to customers of CIL. The “Grahak Sadak Koyla Vitaran” app was unveiled recently in Kolkata by Coal and Railway Minister Piyush Goyal, the ministry said. The app also provides details of coal allotment and lifting status for the convenience of customers from different sources. In a move to provide more coal to power stations, CIL had earlier directed supplies via road to plants located at shorter distances. The ministry said that of CIL’s total despatch of 542 mt in the last fiscal, 140 mt, or around 26 percent was despatched by road.

CIL said its arm MCL is examining the show cause notices issued to it by the Odisha government for violating environment norms and other regulations. Odisha’s mines department had a few days back issued show cause notices and slapped a penalty of ` 201.69 billion on MCL on charges of violating environment norms and other regulations. MCL is studying the show cause notices and taking the required actions.


Former New York mayor Michael Bloomberg’s charity gave another $64 million to a campaign that aims to slash the number of US coal-fired plants by two thirds by 2020, he said. Bloomberg Philanthropies made the donation to the Beyond Coal campaign run by non-profit Sierra Club, and other organizations fighting the burning of coal. Including this latest donation, the charity has given $110 million to Beyond Coal since 2011. The pledge was made a day after President Donald Trump’s environmental regulator announced a move to scrap former president Barack Obama’s Clean Power Plan that would have reduced carbon emissions from coal plants. The Trump administration labeled the Clean Power Plan part of a “war on coal” by Obama. But Bloomberg said that since the plan has been tied up by the courts and never came into effect, the real threat to coal comes from competing power sources, such as cheap natural gas, solar, and wind power, as well as communities, local governments and companies concerned about public health. Since 2011 nearly half of the country’s coal-fired power plants, or nearly 260 plants, have been closed. Beyond Coal wants to push communities to fight coal plants which emit carbon and particulates blamed for lung and heart problems. It aims to increase closures to some two-thirds of the US coal fleet by 2020. While domestic coal use is under pressure, coal exports have risen this year amid high global demand. The Energy Information Administration, the independent statistics arm of the Department of Energy, said that US coal exports were up 62 percent from January to July, compared to the same period in 2016. But US coal-fired power plant closures have continued apace since Trump came to office in January.  According to experts this compromised the objectivity of Bloomberg new energy finance.

China’s Shanxi province has sold mining rights for 10 CBM blocks, the first such deal after the government’s decision this year to use auctions as primary means for distributing rights. Seven regional firms obtained the rights to the blocks, estimated to contain a combined total of 430 billion cubic meters’ worth of coalbed methane, but did not say how much the rights were sold for. Shanxi has 8.3 trillion cubic meters of CBM assets, accounting for one-third of the nation’s reserves.

China’s small coal miners are still losing money and struggling to pay off debt after being ordered to shut inefficient, outdated operations and forced to miss out on a historic price rally, China’s Coal Industry Association Vice Chairman Jiang Zhimin said. Jiang Zhimin flagged the widening gap between big state-owned coal producers and the smaller private ones in the world’s top consumer of the fuel in the wake of a crackdown by Beijing on illegal mines and curbs on coal transport by trucks. China’s coal market is expected to be balanced in the fourth quarter, he said.

China’s Datang Corp has 28 days of coal stocks for its power plants, enough for winter consumption, the company’s general manager Chen Feihu said, brushing off concerns that utilities could not secure coal supplies for winter. That amount of supply is higher than China’s five major utilities were storing at this time last year. Overall Datang has abundant coal supplies but power plants in the three north-eastern provinces of Heilongjiang, Liaoning and Jilin still face some tightness, Chen said. Chen said Datang will build a large-size coal reserve center in Heilongjiang, to help safeguard coal supplies for the area, without giving the amount of capacity. Chen expects coal prices to return to a reasonable range as the government looks to increase coal mining capacity from mines with more advanced production technology.

China’s state planner the NDRC said it will allow power plants to send more electricity to the grid if they sign more long-term coal supply contracts with miners in Beijing’s latest move to help calm a red-hot coal market. Long-term supply deals between utilities and coal producers will help calm volatile coal prices, the NDRC said. Coal prices remain high as utilities look to book winter supplies in the peak demand period for the fuel. The rising prices, increasing safety checks and low domestic production rates have all added to concerns that supply may tighten. The NDRC urged utilities to sign long-term purchase contracts with coal producers for next year as early as they can to secure enough supplies for this winter.

Authorities in Shanxi, one of China’s biggest coal-producing regions, said they plan to close nine more coal mines by the end of this year, according to a post on a government website. The planned closures come after authorities in the region vowed to suspend or slow the construction of 12 mt of coal production capacity from 2016 to 2020 to battle oversupply. The closures will mean the suspension of production in mines which produced a total of 5.25 mt of coal a year, said Shanxi authorities. In May, the province said it would shut 18 collieries and cut 17 mt of coal capacity this year.

Enel has agreed to divest its 10% stake in Indonesian coal producer Bayan Resources, held through its subsidiary Enel Investment Holding to Bayan’s controlling shareholder Low Tuck Kwong, for a consideration of $85 mn. Enel purchased a 10% stake in Bayan coal producer in August 2008, during the Initial Public Offering (IPO) resulting in the listing of the Indonesian company in the Jakarta Stock Exchange. Bayan is an Indonesian integrated coal producer. Bayan is engaged in open cut mining of various coal qualities from mines located primarily in East and South Kalimantan, Indonesia and is also working through its subsidiaries in various business sectors, including port service management, coal loading, barging, contractor and heavy equipment rentals.

PT Adaro Energy Tbk, Indonesia’s second biggest coal miner by production, said  coal prices may be relatively stable in 2018. Coal production in Indonesia, the world’s top thermal coal exporter, is expected to increase 5 percent in 2017 and 2018 from an estimated 440 mt in 2016. Domestic consumption is expected to reach 101 mt this year. Coal is around 57 percent of the country’s energy mix, although the government wants to roughly double the share of renewable energy by 2025. Domestic and Southeast Asian coal demand was “quite strong”, but big price fluctuations in 2018 are unllikely. Adaro expected to keep its output “stable” in 2018, compared with targeted production of 52-54 mt in 2017. Adaro is developing 2,200 MW of coal-fired power plants and aims to expand that to as much as 4,000 MW of capacity within five years.

A group of investors including buyout firm Apollo and pension fund Canada Pension Plan is bidding for coal assets put up for sale by mining giant Rio Tinto, which could fetch $2 billion. The sale, run by Credit Suisse, of the Kestrel and Hail Creek coking coal mines is part of Rio’s planned exit from Australian coal to focus on iron ore, copper and aluminium. Interested parties have been invited to submit tentative offers by a December 8 deadline. Rio Tinto has just completed the sale of its Australian Coal & Allied thermal coal unit to China-backed Yancoal Australia for $2.69 billion.

CIL: Coal India Ltd, mt: million tonnes, MSEDCL: Maharashtra State Electricity Distribution Company Ltd, MAHAGENCO: Maharashtra State Power Generation Company, MW: Megawatt,  BCCL: Bharat Coking Coal Ltd, ECL: Eastern Coalfields Ltd, MCL: Mahanadi Coalfields Ltd, CCL: Central Coalfields Ltd,  Mahadiscom: Maharashtra State Electricity Distribution Company, TPS: thermal power station, WCL: Western Coalfields Ltd, SCCL: Singareni Collieries Company Ltd, kWh: kilowatt hour, GSECL: Gujarat State Electricity Corp Ltd, CERC: Central Electricity Regulatory Commission, US: United States, CBM : coal-bed methane, NDRC: National Development and Reform Commission

Courtesy: Energy News Monitor | Volume XIV; Issue 23


Monthly Gas News Commentary: October 2017


India wants to attract foreign investors to $300 billion worth of energy projects planned for the next decade. India ships in about 80 percent of its oil needs and India aims to reduce this to 67 percent by 2020. The planned projects will include increasing the country’s refining capacity, oil and gas block exploration, and developing gas infrastructure, including for transporting LNG and regasification. India’s oil and gas output has been stagnant for years while its fuel demand has risen with economic expansion, hitting federal finances with an import bill worth billions of dollars.

IOC aims to have capacity to import about 13.5 mt of LNG in five years helping India to gradually move to a gas-based economy. The government wants to raise the share of natural gas in India’s energy mix to 15 percent in the next few years from about 6.5 percent now. IOC currently holds rights to annually import 2.25 mt of the super cooled fuel at Petronet LNG’s Dahej terminal in western Gujarat state. The company is betting big on growing demand for natural gas for transport and manufacturing. It has a target to generate 15 percent of its revenues from its gas supply and distribution business by 2021. IOC is adding capacity through its own upcoming LNG terminal and through stakes in other regasification plants. It is in talks to buy about a 25 percent stake in the 5 mtpa Mundra LNG terminal, besides leasing 1 mt of capacity at Swan Energy’s 5 mtpa facility at Jafrabad. Both of these plants are being built in the western state of Gujarat. Western India is connected with pipelines and LNG import facilities, while industries in the east are still deprived of the cleaner fuel because of a lack of infrastructure. To fill that gap, IOC is building a 5 mtpa LNG import terminal at Ennore on the eastern coast. It has also booked 3 mtpa of capacity at Adani Enterprises’s 5 mtpa Dhamra LNG terminal and plans to lease about 0.5 mtpa of capacity at Petronet’s Kochi LNG plant in south India. IOC, which has long-term agreement to import 0.7 mt from the Cameron LNG Project in the United States, is scouting for more such deals. Supply from the Cameron project will begin by end of 2018. The company is also looking at a mix of long-term and LNG spot deals. Currently, the company on average imports two spot LNG cargoes a month.

India is pushing to renegotiate more LNG deals after its success in reaching agreements with some of the world’s largest energy suppliers. GAIL (India) Ltd is working toward renegotiating two more long-term deals. Those would follow new deals with Qatar’s RasGas Company in 2015 and Exxon Mobil Corp that saw the Indian buyer get lower prices in exchange for agreeing to purchase higher volumes. GAIL is renegotiating its 20-year contract with Russia’s Gazprom PJSC. India, the world’s fourth-largest LNG buyer, is increasingly relying on imports as it seeks to double use of the fuel by the end of decade amid falling domestic production. The recent renegotiation of an existing LNG contract between PLL and Exxon Mobil would open the doors for similar re-negotiations for companies like GAIL who are also trying to re-negotiate such contracts, ratings agency ICRA said. ICRA said that similar to PLL, GAIL has also been trying to re-negotiate its contracts and swap the LNG with other marketers in other regions of the world.

