Time to end ‘Make Believe’ in India

Lydia Powell, Observer Research Foundation

2014 has been an eventful year for energy. During the first half of the year, narratives of shortages in coal, gas and power dominated the sector. Scams in each of these sectors supposedly scripted and executed by the previous Government were blamed for the dire state of the energy sector. Commentators highlighted how India was becoming one of the biggest importers of coal despite having large reserves of coal. Alarming figures were presented for future volumes of imported coal. Charts of the hockey stick variety that predicted economic doom for the country on account of growing trade deficit that imported coal would impose on the country could be seen everywhere. Observers lamented that natural gas could not be pumped out because of poor governance of the oil & gas sector. Power shortages were said to be the consequence of fuel shortages and governance shortages. Renewable energy sectors such as solar and wind were said to be on the decline as policies such as Accelerated Depreciation and Generation Based Incentives were withdrawn and Mandatory Purchase Obligations (such as Renewable Purchase Obligations or RBOs) for renewable energy sources were not imposed.

The second half of the year brought a new Government that was supposedly going to set right all the mistakes that were made by the previous Government. We were told that once the new Government completes reform, shortages will be history. Recently we were also told that India’s coal production would increase to 1 billion tonnes (BT) by 2019 and that we will simultaneously have 200 GW of solar power probably to off-set all that dirty carbon that burning of 1 BT of coal would produce. An amendment of the Electricity Act would supposedly impose punitive penalty for violation of RBOs that would boost solar power.  In just five years India will simultaneously be fossil fuel driven, energy abundant, clean and green or so we are told.

The cornucopian energy narrative promoted by the new Government is understandable. It has come to power on the premise that growth, abundance and prosperity are substitutes for everything including freedom, ethics and justice. It has to create illusions of grandeur with exaggerated figures and projections to keep the narrative alive. But this narrative of make-believe is unsustainable. As illustrated by many of the analysis pieces and news items that have appeared in various issues of ORF Energy News Monitor, reality appears to slowly undermining the Big Story of the new Government. Coal shortages, power shortages and even governance shortages appear to be more nuanced than what we were led to believe. Clearly, there is something wrong with the simple meta-narratives that are force fed to us by the Government and its client, the media.

The liberal philosopher Isaiah Berlin distinguished between foxes and hedgehogs among thinkers drawing from an ancient Greek saying which said that ‘the fox knows many things but the hedgehog knows one big thing’.  Berlin favoured foxes over hedgehogs. Unfortunately, for the new Government energy policy is just one big ‘hedge hog’ idea: Think Big: Big Coal, Big Solar and so on. (Effectively it is a ‘take projections for supply and multiply it by five’ policy). Complications and exceptions are marginalised or compressed into this World View.  Foxes of energy policy that have a variegated view are not comfortable with one big slogan. Foxes are sceptical of grand theories as they feel that complexities in the sector prevent generalisations. The hedgehog Government thinks that one big idea is substitute for policy but foxes think that the devil is in the details.  Emerging reality supports the foxes. Energy policy cannot be a daily exercise of exaggeration.  In the New Year, we need to put an end to this Make Believe in India. Otherwise we cannot make anything in India, including energy policy.

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 28

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POWER TARIFFS MOVING UP

Monthly Power News Commentary: April – May 2018

India

Saddled with a debt burden of ₹ 805 billion, discoms in Rajasthan were given a lifeline in 2016 under the UDAY scheme. But after two years, their performance on many parameters shows that the scheme is far from being a panacea for the beleaguered power sector even as it left the state finances in complete disarray, constraining its spending for developmental works. The latest data available till December 2017 shows that the discoms in the state are still struggling to achieve the mandated level operational efficiency in key parameters. The progress in reducing AT&C losses has fallen short by a huge margin. While the target was to bring down the AT&C losses to 18.42%, the reduction has been marginal, falling to 24.44% from 26.02% in the previous year. Similarly, the state discoms have failed to meet the improvement in reducing the aggregate cost of supply and aggregate revenue realization per unit of power. Against a target ratio of 0.2%, the gap is still 0.26% showing an anemic fall from 0.29% in the previous year. The performance on the profit & loss front is neither encouraging. Instead of reducing the losses to ₹ 10.55 billion, they still remain higher at ₹ 14.46 billion.

The Himachal Pradesh State Electricity Regulatory Commission has announced revised tariffs for domestic and commercial consumers. Though there has been an increase in the energy charge rates for domestic category of consumers, but the same has been kept same as last year after accounting for the subsidy provision made in the budget. There is average increase of 1.5% in tariff for non-domestic and non-commercial power supply, 1.5% for industries, 2.5% for commercial and 3% for domestic water pumping supply. The state government has made a provision of ₹ 4.75 billion in the financial budget for 2018-19 for providing rollback subsidy to electricity consumers of domestic and agriculture categories during the year. Therefore, there is no effective increase in energy charges for domestic category and they will continue to pay the same energy charges as earlier. For agricultural consumers under the irrigation and drinking water pumping supply category, the energy charges shall be ₹ 0.75/kWh for consumer category up to 20 KW under single part tariff and ₹ 0.75/kWh only for LT category under a two-part tariff. These revised energy charges on account of government subsidy would only be applicable to agricultural and allied activities and which are paid for by individuals/ user groups but shall not be applicable on government supply. The HPSEBL had projected the annual revenue requirement of ₹ 69.55 billion for financial year 2018-19, which includes true-up gap of ₹ 3.65 billion for financial year 2016 (based on final audited account) and true-up gap of ₹ 2.52 billion for financial year 2017 (based on provisional audited account). Total revenue income and expenditure approved for HPSEBL for 2018-19 are ₹ 539.6 million and ₹ 53.89 billion, respectively. The commission has allowed ₹ 419.2 million against the demand of ₹ 3.65 billion for true-up gap of financial year 2016 by the HPSEBL. The commission has not considered the true-up gap of ₹ 2.52 billion for financial year 2017 as the same was not based on final audited accounts. It has also approved a provisional amount of ₹ 2 billion towards arrears liability accruing on account of the Seventh Pay Commission against the total demand of ₹ 6.72 billion made by the HPSEBL on this account. Considering the revenue from the existing tariff, a revenue gap of ₹ 1.38 billion has been observed for financial year 2019. Therefore, it has approved an overall tariff increase to meet this gap.

Electricity bills of consumers in Punjab are expected to inflate with the Punjab State Electricity Regulatory Commission announcing an average power tariff hike of about 2 percent across all categories for 2018-19. The Commission also decided to marginally increase fixed charges along with an increase of about 2 percent over the existing energy charges. In the new tariff order released, the commission assessed the Aggregate Revenue Requirement of power utility PSPCL at ₹ 324.86 billion for 2018-19. The combined average cost of supply for 2018-19 worked out to be 655.49 paise/kWh.

Jharkhand has hiked the electricity tariff for domestic consumers up to 98 percent and slightly reduced the tariff for commercial industries, the State Regulatory Board said. As per the new rates, domestic consumers will have to pay ₹ 5.50/kWh for 200 units as compared to earlier ₹ 3/kWh while the tariff has been reduced to ₹ 6/kWh from the existing ₹ 6.80/kWh for the commercial industries. New tariffs were being imposed to improve the state’s power system. Poor workers, farmers and small traders would be provided subsidy by the state government and an announcement in this regard would be made soon. In rural areas, the new tariff has been set at ₹ 4.40/kWh from the existing 1.25/kWh. The farmers too have to foot more bills as ₹ 5/kWh will be charged for irrigation from existing ₹ 0.70-1.25/kWh.

More than seven decades after independence, India has achieved electrification of all its villages after electricity reached Leisang village in Manipur. All of the country’s 597,464 census villages have been electrified. Electrified means the village is connected to power grid. It essentially does not mean that all its habitants have access to electricity. According to government definition, a village is considered electrified if it has the basic electrical infrastructure and 10 percent of its households and public places have power. When the current government launched its version of the village electrification scheme — the ₹ 760 billion Deendayal Upadhyaya Gram Jyoti Yojana — there were an estimated 18,452 unelectrified villages. An additional 1,275 villages were added to the list subsequently. About 31.4 million rural households, or 17 percent of total 179.9 million rural households, still do not have any access to electricity. The highest number of them are in Bihar, UP, Assam, Jharkhand and Odisha. To take electricity to all households by end 2018, the government has launched the Pradhan Mantri Sahaj Bijli Har Ghar Yojana or the Saubhagya scheme. Of the ₹ 163.20 billion needed for the task, ₹ 123.20 billion has already been provided in the Union Budget.