The petroleum ministry will soon send a proposal to the Cabinet to set up a gas trading exchange that will replace the current pricing structure for natural gas. The country will gradually move towards market-determined prices for gas. Priority sectors will get gas at government-determined prices during the transition. The ministry is planning to set up a think-tank to take advice on policy reforms and will consist of industry representatives and experts from India and abroad. The government is exploring an investment opportunity of $300 billion in hydrocarbons sector over the next 10 years. The petroleum ministry also launched a new ‘Forum for Energy for New India’. The industry was tasked with the challenge of putting one of India’ basins in the north-east on Super Basin list: Cambay, or the KG Basin.  The term was coined by IHS Markit ‘Super Basins’ for 25 basins around the world that have at least 5 boe of recoverable resources remaining.

Japan and India have taken their discussions of LNG technologies in inland water and coastal shipping forward. Enhancing cooperation in establishing a transparent, efficient, truly global and balanced LNG market is also being discussed between the two countries.

As the government is unlikely to implement major policy-level interventions in the CGD entities either through a change in the gas allocation policy or capping the returns earned by them, their return profiles are likely to remain structurally strong, Credit rating agency Ind-Ra said. The business profile is strengthened by the players’ sole supplier status in their respective geographical areas, supply-side advantages in the form of access to crucial inputs such as gas supply and availability of land for setting up a marketing infrastructure for both CNG and PNG. According to Ind-Ra, CGD as a space complements the government’s move towards cleaner fuels and any policy directed towards lowering the importance of CGD could derail the objective. It is believed that OMCs do not pose a threat to the business models of CGD players in terms of setting up their own city gas infrastructure post marketing exclusivity.

RIL and its partners, BP and Niko Resources, have so far paid only $82 million to the gas pool account, maintained to park the differential between the notified gas price given to others and the $4.2/mmBtu that the three contractors charge their customers. The firms are yet to pay the penalty imposed on them for disallowing recovery of cost incurred for missing the target during six years from 2010. After a fresh penalty of ₹ 264 million in August, the total now stands at $3.02 billion. Fining them, the government had cited their failure to drill the committed number of wells and producing less than the targeted natural gas from the Dhirubhai-1 and 3 fields in the eastern offshore KG-D6 block. Production was supposed to be 80 mmscmd. The firms have contested the fine. They are of the view that the disallowance of costs incurred by the joint operation has no basis in the production-sharing contract and that there are strong grounds to challenge the government’s position. RIL and its partner BP will invest over $1.5 billion in six satellite gas discoveries in the KG-D6 block, the combine has said in a refreshed plan for starting production from these finds by 2022. This is part of Reliance-BP’s plan to infuse ₹ 400 billion (over $5 billion) into the block and marks the beginning of the investment cycle in the east coast as a result of policy reforms, especially allowing remunerative price to producers, initiated by the government. Besides the six discoveries, Reliance-BP is also working on development plan for R-Series and MJ gas discoveries in the block. RIL-BP combine does not plan to alter the $3.18 billion investment plan for D-34 or R-Series gas field in the same block, which was approved in August 2013. About 12.9 mmscmd of gas for 13 years can be produced from D-34 discovery, which is estimated to hold recoverable reserves of 39.6 bcm. A separate development plan for the MJ find would be submitted by mid-2018. RIL and its partner BP have submitted to the government a $2 -2.5 billion plan to bring to production India’s deepest gas discovery by 2021-22. The partners submitted to the DGH a field development plan (FDP) for the MJ-1 gas find, which is located about 2,000 meters directly below the currently producing Dhirubhai-1 and 3 (D1 and D3) fields in the eastern offshore KG-D6 block. MJ-1 is estimated to hold a minimum of 27.9 bcm of contingent resource. With this, RIL-BP have finalised investment plans totalling $5-5.5 billion (about ₹330 billion to ₹ 360 billion) for three sets of discoveries in the KG-D6 block. Earlier this month, they submitted an FDP of $1.4 billion for bringing to production six satellite gas discoveries in the block. RIL-BP combine had in 2013 submitted a $3.18 billion investment plan for D-34 or R-Series gas field in the same block, sources said adding the actual investment in the find may actually be $1.4-1.6 billion only. The investment in MJ-1 would be slightly higher because a floating production storage and offloading (FPSO) will be used to produce the gas. Work on the three sets of discoveries will start sometime in 2018 and contracting for equipment and services has already started.

Since November 1, 2014, after the new domestic natural gas price came into effect, the contractors were being paid the earlier price of $4.2/mmBtu and the difference between this and the revised price was getting deposited to the gas pool account. Niko said that commencing April 2016 and, thereafter, to date, the revised gas price under the guidelines was below $4.2/mmBtu and deposits were not required to be made to the account. The companies were, therefore, also not paying to the account for nearly 18 months, despite lower gas-price regime. The government fixes prices based on a formula linked to key gas markets across the globe. Analysts cite the prices were below $4.2/mmBtu much before March 2016, they were down to $3.82/mmBtu in October 2015. Since October, the prices came down further to $2.89/mmBtu. This means RIL and its partners should have deposited a larger amount of differential into the account.

In a novel initiative by the petroleum ministry, 10 oil and gas companies under it launched a startup programme for entrepreneurs with a fund corpus of ₹ 3.2 billion to be disbursed over a 3-year period to support innovations in the energy sector. The scheme was launched with MoU being signed by 36 startups for partnering with various state-run firms like IOC HPCL and GAIL (India) Ltd, which is India’s largest gas transmission utility. It is believed that India could not afford to miss out on the ongoing Industrial Revolution 4.0 that signifies the changes being wrought by information technology.  The third largest energy consumer in the world with an annual oil import bill of ₹ 7 trillion, India wants to act on import substitution.

The supply of PNG is about to be initiated in Odisha. With this, GAIL (India) Ltd started supply of environment-friendly PNG to 255 houses in Nalco Nagar located at Chandrasekharpur area in the state capital. The supply of PNG to a limited households was done ahead of its schedule in March 2018. PMUG will pass through five states like Uttar Pradesh, Bihar, Jharkhand, Odisha and West Bengal. The longest stretch of the project, which is about 769 km will be built in Odisha. CGD projects in Bhubaneswar and Cuttack are being taken up in parallel with the JHBDPL. In Odisha, the Natural Gas Pipeline will be constructed at an estimated investment of ₹ 40 billion and will have a length of about 769 km covering 13 districts, like Bhadrak, Jajpur, Dhenkanal, Angul, Sundergarh, Sambalpur, Jharsuguda, Debagarh, Jagatsinghpur, Cuttack, Khurda, Puri and Kendrapara. Initially, natural gas will reach Bhubaneswar in special containers which will be transported by road from Vijaywada in Andhra Pradesh. Later, natural gas will be supplied through the JHBDPL. The pipeline is presently under construction and likely to be completed by 2019. In Bhubaneshwar and Cuttack, the number of PNG connections will be gradually ramped up in the next three to five years. Moreover, 25 CNG stations will be commissioned in the twin cities to supply CNG fuel to vehicles.  Some experts said that the proposal has high probability of success as the supply of household energy such as electricity and cooking fuel (LPG or PNG) have become vote winners from women voters. With expectation of state elections and speculation on the oil minister’s chances of becoming the chief minister, energy schemes are likely to receive the highest priority from the ministry.

India and Mozambique agreed to expedite development of the giant Rovuma gas discovery, which is planned to be converted into LNG for exports. OVL the overseas arm of state-owned ONGC holds 16 percent stake in Mozambique offshore block Rovuma Area 1. OIL has 4 percent stake while a unit of BPCL holds 10 percent stake. The Area 1 covers roughly 10,000 square kilometre area and is located in northernmost part of offshore Mozambique Rovuma Basin. According to OVL, second and final exploration phase for Area-1 ended on January 31, 2015 and have resulted in five discoveries, with combined recoverable resource of about 1.7 tcm. Area-1 represents one of the largest natural gas discoveries in offshore East Africa and has the potential to become one of the world’s largest LNG producing hubs. Area-1 plans to develop initially two LNG trains of capacity 6 mtpa each.

Prepaid smart cards has been launched for CNG consumers in Delhi. The cards introduced by gas distributor IGL are expected to allow customers to save time at CNG stations. It is being promoted as part of GAIL and IGL contribution to the Digital India Campaign.

The Maharashtra Natural Gas Ltd (MNGL) plans to expand its PNG network to areas like Bibvewadi, Baner, Balewadi, Pashan, Sahakarnagar, Undri and Pisoli. This will take PNG to 1 lakh households this fiscal year. PNG is currently being supplied to more than 58,000 households in Pune and Pimpri Chinchwad for cooking purposes. Areas such as Hadapsar, Magarpatta, Vimannagar, Kothrud, Model Colony, Warje, Sinhagad Road, Erandwane, Pimpri, Nehrunagar, Ajmera, Chikhali, Moshi, Chinchwad, Chakan, Hinjewadi and Wakad currently have PNG connections. Being a pollution-free fuel, PNG is easily accessible without storage troubles. In November 2015, the urban development ministry had asked all states and municipal corporations to supply PNG and CNG stations in smart cities. Petroleum and natural gas authorities had urged the civic bodies to ensure speedy approvals for laying gas distribution pipelines in smart cities.

Despite Tripura being the toughest zone for gas exploration in the world, the success ratio is the best, according to ONGC. ONGC has drilled 225 wells in Tripura so far, of which 116 were found to be gas-bearing. The company would start exploration works in the Tichna area after it gets forest and environment clearance from the central government within the next six months. ONGC has, since 1962, established around 41 bcm of recoverable gas reserves in Tripura’s 11 gas fields. ONGC had to spend ₹ 1.6 million/ day for drilling of gas in Tripura against ₹450 million in the deep sea areas. The firm had commissioned its first commercial gas-based power project in India, located in Palatana, 60 km south of Agartala, and run by the ONGC Tripura Power Company.

Upstream oil regulator DGH has refused to review the commerciality of India’s deepest gas discovery made by ONGC on grounds that developing the find poses technological challenges. ONGC plans to invest ₹ 215 billion to develop the ultra deepsea UD-1 discovery in its Bay of Bengal block KG- DWN-98/2 (KG-D5) by 2022-23. The find would have helped double the output from the KG block. It had earlier this year submitted to the DGH for approval a DoC of UD-1 find. DGH refused to review the DoC on grounds there was no technology available to produce gas from such water depths. ONGC plans to drill nine wells on the discovery that lies in water depths of 2,400-3,200 metres and will produce a peak output of 19 mmscmd.

With shale gas business becoming uneconomical due to low crude oil prices, RIL has said it would sell its remaining shale gas assets in the US if any company makes it an “attractive offer”. RIL has invested almost $9 billion in US since 2010. The company was not a distress seller of its shale gas assets and at the same time is not looking to acquire any more assets. At present, RIL owns 45 percent stake in Pioneer Natural Resources’ Eagle Ford shale block and 40 percent stake in Chevron’s asset. On October 11, the company had announced that it sold its Marcellus shale assets for $126 million to BKV Chelsea, an affiliate of Kalnin Venture. RIL had bought stake in Marcellus shale-gas areas of Pennsylvania for $392 million In August 2010. RIL was one of the early investors in the US shale gas assets, but was earning negative returns on its investments since fall in crude oil prices made shale gas production unviable. RIL has agreed to sell a shale oil and gas block in the US for $126 million, a third of the price it paid seven years ago, amid a downturn in global oil prices. It could further receive $11.25 million based on changes in natural gas prices. RIL bought the Marcellus asset in 2010 for $392 million. The US shale market has since become highly competitive and companies have cut costs to stay afloat after a slump in crude oil and gas prices. The three shale assets accounted for less than 1 percent of the consolidated revenue of RIL, which runs the world’s biggest refinery complex in western India.