Madhya Pradesh claimed all villages in the state will be electrified by October and ₹ 2 trillion spent on development of tribals in five years.

In a cluster of 50 villages in Bijnor, where power is supplied through 50-year-old overhead cables, villagers have to face hours-long outages almost daily. Electricity is supposed to be supplied for 22 hours in a day to urban areas and 18 hours a day to rural areas. However, such old and dilapidated power lines are proving a significant hurdle. According to data provided by circle office of Paschimanchal Vidyut Vitran Nigam Ltd, there over 4,500 km of weak and loose electric wires, which result in accidents causing, on an average, the death of nine people every year and disruption of power supply. Power supply to around 50 villages depends on the velocity of the wind. The two feeders — Kaziwala and Dharamnagari are connected with Bijnor city’s sub power station and from these, power is supplied to around 50 villages where consumers are facing lot of power cut especially at the time when the velocity of the wind increases. As summer season has set in and heat wave has also started lashing the plains, consumers of these villages are facing power cut problems. Villagers said, it will increase with the passage of time.

Over hundred villages in Jammu and Kashmir are “un-electrified”, the state government said adding efforts were on to ensure power supply reaches them by the end of next month. A total of 102 villages in Jammu region remain un-electrified and all out efforts are on to cover these villages. To meet the deadline the department had deployed the Indian Air Force to reach inaccessible areas. The Chenab river alone has a potential to generate 22000 MW of power. Power Grid Corp of India Ltd, India’s largest power transmission utility, will invest ₹ 25,000 billion across various projects in the current financial year ending March 2019. The firm has signed a MoU with the power ministry dealing targets that also include parameters related to human resources, project management, R&D and innovation and efficiency. The company currently owns and operates over 148,800 circuit km of transmission lines, 236 Extra High Voltage sub-stations with transformation capacity of more than 322,000 Milli Volt Ampere. Availability of this transmission network has been maintained at over 99.5 percent, the company said.

All 39,073 villages and 106,249 ‘tolas’ (sub-unit in villages) of Bihar are now electrified. All 2.6 million households in Bihar would be provided free electricity connection by end of coming December. Bihar CM said that the centre adopted ‘Saubhagya’ scheme from Bihar model of “Har Ghar Bijali Lagataar’, a major component of the state government’s ‘Saat Nischay’ (seven resolves) programme which promises free electricity connection to each households across the state. CM had launched the Bihar model of free electricity connection programme at an event on November 15, 2016. The Saubhagya scheme was launched by Prime Minister Narendra Modi on September 25, 2017, more than 10 months after Bihar launched ‘Har Ghar Bijali Lagataar’ scheme. While the centre’s Saubhagya scheme promises to provide free electricity connection to over 4 billion households by December 2018, Bihar government’s ‘Har Ghar Bijali Lagataar’ has resolved to provide free electricity connection to all 2.6 million households of the state by the same period.

Citizens would be compensated for unscheduled power cuts lasting longer than one hour if a policy approved by the Delhi government gets a green signal from Lt. Governor Anil Baijal. The compensation would be provided to consumers in their monthly electricity bills. In case of a power cut, a consumer has to file a “no current” complaint through SMS, email, phone, mobile application or website and along with their name, CA number and mobile number. The power distribution company would then attend to the complaint and send a confirmation message to the consumer with power restoration date and time. The respective compensation amount would be then credited to the CA number automatically and a message would be sent to the consumer. This amount would be then adjusted in the consumer’s monthly electricity bill.

In a bid to curb power theft in the city, state government-owned power distribution company, Dakshinanchal Vidyut Vitral Nigam Ltd, is planning to install smart meters in both residential and commercial establishments. Under the new system, through modem (modulator-demodulator) equipped smart meters, data of power consumption by each consumer will be maintained by a central server at the control room. Any theft will immediately be detected and dealt with. Moreover, meter-readers will no longer have to visit each establishment for taking a reading. In the first phase, the power corporation will install the smart meters in those establishments having connections with loads above 10 kilowatt. These include commercial establishments like shopping malls, hospitals and schools besides bulk consumers such as group housing. According to records maintained by the discom (distribution company), in Agra zone, there are about 30,000 electricity connection with loads ranging from 10 KW to 100 KW. Smart meters will also help collect data on real-time or near real-time reading, send power outage notification and monitor power quality like voltage. Smart meters will end the entire work of meter-reading leaving no scope for irregularities on the part of meter-readers and consumers.

The government kicks off a Pilot Scheme for Procurement of Aggregate Power of 2500 MW on competitive basis for 3 years under medium term i.e. from generators with commissioned projects but without Power Purchase Agreement. The power ministry had recently issued the model bid documents, model PAPP and PPSA on 6th April, 2018. The Guidelines for the said scheme were issued on 10th April, 2018. PFC Consulting Ltd has been appointed as Nodal Agency and PTC India Ltd as the Aggregator. PTC India would sign three-year (mid-term) Agreement for Procurement of Power with successful bidders and Power Supply Agreement with the discoms. Under the scheme a single entity can be allotted maximum capacity of 600 MW. The Scheme assures a minimum off-take of 55 percent of contracted capacity. The Tariff will be fixed for three years without any escalation. PFC Consulting Ltd is in process of inviting the bids in first week of May, 2018 under the scheme. The bidding will be conducted on the DEEP e-Bidding Portal and with L1 matching for bucket filling without reverse auction. This scheme is expected to revive the power demand which has affected the generators not having Power Purchase Agreements.

The UP cabinet overturned the decision of the previous government decision to construct the Karchana power plant in Allahabad by the state government. The cabinet instead decided that the project will be developed through competitive bidding. The 1,320 MW power project was to be developed by the state-owned UP Rajya Vidyut Utpadan Nigam. According to the detailed project report of the state government, the project is expected to cost around ₹ 105 billion. The cabinet also decided to get the transmission substations constructed for Jawaharpur and Obra power plants through a tariff based competitive bidding. The state government plans to construct a 400 kilovolt transmission substation each in Badaun and Firozabad for evacuation of power from Jawaharpur power project.

State Bank of India is preparing a major debt restructuring and takeover plan for stressed power assets, to improve valuations and attract new owners with incentives and a quick resolution process. The country’s largest lender has called all power plant lenders in Mumbai for discussing a proposal that has a direct bearing on loans adding up to ₹ 1.77 trillion in 75,000 MW stressed capacity. It has also asked the power ministry to waive transmission penalties and grant early regulatory approvals to help new promoters. The bank proposes to get debt of the stressed assets rated by credit rating agencies. The projects will be offered to the NIF. The fund will invite bidders with a base price. Otherwise, NIF will take over the projects and hand them to companies such as NTPC or private firms for operations on contract basis. Power sector financiers Power Finance Corp had also mooted a proposal to float joint venture with companies like Rural Electrification Corp, NTPC Ltd and BHEL to acquire stressed assets. The proposal has however been shelved due to lack of concurrence and stringent Reserve Bank of India rules. Currently, more than 75,000 MW generating assets, either operating or under construction are severely stressed due to various reasons like lower availability of coal, lack of power purchase agreements and delays in regulatory clearances. The government is reviewing 34 stressed thermal power projects with an estimated debt of about ₹ 1.77 trillion.

The UPPCL signed an MoU to replace 40 million conventional electricity meters with smart ones. This move of UPPCL, in association with EESL, seeks to address the state’s power woes and ensure customer convenience. Implementing the smart meter programme is one of the operational performance parameters of the Centre’s UDAY scheme. As per the MoU, EESL will invest ₹ 26 billion, enabling discoms to ₹ 80 billion in eight years.