Cairn Oil and Gas, part of Vedanta Ltd, will invest ₹ 300 billion ($4.6 billion) in exploration projects off India’s east coast and in the onshore fields of Barmer in the west. The company expects approvals to be in place by the end of October. The company had said that it could invest more in further developing its four main Barmer fields on the condition its production-sharing contract was extended. The fresh investments are part of the company’s plan to produce oil and gas in India beyond 2020. Cairn will also start drilling for oil and gas in the KG basin in the Bay of Bengal by the end of March. The projects, apart from KG basin, include its gas field in the Raageshwari field in Barmer and an enhanced oil recovery (EOR) programme in the Bhagyam and Aishwariya fields.

India’s H-Energy Pvt Ltd, a unit of real estate group Hiranandani, will start operations at its LNG terminal in the western Maharashtra state by May 2018. India plans to raise the share of natural gas in its energy mix to 15 percent in three years from the current 6.5 percent. H-Energy has invested ₹ 17 billion ($261 million) to build its 4 mtpa regassification terminal near the Jaigarh port in the state. The global market is currently flooded with cheap LNG with many suppliers queuing up to sell volumes to India on a spot basis. H-Energy is among the three companies in India, which will be adding LNG capacity to a gas-hungry nation in 2018. H-Energy is building another LNG terminal off the coast of Kolkata in the Bay of Bengal. The increase in natural gas prices from this month would benefit domestic gas producers by around ₹13 billion during the second half of the current fiscal. The government has increased the price payable for domestic natural gas by around 17 percent to $2.89/mmBtu for the period October 2017 to March 2018. This is the first price increase after five consecutive domestic gas price reductions, and has been driven by an increase in the average gas prices prevalent at the reference gas hubs over the period July 2016 to June 2017.  The price ceiling for gas from difficult deep-sea and high-pressure high-temperature areas/fields has been raised 13 percent to $6.30/mmBtu. The gas price for the April-September period was $2.48/mmBtu, and the ceiling for gas from difficult fields was $5.56/mmBtu. Prices of domestic natural gas are revised twice a year. Last year, the government allowed pricing freedom to producers of gas from difficult areas, with a ceiling linked to a mix of other fuels such as coal, liquefied natural gas, naphtha and fuel oil.

Upstream oil regulator DGH has refused to review the commerciality of India’s deepest gas discovery made by ONGC on grounds that developing the find poses technological challenges. ONGC plans to invest ₹215.28 billion to develop the ultra deepsea UD-1 discovery in its Bay of Bengal block KG- DWN-98/2 (KG-D5) by 2022-23. The find would have helped double the output from the KG block. It had earlier this year submitted to the DGH for approval a DoC of UD-1 find. DGH refused to review the DoC on grounds there was no technology available to produce gas from such water depths. ONGC plans to drill nine wells on the discovery that lies in water depths of 2,400-3,200 metres and will produce a peak output of 19 mmscmd.

Rest of the World

The Russian Yamal LNG project will ship the first two cargoes of LNG in November, followed by another four in December. The Yamal LNG project is co-owned by local Russian gas producer Novatek, as well as France’s Total, China’s CNPC and the Silk Road Fund. Russia’s biggest natural gas producer Gazprom aims to take a 10 percent share of the Chinese gas market after 2025. Gazprom said earlier this year it planned to begin supplying gas to China through Siberia on December 20, 2019.

Exxon Mobil has pulled out of a major project in Pakistan, in a potential blow to plans to boost imports of LNG after years of winter shortages. Differences among the six-member group behind the project in Port Qasim in Karachi mean French oil major Total and Japan’s Mitsubishi may also quit and join a rival scheme. A highly-developed pipeline grid, extensive industrial demand and the biggest natural gas-powered vehicle fleet in Asia after China and Iran make Pakistan an easy fit for LNG and official estimates show imports could jump fivefold to 30 mtpa by 2022. The new project would include a FSRU where LNG will be converted back into gas for feeding into the country’s grid. Qatar Petroleum, the world’s biggest LNG producer, Turkish developer Global Energy Infrastructure Ltd and Norway’s Hoegh LNG, which will provide the FSRU, are the other partners. Pakistan plans to add its second LNG import terminal by the end of this year, but private companies have proposed building six more largely around Port Qasim.

Africa is set to develop a gas pricing index based on the cost of electricity set midway between existing global benchmarks to ensure fairer pricing in new export projects on the continent. The idea is being floated when the world’s poorest continent, where 600 million people are without electricity, is turning to LNG as a cheaper way to power up amid plentiful global supply. Plans to boost African power generation by 30,000 MW by 2030 could translate into 42 mt of additional LNG consumption a year, according to the US Department of Energy. Trading firm Gunvor could peg some sales of LNG from its planned Fortuna facility in Equatorial Guinea, due to start in 2020, to the index. Gunvor struck a deal to buy all of the plant’s output, but there is a provision allowing Equatorial Guinea and its partners to sell up to half the volumes within Africa. Equatorial Guinea already exports LNG to countries that include South Korea and Argentina. Angola and Nigeria are also major African LNG exporters, with Cameroon set to start this year. New LNG projects are planned in Senegal, Mozambique, Congo Republic and Tanzania. Equatorial Guinea aims to export LNG to Africa for the first time, including to Mali, Burkina Faso and Ghana. Africa’s natural gas consumption rose 20 percent from 2011 to 2014 from 110 bcm to 130 bcm, according to the US EIA still a tiny market but the world’s fastest growing. In Nigeria, Seplat Petroleum expects demand to grow rapidly for use in energy, cement and fertiliser projects. But the still small size of Africa’s gas market may make establishing an index difficult, industry experts said.

Indonesia has agreed with Japan’s Inpex to extend the company’s contract to operate the Masela LNG field in the country’s east by up to 27 years once it expires in 2028, the energy ministry said. Indonesia in March 2016 rejected a $15 billion plan by Inpex and its partner Royal Dutch Shell to develop what would have been the world’s largest floating LNG facility to process gas from Masela, saying an onshore plant would benefit the local economy more. Inpex subsequently asked to increase output from the LNG plant to 9.5 mtpa but the government has pushed the company to set aside a larger portion of the gas via a pipeline to domestic buyers. Inpex is also working with BP, Mitsubishi, China National Offshore Oil Corp, Sumitomo and Sojitz on an $8 billion expansion of the Tangguh project in West Papua province that will boost annual LNG production capacity there by 50 percent. Indonesia’s gas demand has been in decline in recent years, and questions remain around how quickly Southeast Asia’s largest economy can develop infrastructure to absorb gas from these projects.

South Africa said the government remains committed to shale gas exploration despite a court order revoking fracking regulations that pushes back plans to award the first exploration licenses by 2019. Farmers lobby AgriSA had said earlier that the High Court had issued an order quashing regulations governing proposed shale gas fracking in the Eastern Cape, one of the main areas where proposed shale gas exploration could take place. The ruling to quash the regulations marked the latest setback to South Africa’s shale gas ambitions after a scientific study published last month suggested its Karoo Basin probably has a fraction of estimated deposits, deflating expectations of an energy bonanza. Africa’s most industrialized economy has been hoping to find sufficient shale gas resources to exploit on a commercial basis. The Japanese government will offer $10 billion to support firms bidding to build LNG infrastructure around Asia. It will allow Japanese firms to bid aggressively for work to build facilities such as LNG receiving terminals and power plants, backed by loans and investments from Japan Bank for International Cooperation (JBIC) and insurance from Nippon Export and Investment Insurance (NEXI), it said. Japan will announce the initiative in Tokyo at the annual LNG Producer-Consumer Conference.

Fortum said it would launch an €8.05 billion ($9.5 billion) takeover bid for Uniper, the power stations operator and energy trading business partly owned by German utility E.ON. However, Uniper, along with four other Western companies, has also pledged to invest up to €950 million each in the Nord Stream 2 pipeline project which should double the amount of gas directly shipped from Russia to Germany. Some Finnish politicians have questioned whether the government’s indirect involvement via Uniper would tie Finland to the Nord Stream project, which has split the European Union over worries of Russia’s growing influence. Eastern European and Baltic states fear the pipeline will increase reliance on Russian gas and undermine Ukraine’s role as a gas transit route, but Germany and other beneficiaries in northern Europe back the project.

Chevron Corp said it has started producing LNG at its Wheatstone project in Australia, slightly later than expected, and plans to ship its first cargo soon. The LNG market will be focused on how smoothly Wheatstone progresses following the troubled start-up at Chevron’s bigger Gorgon LNG project. Both projects are fed from natural gas fields offshore the state of Western Australia. Wheatstone is the sixth out of eight projects in a $200 billion Australian LNG construction boom that is now in its final stretch. The two remaining ones are Royal Dutch Shell’s Prelude floating LNG project and Ichthys, led by Japan’s Inpex. Wheatstone exports could stall rising spot LNG prices, which have surged 55 percent since March to $8.50/mmBtu on strong demand and the delayed ramp-up of many of the Australian LNG export facilities.

Kazakh firm KazTransGas will ship 5 bcm of natural gas to China’s PetroChina for about $1 billion, the Kazakh company said. Shipments will start on October 15 and will be carried out over the course of one year, KazTransGas said. A gas pipeline completed in 2009 connects all Central Asian energy exporters – Turkmenistan, Uzbekistan and Kazakhstan – to China. But Kazakhstan has until now exported gas only to Russia because additional pipelines were needed to link its fields to the Chinese one. KazTransGas, which operates Kazakh gas pipelines and has no upstream assets, did not name the producers that would supply the gas but said some of it would come from the stocks in its storage.

LNG: liquefied natural gas, LPG: liquefied petroleum gas, PNG: piped natural gas, CNG : compressed natural gas, IOC: Indian Oil Corp, mtpa: million tonnes per annum, mt: million tonnes, CGD: City Gas Distribution, OMCs: Oil Marketing Companies, Ind-Ra: India Ratings and Research, RIL: Reliance Industries Ltd, mmBtu:  million metric British thermal units, KG: Krishna-Godavari, JHBDPL: Jagdishpur Haldia & Bokaro Dhamra Natural Gas Pipeline, IGL: Indraprastha Gas Ltd,  DGH: Directorate General of Hydrocarbons, ONGC: Oil and Natural Gas Corp, DoC: Declaration of Commerciality, mmscmd: million metric standard cubic meter per day, CNPC: China National Petroleum Corp, FSRU: Floating Storage and Regasification Unit, bcm: billion cubic meters, US: United States, EIA: Energy Information Administration

Courtesy: Energy News Monitor | Volume XIV; Issue 22

Pressure on Property Rights: The Case of Coal in India

Lydia Powell, Observer Research Foundation

The dramatic changes in the supply and demand for primary energy resources (such as coal, oil and natural gas) and the consequent increase in their value have brought property rights of these resources under stress. When India opened up its economy in 1991, it freed up product markets to some extent but left factor markets (markets for land, resources, labour, capital, institutions) untouched. Product markets transformed beyond recognition in the decades that followed but factor markets remained static. What we are witnessing now in the coal sector and to a lesser extent in the natural gas sector is part of the broader the pressure product markets are exerting on static factor markets.

As per the Indian constitution, property rights over key fuel and non-fuel mineral resources are with the people but the State legally owns them on behalf of the people and has the fiduciary responsibility of using it to the benefit of the people. The legislative framework drawn within the provisions of the Constitution decide rules governing the utilisation and transfer of rights to fuel mineral wealth. Under the existing framework, major minerals including coal, petroleum, natural gas and atomic minerals come under the purview of the Federal Government while minor minerals are under the respective State Governments. Grant of concessions of all fuel minerals (oil, gas, coal and atomic resources) are with the Central Government and therefore are uniform throughout the country.  But State Governments are the owners of the minerals in their respective territorial jurisdiction and are entitled to payments such as royalty (which constitutes the bulk of the revenue from mining), dead rent (which is area based and designed to discourage miners from keeping properties idle) and a set of sundry fees and local taxes.  In offshore areas, exclusive economic zones and in the continental shelf, all rights are with the Central Government.

The value of output from fuel minerals of which coal constitutes the bulk in India has increased by over ten times in the last three decades and consequently the pressure to alter or reduce Governments control of property rights over coal has been growing. What the private sector wants is a bigger share of increase in value of these resources through a larger role in exploiting coal resources. State Governments too want a larger share of the increase in value of fuel minerals through an increase in royalty and other fees. The Central Government has tried to respond by introducing small changes to the existing rules governing property rights over fuel minerals.

The first such change was an amendment to the Coal Mines (Nationalisation) Amendment Act of 1976 that excluded private companies from the right to exploit coal. The Coal Mines (Nationalisation) Amendment Act 1993 offered limited rights to private companies engaged in power generation and steel production to mine coal for captive use. In 1996 this right was extended to companies producing cement. Coal blocks were administratively allocated by the Government to captive users but this neither contributed to a substantial increase in coal production nor did it meet the expectations of the private sector in terms of greater degrees of freedom over coal production. Pressure continued to mount for deeper changes in the rules governing property rights over fuel resources and the Government responded with yet another amendment to the existing legislative framework by introducing ‘The Coal Mines (Nationalisation) Amendment Bill 2000’ in the Parliament with objective of removing the restriction of mining coal only for captive use. The Bill failed to emerge as operational law as it could not navigate its way through the two houses of the Parliament.  The Bill was withdrawn in 2014.

However ‘The Mines and Minerals (Development & Regulation) Amendment Bill 2008’ which sought to introduce competitive bidding for allocation of coal blocks for captive use was passed by both houses of the Parliament and was introduced as operational law in 2012. In 2014, the Supreme court of India declared the entry of private parties into coal production for captive consumption as well as the allocation procedure that the Government had used to assign coal blocks to private companies (as opposed to auctions as required by governing rule) were ‘arbitrary and illegal’. This strengthened the case for a change in property rights through the auction of coal blocks.  In 2015 the Government began auctioning coal blocks.  Auctioning of limited rights to exploit resources (in this case, access to extract coal resources) effectively opens a market for property rights over coal.

Would the auction of property rights over coal not only introduce transparency, reduce opportunities for corruption, raise revenue for the Government but also generate efficient allocation of the right to extract coal (which means that the right will be assigned to the firm which values the resource the most and can use it in the most efficient way)?

It is too early to give definitive answers to these questions but some probable answers may be considered at this point. The move towards auctions of the right to extract coal was not driven by concerns over the need to change factor markets (coal resources) in response to changes in product markets (electricity) but by concerns over misallocation and loss of State revenue that arose from the administrative process of allocating coal blocks raised by agencies such as Comptroller and Auditor General of India (CAG) and the Central Bureau of Investigation (CBI). Under their diagnosis the cure is more transparency in allocating rights and increase in revenue for the State. Claims of these two objectives being achieved are already widely reported in the press (see news items in this week’s issue).  However the fundamental crisis in the sector is not just the lack of transparency, the inevitability of crony capitalism and corruption but rather the need for efficient markets for fuel that can keep up with the market for electricity.

The design of the on-going auction of coal blocks does not appear to reflect this concern adequately. What it appears to reflect are (a) an effort to correct past mistakes and (b) exploit the opportunity to capitalise on it politically. The response of the bidders appears to demonstrate a desperate hurry to get out of the trap set by past mistakes in policy rather than true commercial value of the resource. The design of the auctions is hinged in past (or past mistakes to be precise) and is oriented towards the present rather than being hinged in the present and oriented towards the future of the coal sector. In a well designed and open auctions market, the social value of the coal resource would be approximately equal to the efficient firm’s valuation of it.  But this is the ideal case. The price quoted in the auctions appear to reflect externalities of past mistakes which means that it reflects private value (such as a firm having no other option but to get the block as it has invested heavily in end use) rather than social value.  Former Chairman of Coal India Limited, Partha S Bhattacharyya has pointed out in a recent column in the Indian Express that there is a significant probability of firms walking away from their blocks in favour of imports. Aggressive bidding is not necessarily a good sign in the Indian context. Nor is it a sign of markets coming of age. The history of auctions in the case of Ultra Mega Power Projects and Solar Projects show that self destructive bidding is common in the country given that the cost of exiting or renegotiating a bid (contract) is low.

The restriction on end-use and the absence of a secondary market for the right to exploit coal also limit opportunities of efficiency. If a perfect secondary market exists, the block would eventually find its way into the hands of the firm that is best able to use it. This means that an efficient outcome will emerge irrespective of the initial results. Let us hope, along with the so called aggressive bidders, that a market would eventually emerge either when the constraint on end-use is lifted or when a secondary market is opened up.

Views are those of the author                     

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 37



Monthly Oil News Commentary: October 2017


Rationalisation of GST rates will give the petroleum sector a positive push. The GST council, in order to reduce the cascading impact of taxes on the oil and gas industry due to non-inclusion of key petroleum products, had recommended a tax structure for offshore oil and gas services, import of oil rigs, transportation of natural gas and sale of bunker oil. The reduction in GST rate for bunker fuel to 5 percent from 18 percent earlier will enhance its sale to foreign vessels and the GST rate reduction in offshore contracts to 12 percent from 18 percent earlier will reduce tax burden on offshore hydrocarbon activates. Exemption from 5 percent Integrated IGST for the import of rigs and ancillary equipment in the hydrocarbon sector will promote activities in the upstream sector and rate reduction in transportation of natural gas through pipeline to 5 percent from 18 percent earlier will make the fuel more affordable. While the new tax regime included most of the goods and services, core petroleum products including crude oil, natural gas, petrol, diesel and aviation turbine fuel were kept out of its ambit due to stiff opposition from state governments. Also, other oil products such as kerosene, LPG gas and naphtha were included in the GST. This resulted in oil companies having to comply with both the old and the new tax regimes as well as deal with stranded taxes. According to ratings agency ICRA, the recommendations made will fare well for upstream companies and help them control their capital expenditure.

Chiefs of several global and Indian oil companies are said to be wanting petroleum products to be included in the GST, according to Niti Aayog. Global oil giants, including Saudi Aramco and Moscow- controlled oil giant Rosneft, have committed to increasing investment in India. CEOs are reportedly confident of India’s potential to become a gas-based economy.

Meanwhile election bound Gujarat became the first state to say it would cut VAT on petrol and diesel after the Centre urged states to cut their levies on fuels by 5%. Other BJP-ruled states, such as Madhya Pradesh, Chhattisgarh, Uttarakhand, and Jharkhand, and states where it shares power, like Bihar, seemed likely to follow suit with cuts or seriously consider the option of doing so. Similarly, Madhya Pradesh was likely to announce a Diwali gift for consumers by slashing petrol and diesel prices. But Haryana, though a BJP state, appeared in no mood to cut taxes. Kerala said a reduction was unfeasible, while Odisha felt the request was unjustified. Tamil Nadu declined to react, while Punjab said his state didn’t need to effect cuts because, though Centre had hiked excise duty on fuel 11 times in 36 months, the state had not increased VAT. Kerala ruled out the possibility of a VAT reduction, saying the state government could not accept the extra burden that would be created by lowering VAT on the fuels as Kerala had already been crippled by the heavy burden of GST. The federal government urged state governments to reduce VAT on petrol and diesel by 5 percent to further ease retail price of the auto fuel after the central government cut excise duty on these by ₹ 2/litre.  The argument is that raising excise duty on fuel during the low global oil price era also involved a responsibility to bring it down when necessary. The Centre sacrificed ₹ 260 billion in revenue in the duty cut (the full year impact of the duty cut.) For the rest of the financial year, the impact is ₹ 130 billion. The central government raised excise duty by ₹ 11.77/litre on petrol and ₹ 13.47/litre on diesel between November 2014 and January 2016 to take away gains arising from plummeting international oil rates. The central government slashed excise duty on petrol and diesel by ₹2/litre to tame rising inflation and to shield consumers from the surging price of auto fuels. The move is in response to criticism that increase in taxes on petrol and diesel, while global prices remained low, was pinching consumers. Fuel prices have started moving up owing to refinery shutdowns in the US following recent hurricanes. The petrol price in Delhi was ₹ 70.83/litre, its highest since 16 January; diesel cost ₹ 59.07, also its highest since the same date. Crude oil price, which had touched a monthly average of $123.6/barrel in March 2012, eventually declined to $28.1 in January 2016. In September 2017, the global crude oil price averaged $54.52/bbl according to information available with the PPAC an arm of the oil ministry. The finance ministry attributed the current spike in domestic auto fuel prices to rising global prices and said the trend had started reflecting in inflation.