After nearly a decade, the Tamil Nadu government has allowed private power companies based in the state to sell more than 1 MW of power directly to industrial consumers. Companies can sell power after paying the wheeling and cross subsidy surcharge to TANGEDCO. The decision was taken owing to the availability of surplus power, with supply likely to rise in a few days when the wind season begins. A decision not to allow private companies to sell more than 1 MW power directly to consumers was taken in 2009 as there was a power shortage. The latest government decision to allow open access sale of power is likely to be a boon for private power companies as TANGEDCO is not evacuating power from these companies to the maximum capacity. But private companies want the government to lower the cross subsidy surcharge. TANGEDCO said the decision to lower the cross subsidy surcharge depends on the Tamil Nadu Electricity Regulatory Commission.

Himachal Pradesh will take up the issue of its 7.19 percent share in electricity generated from power projects run by BBMB with the governments of Punjab, Haryana and Rajasthan to get the matter expedited. Himachal Pradesh has been demanding its share in electricity generated from BBMB power projects for long. The state would raise its demand of share in BBMB as per the Supreme Court ruling.

Rest of the World

A senior counsel of France’s highest administrative court, the Council of State, has recommended that France end regulated electricity prices, state-controlled utility EDF said. The utility said it had noted the recommendation, which argued the regulated tariffs, which some 30 million clients are still subscribed to, did not comply with European competition regulations. EDF said it would make no further comment. The court’s final decision is expected by the end of May. An end to regulated prices could intensify competition in France’s retail electricity market, where EDF faces growing competition from alternative suppliers. French oil and gas major Total in April said it would buy a majority stake in electricity retailer Direct Energie in a €1.4 billion ($1.67 billion) deal. Italy’s energy group Eni and French consumer retailer Casino have also entered the power market. A decade after France liberalized it energy sector, former monopoly EDF still holds around an 85 percent share of the retail power market, with most of its customers on regulated tariffs.

South African power utility Eskom, which is grappling with liquidity problems, pledged that it would not resort to controlled power blackouts this year despite reports that it was facing coal shortages. Eskom supplies about 95 percent of South Africa’s electricity, predominantly by burning coal. The state-owned utility has been forced to introduce nationwide electricity cuts in the past decade, the latest in 2015, denting economic output. Eskom said that six power plants currently had less than the required coal supplies, down from seven recently, and the company has raised 43 billion rand ($3 billion) to run its operations since January.

New York’s power grid operator forecast that demand for power from the system will decline over the next decade due to efficiency programs and as more homes and businesses generate their own electricity on site. The NYISO, the grid operator, projected power demand would decline at a rate of 0.14 percent per year through 2028. Annual electric usage in 2017 fell to its lowest level since 2001, according to the NYISO. In 2017, demand peaked at 29,699 MW, which was 7.4 percent below 2016’s peak of 32,075 MW and 12.6 percent below the record peak of 33,956 in 2013. One megawatt can power about 1,000 US homes. At the same time that demand for power from the grid is declining, the NYISO said the state’s generation mix is changing as energy companies build mostly natural gas-fired units downstate and mostly wind farms update, while coal and nuclear plants retire.

Croatia’s spot power exchange CROPEX said it would merge with its Slovenian counterpart BSP SouthPool on June 19 after a successful completion of testing activities. The merger, initially planned for 2017, was delayed for regulatory and technical reasons. CROPEX said the go live date is subject to final approval by the regulatory authorities. The aim is to join the rest of Europe through the so-called Multi-Regional Coupling project which includes 19 countries that account for about 85 percent of European power demand. Electricity traders expect the link-up to push Croatian trading prices up because of its connection with the more expensive Italian market. Power markets coupling is designed to optimise the allocation process of cross-border capacities through a coordinated calculation of prices and flows between countries. It uses so-called implicit auctions in which players do not actually receive allocations of cross-border capacity themselves but just bid for electricity in their exchange. The exchanges then use the available cross-border transmission capacity to minimize the price difference between two or more areas. The aim is to spur more competition, provide better supply and more stable prices for consumers.