ONGC has drawn a blueprint to raise crude oil production by 4 mt and almost double its natural gas output by 2020 to meet the target of cutting India’s import dependence by 10 percent. The state-owned firm will raise crude oil production from 22.6 mt in 2017-18 to 26.42 mt in 2021-22. The nation’s biggest oil and gas producer has prepared the ‘Road map for Import Reduction’ two years after the target for reducing oil import dependence by 10 percent, from 77 percent was set. India imported a record 4.83 million bpd of oil in September as several refiners resumed operations after extensive maintenance to meet rising local fuel demand. The world’s third-biggest oil importer shipped in 4.2 percent more oil last month than a year earlier and about 19 percent more than in the previous month, ship-tracking data showed. ONGC plans to increase focus on EOR projects after a policy incentivizing the activity is formulated. The policy is expected to benefit the company which garnered an incremental gain of 7.36 mt through EOR activities last fiscal year contributing to 35 percent of ONGC’s crude oil production. Also, ONGC spent around ₹ 51.95 billion on EOR activities in 2016-17. The new policy is aimed at arresting the declining trend in domestic crude oil production. The upstream regulator of the country DGH had called for stakeholder consultation for the policy in April this year and appointed consultancy firm Deloitte to undertake a study on the best practices existing worldwide on EOR. ONGC is working on a plan to invest ₹ 578.25 billion on 28 EOR projects to tap an additional 194 mtoe. Of the 28 projects, the company has already completed 23 projects at a cost of ₹ 475.67 billion helping it tap more than 112 mt of additional crude by the end of 2016-2017. ONGC and Cairn India currently deploy EOR techniques in mature fields. State owned Oil India Ltd had also recently signed a MoU with the University of Houston to collaborate in the fields of IOR and EOR for production enhancement from mature fields.

During the first nine months of the year India’s oil imports rose 1.8 percent to about 4.4 million bpd, with most supplies coming from the Middle East, followed by Africa and Latin America. Indian fuel demand typically eases in the third quarter as monsoon rains hit construction, industrial activity and reduces consumption of transport fuels. That provides refiners with an opportunity to carry out maintenance. Capacity addition is also driving up India’s oil imports. The country added 170,000 bpd of capacity at plants owned by BPCL and HPCL-Mittal Energy, which are gradually ramping up crude runs. India, which imports about 80 percent of its oil needs, has emerged as a key driver for growth in global oil demand. India is increasing refining capacity to keep pace with the expected growth in fuel demand as India seeks to boost the manufacturing sector.

IOC has bought two new types of US crude for December delivery as it tests different grades from the US. IOC bought 1 million barrels each of US Southern Green Canyon (SGC) and WTI Midland crude likely from a Chinese trader. The purchase was in addition to 2 million barrels of Basra Light crude to be delivered in the same month. The US has become a new source of crude supply for Asia since Washington lifted a ban on crude exports in late 2015. India joined other Asian countries in buying US crude in the fourth quarter to widen its import sources as well as to reduce trade surplus with the US. IOC has issued another sour crude tender that will close later to purchase more oil for the same period. The refiner has bought about 5.5 million barrels of US crude so far this year. Other Indian refiners to have bought US crude include BPCL, Bharat Oman Refinery, HPCL and RIL.

As a leading energy consumer, India is looking to upgrade its relationship with producing countries to a strategic one, instead of mere buyer-seller. Saudi Aramco, which established its business presence in India last year, has formed an Indian subsidiary that will engage in crude oil and LPG marketing, engineering and technical services, and other business development activities.

Kuwait’s Al Arfaj Group plans to build a 600,000 bpd oil refinery and a 10 mtpa LNG terminal in the Indian coastal state of Andhra Pradesh. India, which imports about 80 percent of its oil needs, aims to raise its refining capacity by 50 percent in the next seven years to about 7 million bpd. Saudi Aramco said it planned a ‘mega investment’ in refining, petrochemicals and fuel retailing in India.

Rest of the World

Global supply and demand for crude oil will be largely balanced next year, as growth in consumption helps erode a three-year-old overhang of unused fuel and should mostly offset a steep rise in output, the IEA said. The Paris-based IEA said it continues to see global demand for crude growing by 1.6 million bpd in 2017, before moderating to 1.4 million bpd in 2018. Commercial oil stocks likely fell in the third quarter of this year, only the second draw since the crude price crashed in 2014, thanks to a drop in the amount of oil held in floating storage or in transit, the IEA said. Commercial stocks in industrialized countries fell in August by 14.2 million barrels to 3.015 billion barrels, leaving a surplus of 170 million barrels above the five-year average, the IEA said. However, the IEA said its numbers implied a build of up to 800,000 bpd could take place in the first quarter of next year, meaning the OPEC and its partners cannot afford a slip in adherence to their supply-restraint deal. OPEC supply was little changed in September at 32.65 million bpd, but down 400,000 bpd from a year earlier, meaning the group’s compliance with its self-imposed 1.2-million bpd output cut stood at 88 percent last month and 86 percent for the year to date, the IEA said. Together with its partners, which include Russia, Oman and Kazakhstan, the group has agreed to restrain output by 1.8 million bpd until March next year. The IEA said it expects demand for OPEC’s crude to rise to 32.98 million bpd in the fourth quarter of this year, above September’s output, and then to fall to 31.87 million bpd in the first three months of 2018. The IEA said it sees non-OPEC crude supply rising by 700,000 bpd in 2017, and by 1.5 million in 2018 to reach 59.6 million bpd, with the US being the largest contributor. US crude production, aided in large part by resurgent shale output, grew by 550,000 bpd in July compared with a year earlier to 9.24 million bpd, its highest since November 2015. The impact of Hurricane Harvey, which hit the US Gulf Coast in late August, is expected to have curtailed production in August and September. But for 2017 as a whole, the IEA expects US crude output to grow by 470,000 bpd and by 1.1 million bpd in 2018. Southeast Asian demand for oil will keep growing until at least 2040 as emerging nations there rely on the fossil fuel to transport their rapidly growing populations, ship goods and make plastics, the IEA said. Oil usage in the region will expand to around 6.6 million bpd by 2040 from 4.7 million bpd now, with the number of road vehicles increasing by two-thirds to around 62 million, the agency said in a report. It did not make any forecasts beyond 2040. A global push to replace combustion engines in vehicles with electric-powered ones to fight climate change has raised concerns in the oil industry that demand for the commodity could peak in the next 10-20 years. But oil will continue to meet around 90 percent of transport-related demand in Southeast Asia, especially for trucks and ships, the IEA’s director of energy markets and security, said. Oil demand from the petrochemicals sector, one of the largest users of the fossil fuel, will also grow fairly substantially. Southeast Asia will have to fork out more than $300 billion in 2040 for net energy imports, equivalent to about 4 percent of the region’s total gross domestic product, the IEA said.

According to Saudi Arabia, demand for oil will increase between 2030 to 2040 because there will be a need from petrochemical and other industries, not just for energy production. Global oil demand is expected to grow by 45 percent by 2050 despite an international push for using more renewable sources of energy according to the Kingdom. The kingdom, which is the world’s biggest crude exporter, would remain a cornerstone of the global oil industry through state-owned Saudi Aramco.

Russian said it plans to discuss a possible extension of the global oil output cut deal and the general situation on world oil markets with Saudi Arabia.  Russia held on to its position as China’s top crude oil supplier ahead of Angola and Saudi Arabia for the seventh straight month in September, with shipments hitting a record as refiners rushed to buy lower-sulfur oil to meet cleaner fuels standards. Imports from Russia last month were almost 6.35 mt or 1.545 million bpd up 60.5 percent from the same month last year, according to the General Administration of Customs data. For the first three quarters, crude volumes from Russia gained 18 percent year-on-year to nearly 45 mt or 1.2 million bpd, also holding firm its top ranking. The lower cost of Russian crude and China’s shift to cleaner diesel was the key driver behind the record Russian oil purchases. Meanwhile Angola, China’s second largest source of crude, supplied 11.7 percent more oil than a year earlier at 4.677 mt or 1.14 million bpd. Angola also maintained the second spot for the January-September supplies ahead of Saudi. Supplies from Saudi Arabia were up 9.6 percent last month year-on-year at 4.276 mt or about 1.04 million bpd. Russian supplies could climb further next year as privately run conglomerate CEFC China Energy agreed earlier this month to buy 220,000 to 260,000 bpd of oil from Rosneft, as part of a $9.1 billion investment in the world’s largest listed oil company. China’s total crude oil imports in September climbed to the second highest on record at around 9 million bpd, buoyed by purchases from CNOOC and as independent refineries returned from maintenances.

Russia’s largest oil producer Rosneft wants to boost its supplies of oil to China through Kazakhstan to as much as 18 mtpa (360,000 bpd) from around 10 mt in 2017. Such a big increase may significantly drain flows of Urals blend to Europe at a time when Russian oil output has been reduced as part of a global pact to support prices. Russian oil production has been steady, at around 10.9 million bpd due to a global pact to reduce total production by around 1.8 million bpd to support weak oil prices. Russia has steadily increased oil supplies to China over the past years to become the main supplier of oil to the country. This year, Rosneft’s total oil supplies to China are set to reach a record high of 40 million tonnes (800,000 barrels per day). Rosneft and China’s CNPC agreed in January on an increase of oil supplies via Kazakhstan through to 2023 with total supplies of 91 mt over a 10-year period. Kazakhstan’s energy ministry said Rosneft has not officially applied for an increase in transit volumes to China.

Saudi Arabia and Iraq expressed satisfaction with the orientation of the global oil market towards recovery as a result of a deal to boost prices by limiting production. OPEC, Russia and a number of other oil producers are cutting output until March 2018 in an effort to boost the price of crude. Saudi Arabia and Iraq are respectively the biggest and second-biggest producers in the OPEC.

Iraq and Iran boosted crude exports in September, taking advantage of a slower pace of shipments from rival Saudi Arabia to win buyers in key markets like China and the US. Iraq shipped 3.98 million bpd the highest since December, while Iran’s exports rose to 2.28 million bpd, the most since February, according to ship-tracking data. Saudi Arabia’s exports were 6.68 million barrels a day, the second-lowest for this year, the data show. Iran and Iraq’s moves to grab market share cast a light on internal tensions within OPEC as Saudi Arabia, the group’s de facto leader and world’s top oil exporter, works to re-balance the global market. Saudi Arabian Oil Company, known as Aramco, will make the deepest cuts in supplies to customers in its history in November, the energy ministry said.

OPEC and other oil producers may need to take “some extraordinary measures” next year to rebalance the oil market, the OPEC said. Saudi Arabia and Russia helped secure a deal between the OPEC and 10 rival producers to cut output by about 1.8 million bpd until the end of March 2018 in an effort to reduce a glut.  Consultations were under way for the extension of the OPEC-led pact beyond March 2018 and that more oil producing nations may join the supply pact, possibly at the next meeting of OPEC in Vienna on November 30. Saudi Arabia said it hoped to reach a consensus with Russia and other major oil producers on the future of the deal before November’s meeting.

Iraq and Iran boosted crude exports in September, taking advantage of a slower pace of shipments from rival Saudi Arabia to win buyers in key markets like China and the US. Iraq shipped 3.98 million bpd the highest since December, while Iran’s exports rose to 2.28 million bpd, the most since February, according to ship-tracking data. Saudi Arabia’s exports were 6.68 million barrels a day, the second-lowest for this year, the data show. Iran and Iraq’s moves to grab market share cast a light on internal tensions within OPEC as Saudi Arabia, the group’s de facto leader and world’s top oil exporter, works to re-balance the global market. Saudi Arabian Oil Company, known as Aramco, will make the deepest cuts in supplies to customers in its history in November, the energy ministry said.

The EU banned the sale of oil and oil products to North Korea, in a largely symbolic move aimed at encouraging countries that have more significant levels of trade with the country to follow suit. EU Foreign Ministers also imposed a blanket ban on doing business with North Korea in sanctions that go beyond the latest UN measures. The EU does not sell oil to Pyongyang. Following North Korea’s most powerful nuclear test, the United Nations Security Council capped North Korean imports of crude oil, but China and Russia resisted an outright ban.

GST: Goods and Services Tax, CEOs: Chief Executive Officers, VAT: Value Added Tax, BJP: Bharatiya Janata Party, US: United States, bbl: barrel, PPAC: Petroleum Planning & Analysis Cell, ONGC: Oil and Natural Gas Corp, LPG: liquefied petroleum gas, mt: million tonnes, bpd: barrels per day, EOR: enhanced oil recovery, DGH: Directorate General of Hydrocarbons, MoU: Memorandum of Understanding, IOR: improved oil recovery, IOC: Indian Oil Corp, BPCL: Bharat Petroleum Corp Ltd, HPCL: Hindustan Petroleum Corp Ltd, WTI: West Texas Intermediate, RIL: Reliance Industries Ltd, mtpa: million tonnes per annum, IEA: International Energy Agency, OPEC: Organization of the Petroleum Exporting Countries, EU: European Union, UN: United Nations

Courtesy: Energy News Monitor | Volume XIV; Issue 21


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


As world energy markets transform at an unprecedented rate, India is at the forefront of the shift towards profitable renewables given that the country’s solar belt has the potential of 749 GW for power generation say some experts. As shown by a new IEEFA (Institute for Energy Economics and Financial Analysis) analysis, accelerating this trend will allow India avoid the costly mistakes made by slow-moving, late-learning European utilities, which have wasted billions on stranded coal and other thermal power assets. Similar trends have been apparent now for some time in China and India, where drives to install both thermal and renewable capacity concurrently have seen coal-fired power station utilisation rates drop to record lows of 47 percent and 57 percent respectively in 2016. This is despite electricity demand growing in these countries. The government has set a target of 175 GW of renewable energy by 2022, including 100 GW of solar and 60 GW of wind. India’s draft Third National Electricity Plan (NEP3) for the next two five-year periods, to 2027, unambiguously concludes that beyond the half-built plants already under construction, India does not require any new coal-fired power stations. According to some experts this conclusion overlooks some key facts. The Draft National Electricity Policy of 2016 by CEA said that coal based power generation capacity of 44,085 MW was required to meet demand until 2027 but as 51,025 MW of coal based capacity was under construction in the period 2017-2022 additional coal based capacity would not be required.  This was widely interpreted in the media, especially by agencies opposed to coal, as cancellation of coal based power plants on account of increase in renewable energy. Between 2010 and 2015 coal based power generation capacity doubled from about 85 GW to 165 GW largely driven by the private sector.  It took only 5 years for the private sector to build the same generation capacity that took nearly 6 decades for the public sector to build.  Electricity demand grew only by 5.2% in this period. This is the main reason why additional coal capacity is not required in the next ten years these experts say.

The government’s mega push for clean energy generation capacities, India is set to overtake the EU in expansion of new renewable energy generation capacity for the first time, according to the IEA. India’s move to address the financial health of its power utilities and tackle grid-integration issues drive a more optimistic forecast, the Paris-based agency said in its latest report Renewables 2017. The IEA said that solar PV and wind together represent 90 percent of India’s capacity growth as auctions yielded some of the world’s lowest prices for both technologies. The government is working on an ambitious plan to increase the installed base of domestic renewable energy capacity to 175 GW by 2022. The IEA’s latest report on renewables market analysis and forecast said new solar PV capacity grew by 50 percent globally last year, with China accounting for almost half of the global expansion. For the first time, solar PV additions rose faster than any other fuel, surpassing the net growth in coal. This year’s renewable forecast by IEA is 12 percent higher than last year, thanks mostly to solar PV upward revisions in China and India. Three countries – China, India and the United States – will account for two-thirds of global renewable expansion by 2022.

The wind power tariff which reached a record low of ₹2.64/kWh in the auction conducted by SECI is significantly lower than the approved feed-in tariffs for wind projects and signify increased competitiveness of wind, ratings agency ICRA said. The winning bidders for 1000 MW wind power capacity have quoted tariff in the range of ₹ 2.64/kWh to ₹ 2.65/kWh. The tariff discovered in the current scheme is lower by 24 percent against the previous bid tariff of ₹ 3.46/kWh as discovered in the reverse auction under the first scheme in February 2017.

Rejecting the requests of both wind developers and the MNRE, Karnataka’s power regulator has reiterated its earlier decision that PPAs, which had not been approved before it set a new wind power tariff, would be okayed only at the new rate. The KERC had passed an order on September 4, setting a fresh feed-in tariff for wind power at ₹ 3.74/kWh considerably lower than the tariff of ₹ 4.50/kWh, set by it in October 2015, which had prevailed till then. The order, however, put into jeopardy 599 MW of wind capacity whose developers had already signed PPAs with various discoms in Karnataka at the old rate of ₹4.50/kWh, but the PPAs had still to be ratified by KERC. Around 273 MW had already been commissioned and were supplying power to the state discoms at ₹ 4.50/kWh, but following the new order, would have to renegotiate their PPAs at ₹ 3.74/kWh. The remaining 326 MW are still under construction. Of the 273 MW of wind power in Karnataka, which have already been commissioned but have PPAs awaiting approval, PPAs for 242.50 MW were signed before March 31 this year.

A US based renewable energy company has moved the Madras High Court challenging the recent wind auction held by Tamil Nadu government, claiming that its bid was unfairly rejected even though it had quoted a tariff lower than the winning bid. The Tamil Nadu Generation and Distribution Corp (TANGEDCO) held a 500 MW wind auction in end-August where the winning price was ₹ 3.42/kWh. Evergreen Renewables, a subsidiary of Evergreen Power Solutions Inc., has moved the court to stay the entire auction proceedings and set aside TANGEDCO’s letter rejecting its bid. The firm had quoted a tariff of ₹3.34/kWh, Evergreen said. Evergreen has developed over 3,000 MW of solar and wind power in the US, and is currently setting up around 550 MW of wind projects across Tamil Nadu, Gujarat, Karnataka and Madhya Pradesh, the company said. It commissioned its first and only solar project of 11.5 MW in Telangana in April 2016.

The €5 billion Finnish energy systems provider, Wartsila, is looking to develop India as its biggest Asian market for battery storage solutions, given the huge potential from the country’s solar power play. India’s solar-power capacity has grown exponentially to around 14 GW and the government has set an ambitious target of 100 GW by 2020, but storage has been a missing link thus far and the government is now acknowledging the need for it. Therefore, the government wants the industry to set up battery-manufacturing units in India as a sharp decline in prices of batteries between 2010 and 2017 has made battery-backed solar power more viable. While India has a huge solar-power potential, this source of energy is intermittent and subject to fluctuations. The world over, solar power is supplemented with gas-based or hydropower to ensure continuous power supply. India does not have much gas, and hydropower project development in the country has been slow, leaving battery storage as a backup option.

Solar power tariff ranged between ₹ 2.65-3.36/kWh in an auction conducted by Gujarat Urja Vikas Nigam (GUVNL) for 500 MW capacities. This was slightly up from all-time low rate of ₹ 2.44/kWh discovered earlier this year. The SECI is also conducting the second auction for another 1 GW capacities. The second auction assumes significance because India has set an ambitious target of having 60,000 MW of wind power capacity by 2022. India has installed wind power capacity of 32.5 GW as per latest report for the month of August by the CEA. The country needs to add 5-6 GW wind capacity every year to meet the target. Globally, India is at the fourth position after China, the US and Germany, in terms of wind capacity installation.

A JV of French energy firm Engie SA and Dubai-based private equity firm Abraaj Group may invest around $1 billion to build a 1,000 MW wind power platform in India. The strategy ahead for the JV announced involves bidding for new contracts and making acquisitions to reach the targeted capacity. The capital expenditure planned in equity and debt comes in the backdrop of India’s wind sector transitioning from a feed-in tariff regime to tariff-based competitive auctions. While feed-in tariffs ensure a fixed price for power producers, wind power tariffs in India followed the solar route and hit a record low of ₹ 3.46/kWh in a February auction conducted by Solar Energy Corp of India. Prior to this JV, both Abraaj and Engie have had a presence in the Indian solar space. While the Abraaj Group, with $11 billion under management, announced a partnership with the Aditya Birla Group in October 2015 to build a renewable energy platform focused on developing solar power plants, Engie, with €66.6 billion in revenue, has been trying to expand its presence in India’s clean energy space. Foreign investments are crucial for India’s renewable energy industry as the lower cost of foreign capital and the size of the market has helped bring down tariffs. Engie plans to set up 2 GW of capacity in India by 2019, with its subsidiary Solairedirect SA actively bidding for solar projects, and has an 810 MW portfolio. India’s low green energy tariffs have caused disruptions with some states looking to renege on their offtake commitments for projects awarded at comparatively higher tariffs.

Essel Infraprojects Ltd said it has commissioned 55 MW capacity solar projects in UP and Karnataka. The company is already managing 165 MW capacity solar projects in the country. It said as part of its commitment towards generating green energy, Essel Infra will commission an additional 60 MW capacity project in Karnataka in the next 45 days. The company is aiming to increase its share in green energy through construction of massive solar projects in UP, Odisha and Karnataka of 520 MW capacity in the near future. Essel Infra recently commissioned a 50 MW capacity solar project in Jalaun, UP and a 5 MW capacity project in Bijapur, Karnataka. The company’s effort in generating green power is in tune with the government’s target of generating 100 GW power through solar projects by 2022.

Adani Enterprises announced plans to demerge its renewable energy business into associate company Adani Green Energy Ltd as part of simplifying overall business structure. Post demerger scheme, which has been approved by the boards of the two companies, AGEL would be listed on the exchanges. AEL has a renewable energy portfolio of 2,148 MW in India. Announcing the scheme of arrangement for demerger of the renewable power undertaking into AGEL, Adani Enterprises said it would “simplify the business structure”. Under the proposed scheme, AGEL would issue 761 new equity shares for every 1,000 equity shares of AEL.