PetroVietnam Power Corp has been granted government approval to build two gas-fired power plants in southern Vietnam at a total cost of nearly $1.5 billion, its parent company said. The Southeast Asian country is developing a wave of new power plants to support economic growth that is among the strongest in Asia. Vietnam’s gross domestic product grew 6.81 percent last year, faster than an expansion of 6.21 percent a year earlier. The Vietnamese government has given the go-ahead for the two facilities in the province of Dong Nai, state oil firm PetroVietnam, which holds a 51 percent stake in PetroVietnam. The Nhon Trach 3 and Nhon Trach 4 plants will have a combined capacity of 1,500 MW and will cost 33.3 trillion dong ($1.46 billion) to build, PetroVietnam said. They are scheduled to start generating in 2020 and 2021 respectively. In a separate deal, Singapore’s Sembcorp Industries said its wholly-owned subsidiary, Sembcorp Utilities, signed a MoU with Vietnam to build another power plant in the country.

China will launch its first real-time spot electricity markets in eight regions, the NEA said, as Beijing accelerates efforts to liberalize power prices currently set by the government. In a draft rule, the NEA outlined guidelines for eight regions to set up real-time trading platforms that will set prices for the cash market as well as those for a day ahead, allowing power generators, industrial users and distributors to trade power in real time. The eight regions are Guangdong, western Inner Mongolia, Zhejiang, Shanxi, Shandong, Fujian, Sichuan and Gansu. Their power generation in 2017 was 2.6 trillion kilowatt-hours, 42 percent of China’s total. The move comes after those regions launched electricity markets last year for monthly and quarterly prices.

Middle Eastern and North African countries need to spend $260 billion over the next five years for electricity production to meet rising demand. The region, which includes oil heavyweights Saudi Arabia, Iran and Iraq, must make the investments to add 117 GW of power generation by 2022, Arab Petroleum Investment Corp said. The Dammam-based energy development bank said $152 billion is needed for electricity generation and the rest for transmission and distribution projects. It estimated that power capacity in the Middle East and North Africa, currently standing at 321 GW, needs to expand by 6.4 percent on average annually by 2022 to meet growing demand. The six nations belonging to the Gulf Cooperation Council — Bahrain, Kuwait, Oman, Qatar, Saudi Arabia and the United Arab Emirates — need to spend $89 billion to add 43 GW over the next five years, according to APICORP estimates. Iran needs to add 25 GW of power to its current capacity of 77 GW with estimated investments of $50 billion. Iraq, another oil-rich country, is required to invest $39 billion to add 12 GW of electricity by 2022. Egypt, the most populous country in the region, is estimated to need $46 billion of investments to add 22 GW of power to raise its capacity to 60 GW in 2022.

UDAY: Ujwal Discom Assurance Yojana, discoms: distribution companies, AT&C: Aggregate Technical and Commercial, kWh: kilowatt hour, HPSEBL: Himachal Pradesh State Electricity Board Ltd, PSPCL: Punjab State Power Corp Ltd, km: kilometre, MW: megawatt, NIF: National Investment Fund, MoU: Memorandum of Understanding, CM: Chief Minister, CA: Consumer Account, KW: kilowatt, UPPCL: Uttar Pradesh Power Corp Ltd, EESL: Energy Efficiency Services Ltd, TANGEDCO: Tamil Nadu Generation and Distribution Corp, BBMB: Bhakra Beas Management Board, NYISO: New York Independent System Operator, US: United States, NEA: National Energy Administration, APICORP: Arab Petroleum Investment Corp, GW: gigawatt

Courtesy: Energy News Monitor | Volume XIV; Issue 49

Review of India’s Forest and Environment Related Laws – A Glance at MoEF&CC HLC Report

K K Roy Chowdhury, Energy & Environment Expert, Delhi

  1. The Ministry of Environment, Forests & Climate Change (MoEF&CC) administers a number of statues enacted by the Parliament. These statues inter-alia include the following:
    • Environment (Protection) Act, 1986 (EP Act)
    • Forest (Conservation) Act, 1980 (FC Act)
    • Wildlife (Protection) Act, 1972 (WLP Act)
    • The Water (Prevention and Control of Pollution) Act, 1974 (Water Act)
    • The Air (Prevention and Control of Pollution) Act, 1981 (Air Act).

Based on experience gained in the implementation of aforesaid Acts, MoEF&CC decided and constituted a High Level Committee (HLC) under the Chairmanship of Shri T S R Subramanian, Former Cabinet Secretary, to review these Acts and suggest appropriate amendments to bring them in line with their objectives. The MoEF&CC Office Order in this regard was issued on 29th August 2014. The HLC was asked to submit its report to the Ministry within two months. In partial modification of this Order, the Ministry through its Office Order of 18th September 2014, included The Indian Forests Act, 1927 (IF Act) into the Terms of Reference of the HLC. Further, the tenure of the HLC was extended for a further period of one month i.e. from 29th October 2014 to 28th November 2014.

  1. It is understood that the aforesaid High Level Committee, in course of their work, also conducted several public consultations with NGOs, environmental activists, industry associations, and others, and invited suggestions from different stakeholders. Subsequently, the Committee submitted its Report on Forest and Environment Related Laws to MoEF&CC in November 2014. The summary of recommendations of the High Level Committee is briefly reproduced below.
  2. Summary of Recommendations of the High Level Committee
    • It is suggested to identify and pre-specify ‘no go’ forest areas, mainly comprising PAs and forest cover over 70% canopy.
    • It is suggested that the Ministry may define the term ‘forest’ at an early date.
    • It is suggested to offer economic incentives for increased community participation in farm and social forestry by way of promoting and proving statutory safeguards to ‘treelands’ as distinct from ‘forest’.
    • It is suggested that plantation of approved species on private lands could be considered for compensatory afforestation with facility for ‘treeland’ trading.
    • It is suggested to revise procedure for clearance under FC Act as above, which is intended to reduce the time taken, without compromising the quality of examination. For linear projects, it is recommended that FR Act needs amendment to consider removal of thecondition of Gram Sabha approval.
    • It is suggested that Compensatory Afforestation guidelines be revised; CA (compensatory afforestation) on revenue land to be enhanced to 2:1 as against 1:1 at present; CA in degraded forest land be now fixed at 3:1; the NPV (net present value) should be at least 5 times the present rates fixed. An appropriate mechanism to be created to ensure receipt of the CA funds, and their proper utilisation, delinking the project proponent from the CA process, after he obtains other approvals, and discharges his CA financial obligations.
    • It is suggested that the quantum of NPV for compensatory afforestation needs to be sharply increased. A reliable mechanism for ensuring that CA is actually implemented, utilising either private or forest land, needs to be put in place.
    • It is suggested that Schedule 1 be amended to include species likely to be threatened by illegal trade. An expert group should review the existing schedules and address discrepancies relating to several species and sub species.
    • With regard to the issue of tackling damage to agriculture and farmland by amendments in Schedule 3, it is suggested that the MoEF&CC may issue circulars to all States apprising them of the legal position, suggesting that they may take appropriate action based on legal provisions.
    • It is suggested that preparation of Wildlife Management Plans be made mandatory and a provision to this effect inserted in the WLP Act.
    • It is suggested that Section 26A sub section (3) and section 35(5) be amended so that permission from the Central Government would only be necessary when the State Government proposes to reduce the boundaries of an existing PA (protected area).
    • It is suggested that manufacture and possession of leg and mouth traps be completely prohibited, except where they are required for visual display for educational purposes.
    • It is suggested that officers entrusted with the task of settlement be given minimum tenure of 2 years. Regular review of such work should be done to ensure completion within time.
    • It is recommended that ‘expert’ status may be given to the forensic facility of WII (Wildlife Institute of India), after suitably strengthening it.
    • It is recommended that Section 50 and 55 of the WLP Act may suitably provide for adequate and purposeful delegation appropriate for faster and better prosecution in respect of a wildlife crime.
    • It is suggested that officers of the Wildlife Crime Control Bureau under the MOEF&CC are authorised to file complaints in Courts.
    • It is suggested that polythene bags and plastic bottles be added to the banned list in Section 32.
    • It is recommended that MoEF&CC to take immediate steps for demarcation of eco-sensitive zones around all the protected areas; States may be asked to send proposals in a time-bound manner.
    • It is recommended that powers to approve applications for bona fide observational research, through photography, including videography may be delegated to the level of Park Director, after verifying the credentials.