The MNRE has written to the Tamil Nadu government, urging it to prevent arbitrary curtailment, or back downs, of solar power in the state. Solar plants have been subject to repeated back downs in Tamil Nadu since last year, to the extent that the National Solar Energy Federation of India (NSEFI) has filed a petition before the Tamil Nadu Electricity Regulatory Commission, urging it to intervene. Separately, Adani Green Energy, which has a 216 MW solar plant in Ramanathapuram district, has also filed a similar petition. The Tamil Nadu government signed Memoranda of Understanding (MoU) with 16 solar power companies for 1500 MW of electricity. All the 16 companies will invest a total of ₹ 900 million in the coming year at the rate of ₹ 60 million/MW solar power. These companies had bid for various capacities of solar power for the year 2017-18 and won bids after they agreed to the lowest tariff of ₹ 3.47/kWh. The 16 companies led by Rasi Green, which won the bid at ₹ 3.47/kWh will set up solar plants in the state. NLC will provide 709 MW unit followed by six companies, 100 MW each. Other companies have been allocated 1 to 54 MW.

The Uttarakhand government and a charitable funding agency, Swan Cultural Center and Foundation, launched ‘Solar Briefcase’ in Kedarnath Dham. The initiative was taken to provide electricity to far flung areas in the hill state. There are more than 60 villages in the state where electrification has not yet been done due to the difficult geographical conditions.

A reverse auction of 500 MW of solar projects held by the Gujarat government saw the lowest winning bid at ₹ 2.65/kWh. This was the first solar auction held after the two conducted by Solar Energy Corp of India in May, when one of the winning bidders had promised to sell power at a record low of ₹ 2.44/kWh. The auctions in May were held for projects at the Bhadla Solar Park in Rajasthan’s Jodhpur district, where solar radiation is the highest in the country. It was expected that winning bids at the latest auction conducted by Gujarat Urja Vikas Nigam Ltd, as the state’s nodal power company is called, would be a shade higher. This is because Gujarat has less intense solar radiation than Rajasthan, and the developers will not be provided land in solar parks — they will have to acquire land on their own. Further, in the four months since the last auction, the cost of solar modules in China, from where 90% of Indian solar developers source their equipment, have begun rising, after having fallen steeply for two years before that. The lowest bid, seeking 90 MW at ₹ 2.65/kWh was made by GRT Jewellers India, a renowned name in the jewellery business. The company, headquartered in Chennai, is venturing into solar for the first time. The second and third lowest bidders were both state-owned power generation companies — Gujarat State Electricity Corp and Gujarat Industries Power Company — bidding for 75 MW each at ₹ 2.66 and ₹ 2.67/kWh respectively. The remaining 260 MW (out of 500 MW on offer) of projects were won by NYSE-listed Azure Power, one of the largest solar developers in the country, which also bid ₹ 2.67/kWh. There were 14 bidders in all in the auction. Among those who lost out were heavyweights such as Tata Power, ReNew Power, Finland-headquartered Fortum Solar, Lightsource Renewable Energy of the UK and Canadian Solar Energy.

Solar developers and the Jharkhand government have resolved an 18-month long deadlock over the price of solar power, with the developers agreeing to a reduced tariff of ₹ 4.95/kWh. The problem arose after the Jharkhand Renewable Energy Development Agency (JREDA) held a mega auction of 1,200 MW in March 2016 to set up solar projects at 45 different areas across the state. Winning bids ranged from ₹ 5.08 to₹ 5.48/kWh for the larger projects of above 25 MW and ₹ 5.29 to ₹ 7.95/kWh for those below. The biggest winner was ReNew Power, which secured 522 MW. Meanwhile, solar tariffs kept falling in succeeding auctions, reaching a record low of ₹ 2.44/kWh in an auction conducted by Solar Corporation of India at the Bhadla Solar Park in Rajasthan in May this year. Last month, the developers finally agreed to a reduced tariff of ₹ 4.99 /kWh per kWh for projects above 25 MW, which the state government agreed to consider. Dubai-based emerging markets buyout fund Abraaj Group has joined hands with ENGIE, a multinational utility company and global independent power producer to set up a wind energy platform in India. The Indian renewable energy sector continues to grow rapidly, underpinned by an increasing demand for power. Power consumption in the country is expected to grow at 9% year-on-year until 2020. The Indian government’s target of 60 GW of wind power capacity by 2022 will require a near doubling of the current installed capacity of 32 GW over the next five years. In 2015, Abraaj Group tied up with Aditya Birla Group to create a large-scale renewable energy platform that will focus on developing utility-scale solar power plants in India.

Wary of being left behind in the race for renewables and electric vehicles, oil marketing companies are quietly drawing up plans to expand their modest presence in renewable energy space. IOC is exploring opportunities for setting up battery charging stations and battery replacement facilities for electric vehicles in its petrol pumps. The centre is pushing solar and wind energy as well as electric vehicles, to curb oil imports and pollution, and meet its commitments under the Paris accord on climate change. India pledged to reduce carbon emissions relative to its gross domestic product by 33-35% from 2005 levels by 2030, under the accord. India pledged that by 2030, 40% of the country’s electricity would come from non-fossil fuel-based sources such as wind and solar power. By 2021-22, BPCL sees 5% of its revenue coming from non-fossil fuel sources. BPCL has shortlisted 10 oil depots and liquefied petroleum gas bottling plants for installation of rooftop solar plants. By March 2017, rooftop solar units had been installed in 1,001 of its retail outlets. BPCL is carrying out a detailed feasibility and system design study at 19 company-owned and company-operated retail outlets in a pilot for solarizing (putting solar panels) large-format retail outlets. HPCL is strengthening its presence in natural gas and renewables to align its business to the changing patterns of demand and seeking to tap potential opportunities. HPCL operates wind farms of 100.9 MW capacity installed in Rajasthan and Maharashtra.

The CCEA is likely to approve revised cost of 412 MW Rampur hydro power project implemented by SJVN Ltd at ₹ 42.33 billion in its meeting scheduled. The CCEA will revise the cost of the project to ₹ 42.33 billion from ₹ 20.47 billion estimated on March, 2006 price level during detailed project report stage. Last year in October, the government dedicated 412 MW Rampur Hydro Station of SJVNL projects to the Nation in Mandi along with other two flagship projects– 800 MW Hydro Power Station of NTPC- Koldam and 520 MW Parvati Project of NHPC. The Rampur project in Kullu district is being operated in tandem with Nathpa Jhakri Hydro Power Station. This project provides 13 percent free power to Himachal Pradesh. Besides, the power from this plant is also distributed to Haryana, Jammu & Kashmir, Punjab, Rajasthan, Uttar Pradesh and Uttarakhand.

In a bid to seek more private sector participation in the hydropower sector, the power ministry has formed a committee under CEA to propose recommendations to the ministry. This also comes at a time when hydropower generation has seen a decline of 12 percent in the month of August compared with the corresponding month, last year, according to the power ministry. According to experts, private sector remains reluctant due to various issues pertaining to project execution. At present, as many as 20 under construction hydro power projects totalling 6,329 MW are either stalled or stressed in the country and ₹ 301.47 billion has been spent on them. According to Niti Aayog’s draft energy policy, the think-tank has proposed a bail out of stranded large hydropower projects of around 11,000 MW capacity. The government of India also aims to add 1,305 MW of additional hydropower generation capacity in the current financial year out of which 305 MW expected from the private sector while 266 MW has already been commissioned.

India is playing a substantive role in building a nuclear power plant on foreign soil for the first time ever with the proposed supply of equipment and material for the power station being built by Bangladesh with Russian assistance. Indian firms are working with Russian and Bangladeshi partners on establishing Rooppur Nuclear Power Plant in Bangladesh. India will supply and manufacture equipment, material for the plant near Dhaka. Besides Bangladeshi nuclear scientists are undergoing training at the Kudankulam Nuclear Power Plant, also built with Russian assistance and uses Russian technology.

Rest of the World

The US nuclear power industry is facing an uphill battle to hang onto its share of the country’s electricity production, with some projecting a worst-case scenario where half of the nation’s 99 nuclear reactors could shut over the next couple of decades. Nuclear power looked to be on the verge of a renaissance about a decade ago. But a surge in domestic natural gas production, billions of dollars in cost overruns on new projects, Japan’s Fukushima accident in 2011, and multiple plant closures have the industry on its heels again. The US Department of Energy expects nuclear energy’s share of the power mix to drop to 11 percent by 2050 from the current 20 percent, and many reactors to close. In the past five years, operators have shut six reactors amid stagnant electricity demand and low natural gas and power prices, and plan to shut another six reactors in deregulated states over the next five years, in part because they cannot compete with gas-fired plants. Most states in the US Northeast and Midwest are deregulated. Merchant plants receive the same money for energy they sell as gas-fired and renewable plants, which are less expensive to operate.

The US Department of Energy said it has offered an additional loan guarantee of up to $3.7 billion to companies building two nuclear reactors at the Vogtle plant in the state of Georgia. The conditional loan guarantees were in the amounts of $1.67 billion to Georgia Power Company, a subsidiary of Southern Co, $1.6 billion to Oglethorpe Power Corp and $415 million to three subsidiaries of the Municipal Electric Authority of Georgia. US Energy Secretary who has remarked he wants to make nuclear power “cool again,” said that the “future of nuclear energy in the US is bright” and that he looks forward to “expanding American leadership in innovative nuclear technologies.” US nuclear power has been struggling in the face of competing power plants that burn plentiful, low-cost natural gas and stagnant electricity demand. The 2011 Fukushima disaster in Japan has also dimmed interest in nuclear power. The Vogtle project is the first new US nuclear power plant to be built since the Three Mile Island accident in 1979. And billions of dollars in cost overruns at Vogtle helped push its main contractor, Westinghouse Electric Co LLC, a subsidiary of Toshiba Corp of Japan, into bankruptcy in March. The US Department of Energy has already guaranteed $8.3 billion in loans to the companies to support construction of Vogtle reactors. Vogtle had initially been expected to begin generating power in 2016, but now the reactors are expected to be completed around the end of 2022.

TEPCO received an initial safety approval from Japan’s NRA to restart two reactors at the world’s biggest nuclear power plant. The approval marks the first safety approval TEPCO has received in the first steps towards the possible restart of reactors since the 2011 meltdown of three reactors at TEPCO’s Fukushima plant following an earthquake and tsunami that led to the eventual closure of Japan’s nuclear power plants. TEPCO has said it needs to resume operations at the closed plants to pay for Fukushima’s restoration and other liabilities from the disaster. The NRA ruled that the No. 6 and No. 7 reactors, each with a capacity of 1,356 MW, at the Kashiwazaki-Kariwa nuclear plant has passed new safety standards enacted after the Fukushima accident.

Russian company Rosatom’s €12.5 billion (11.25 billion pounds) project to build two nuclear reactors in Hungary has been delayed by at least a year, Hungarian authorities said. Hungary said that the Paks nuclear project would be delayed by 22 months because of EU regulatory hurdles but the government was working to shorten the delay. The two Russian VVER 1200 reactors could come online in 2026 and 2027 respectively, a year later than outlined in a 2015 government presentation. Rosatom plans to start work on the site’s auxiliary buildings in early 2018 and that, once permits are secured, construction of the reactors could start in 2020. Suli said the application for the construction permit – originally scheduled for end-2017 – will be submitted mid-2018 and that approval could take up to 15 months. Greenpeace said that EU regulatory controls should have been anticipated and were not responsible for Rosatom’s delay in submitting the request for a construction permit. The Paks site already has four Russian-built reactors that account for about a third of Hungary’s power consumption and will be retired between 2023 and 2037.

Safety levels at nuclear power plants globally are worrying, and although there are no immediate dangers, there are systemic risks that should be dealt with urgently, the head of French nuclear watchdog ASN said. In the past few weeks, the regulator has ordered heightened supervision at EDF’s Belleville nuclear plant citing failures in safety standards. It also demanded a temporary halt in production at the Tricastin nuclear power plant due to flaws at a canal dike that could lead to flooding. Some cases warranted a serious probe, which was why they were classified as “Level 2” incidents on the international nuclear and radiological event scale, where Level 1 marks the lowest level of risk while Level 7 is the highest. The number of such incidents have been on the rise. This was happening while companies in the sector were facing financial difficulties. The regulator was still examining requests to extend the lifespan of the French nuclear fleet, and was particular looking at several key factors such as anomalies that have gone undetected over the years.

Iraq’s Foreign Minister is asking nuclear countries for help building an atomic reactor for peaceful purposes, saying the country has a right to use atomic power peacefully. He made the request in his speech to the UN General Assembly’s annual meeting of presidents, prime ministers and monarchs. He called for assistance “to build a nuclear reactor for peaceful purposes in Iraq, to acquire this nuclear technology.” Iraq’s earlier efforts to build a nuclear reactor were met with an Israeli airstrike in 1981 and years of suspicion about its nuclear intentions.

China plans to complete ahead of schedule a $2 billion hydropower project in Pakistan-occupied Kashmir (PoK) to ease an energy crisis in Pakistan. The Karot Hydropower Project is being built on Jhelum river on a “build-own-operate-transfer” basis for 30 years. It will be owned by a Chinese company for 30 years, after which ownership will be turned over to the government of Pakistan. Karot Power Company Ltd, a subsidiary of China Three Gorges South Asia Investment, owns the Karot Power Station. The company said that the project will help ease Pakistan’s power shortage and generate local employment. Karot Power Station has a capacity of 720 MW and China Three Gorges South Asia Investment also has other power projects in Pakistan, including hydro, wind and solar power, which would largely solve Pakistan’s problem.

BNP Paribas, France’s biggest listed bank, said it would no longer work with oil and natural gas companies that primarily do business in shale or oil sands as it plans to boost support for renewable energy projects. The bank also said that it would no longer finance new projects that are primarily involved in the transportation or export of oil and gas from shale or oil sands. The bank previously said it planned to spend €15 billion to finance renewable energy projects by 2020 and invest €100 million in start-ups specializing in energy storage and efficiency. The lender has already stopped financing coal mines and coal-fired power plants, and no longer supports coal companies that are not planning to diversify their energy sources. BNP Paribas’s smaller rival Societe Generale said in October last year that it would quit financing coal-powered electricity plants from January and increase its support for renewable energy projects.

Oil refinery workers, executives and local politicians gathered near Philadelphia to urge the White House revamp the nation’s renewable fuels program, arguing the future of their plants are at stake. The US renewable fuel program requires higher levels of ethanol and other biofuels to be blended into the nation’s fuel pool, a requirement pitting the oil industry against the powerful farm lobby. President Donald Trump has promised corn growers he would protect the program, while also signalling that he sympathizes with US refiners who bear its costs. The speakers told a crowd of about 100 that the tradable credits at the centre of the renewable fuel program have been exploited by banks and trading firms, threatening the viability of merchant refiners like Monroe Energy and PBF Energy. The US RFS requires US refiners and importers blend ethanol into their fuels or purchase credits from companies that do. The credits fell to a year-to-date low of 34 cents in March amid optimism that Trump would revamp RFS and shift some costs to retailers and others, but it now appears he will not make that change. The US EPA has angered the biofuels industry by calling for less biofuel blending. It also wants to allow exported ethanol to earn credits, increasing the pool of credits and driving down prices.

The EPA is considering a change to US biofuels policy that would allow exports of ethanol to count toward the country’s annual biofuels volumes mandates. The proposal would represent a significant shift from the original mandate of the 2005 renewable fuel program, designed to increase the amount ethanol and biodiesel in the country’s fuel pool while boosting the US agricultural sector. The move would benefit US merchant refiners like Valero and PBF Energy, who are required under the US RFS to blend increasing volumes of ethanol and other biofuels into the country’s gasoline and diesel every year, at a cost of hundreds of millions of dollars. Currently, US biofuels policy only counts fuels blended in the US toward the annual volumes mandates and does not count ethanol that is produced in the US and exported for use abroad. By counting the exports, it would increase the amount of available credits by the equivalent of as much 1 billion gallons of biofuel and push down prices. The EPA proposed a requirement that refiners and importers blend in 15 billion gallons of corn-based ethanol and other conventional renewable fuels next year.

As the sun sets on Japan’s solar energy boom, companies and investors are rushing into wood-burning biomass projects to lock in still-high government subsidies. More than 800 projects have already won government approval, offering 12.4 GW of capacity — equal to 12 nuclear power stations and nearly double Japan’s 2030 target for biomass in its basic energy policy. The sheer number of projects has raised questions about how they will all find sufficient fuel, mostly shipped in from countries like Canada and Vietnam, while some experts question the environmental credentials of such large-scale plants. The projects approved to date that use general wood fuel would need the equivalent of up to 60 million tonnes of wood pellets, compared with global output of 24 million tonnes in 2014, Takanobu Aikawa, a senior researcher at Japan’s Renewable Energy Institute, said. Other fuels such as local forest thinned woods or palm kernel shells from Indonesia and Malaysia would not make up the shortfall, he said. Biomass plants generate energy by burning fuels, releasing carbon dioxide into the atmosphere. They qualify as renewable because plants absorb CO2 as they grow, with a lifespan of years rather than the millions of years needed to make fossil fuels such as coal. Japan Renewable Energy, in which Goldman Sachs has a stake, is building its first biomass power station north of Tokyo, adding to solar and wind power plants. Major utilities, such as Chubu Electric Power Co, are also looking to co-fire biomass in their coal power plants to help cut emissions. Japan wants renewables to account for 22-24 percent of its electricity mix by 2030.

Microsoft has signed a 15-year wind energy agreement with GE in Ireland, becoming one of the first global technology firms to support a new wind project in the country. Microsoft will purchase 100 percent of the wind energy from its new, 37 MW Tullahennel wind farm in County Kerry, Ireland. The agreement will help support the growing demand for Microsoft Cloud services from Ireland, the company said. As part of the deal, Microsoft also signed an agreement with Dublin-based energy trading company ElectroRoute that will provide energy trading services to Microsoft. The wind farm will integrate GE’s ‘Digital Wind Farm’ technology, which makes renewable energy outputs even more reliable. Once operational, the new wind project will bring Microsoft’s total global direct procurement in renewable energy projects to almost 600 MW.

A trade dispute over solar imports has stalled clean-energy projects across the US. With the looming prospect of tariffs driving up the price of panels, utilities and businesses are holding off on signing deals to buy solar power. It may be months before they get more clarity. The trade case dates to an April complaint from Suniva Inc, a bankrupt solar manufacturer based in Georgia. The US International Trade Commission ruled that the US industry has been harmed by a flood of cheap imports, and President Donald Trump will get to decide whether to impose tariffs. With solar development slowing, some corporate buyers may turn instead to wind farms. Such contracts with businesses have been a significant driver of growth for both types of clean energy in the US.

Norway’s Statoil is taking its first step into the solar sector, partnering up with Oslo-listed renewable energy firm Scatec Solar in a JV aiming to build several large-scale solar plants in Brazil. Bruised by pressure on oil prices over the last two years, European oil companies have been intensifying their expansion into renewable energy to seek new sources of revenue. With a 40-percent share in Scatec’s construction-ready 162 MW Apodi farm and a 50 percent share in the project execution company, Statoil adds to a renewable energy portfolio that until now has consisted mainly of offshore wind projects. In September, Scatec Solar said the company was in talks to build its first solar power plants in Iran, joining a wave of foreign energy firms looking to invest in the country.

The IEA raised its forecasts for renewable energy over the next five years following a record 2016. In its medium-term renewables market report, the IEA expects global renewable electricity capacity to rise by more than 920 GW, or 43 percent, by 2022, due to supportive policies for low-carbon energy and cost reductions for solar PV and wind. The projected growth is 12 percent more bullish than the IEA’s forecast last year. In 2016, net additions to renewable energy capacity – including hydropower, solar, wind, bioenergy, wave and tidal – set another world record, growing by 165 GW, 6 percent more than in 2015, the report said. Solar PV capacity grew by 50 percent to reach more than 74 GW last year and it was the first time solar PV additions rose faster than any other fuel, surpassing the net growth in coal. The agency sees renewable power generation rising by more than a third to 8,169 TWh in 2022 – from around 6,012 TWh in 2016 – which is equivalent to the combined electricity consumption of China, India and Germany. China will be responsible for the largest amount of global renewable capacity growth, driven by strong government targets, economic incentives and air pollution concerns. India’s renewable electricity growth could surpass the EU’s by 2022 for it to become the joint second-largest growth market alongside the US as it is seen more than doubling its current capacity.

MW: megawatt, GW: gigawatt, CEA: Central Electricity Authority, kWh: kilowatt hour, PPAs: power purchase agreements, TWh: terawatt-hours, EU: European Union, IEA: International Energy Agency, PV: photovoltaic, SECI: Solar Energy Corp of India, MNRE: Ministry of New and Renewable Energy, KERC: Karnataka Electricity Regulatory Commission, TANGEDCO: Tamil Nadu Generation and Distribution Corp, JV: joint venture, UP: Uttar Pradesh, AGEL: Adani Green Energy Ltd, AEL: Adani Enterprises Ltd, UK: United Kingdom, IOC: Indian Oil Corp, BPCL: Bharat Petroleum Corp Ltd, HPCL: Hindustan Petroleum Corp Ltd, CCEA: Cabinet Committee on Economic Affairs, US: United States, TEPCO: Tokyo Electric Power Company, NRA: Nuclear Regulation Authority, UN: United Nations, RFS: Renewable Fuel Standard, EPA: Environmental Protection Agency

Courtesy: Energy News Monitor | Volume XIV; Issue 20