    • It is recommended that the Schedules provide appropriate provision for taking into account the needs of local festivals, subject to no harm or injury to animals.
    • It is proposed to revamp this project clearance/ approval process.
    • It is proposed to create a National Environment Management Authority (NEMA) at the Central and State Environment Management Authority (SEMA) at the State level as full time processing / clearance / monitoring agencies.
    • The committee has proposed the following:
      • Composition, functions and responsibilities of NEMA.
      • Composition, functions and responsibilities of SEMA.
    • It is proposed that the revised project approval process envisages ‘single-window’ unified, streamlined, purposeful, time-bound procedures.
    • It is proposed that special treatment is offered to linear projects, power/ mining and strategic border projects.
    • It is suggested to review of A/B category units, to delegate a large number brought under the purview of SEMA.
    • It is suggested to strengthen the present monitoring processes, exclusively based on physical inspection by induction of technology, measuring instruments incorporating latest improvements; the standard setting and verification systems be tightened to ensure all violators are identified.
    • It is suggested to:
      • Create a new ‘umbrella’ law – Environmental laws (Management) Act (ELMA) –to enable creation of the institutions NEMA and SEMA.
      • Induct the concept of ‘utmost good-faith’, holding the project proponent responsible for his statements at the cost of possible adverse consequences; thus also contributing to reduction in ‘inspector raj’.
    • It is suggested that the new law prescribes new offences, as also for establishing special courts presided over by session judge. ‘Serious offences’ as defined to attract heavy penalties, including prosecution/ arrest.
    • It is suggested that the central and State Pollution Control Boards be superseded by NEMA/SEMA.
    • It is recommended that noise pollution be incorporated as an offence in EP Act.
    • It is suggested that the procedure for appeals is created through the creation of an appellate tribunal.
    • It is suggested that the role for NGT (National Green Tribunal) is reviewed judicially.
    • It is suggested to
      • Establish a National Environment Research Institute, through an Act of Parliament.– SEMA
      • Identify specific technical institutions/ universities in India to act as technical advisors to the proposed NEMA/ SEMA and other environmental enforcement agencies, to provide credible technical back-stopping for management of the environment.
    • It is suggested that an Indian Environment Service may be created, as an All India Service, based on qualifications and other details prescribed by MoEF&CC/ DoPT/ UPSC.
    • It is suggested that the Indian Forest Service may encourage specialisation in various aspects of forestry and wildlife management, among the members of the service, as well as familiarity with all aspects of management of environment.
    • It is suggested that the MoEF&CC undertake a comprehensive review of departmental forest management policies, practices and procedures, to initiate wide-ranging improvements and reforms. This preferably should not be an internal exercise, and should include independent knowledgeable experts from India and abroad, as well as qualified researchers.
    • It is recommended that the MoEF&CC consolidate all existing EIA Notifications/circulars/ instructions into one comprehensive set of instructions. Amendments or additions may normally be done only once a year.
    • It is suggested that the MoEF&CC arrange to revamp the Environment Protection Act, by inducting relevant provisions of the Water Act, 1977 and the Air Act, 1981; the latter two could be repealed, when the revamped EP Act, 1986 comes into force. This exercise may be done keeping in view the provisions of the proposed Environment Management Act.
    • It is suggested to create an Environment Reconstruction Fund for facilitating research, standard setting, education and related matters.
    • In the light of the fact that though overall responsibility vests with the Ministry, State Governments and the local bodies play an effective role in management of the environment, it is suggested that Governments should provide dedicated budgetary support for environmental programmes as a part of each development project in all the sectors.
    • It is suggested that a comprehensive database be created using all instruments available, on an on-going basis, in respect of all parameters relating to environment.
    • It is suggested that environmental mapping of the country is undertaken, using technology as an on-going process.
    • It is suggested that identification & recovery of environmental reconstruction cost relating to each potentially polluting unit be in-built in the appraisal process.
    • It is recommended that the system of empanelment of ‘consultants’ is reworked.
    • It is recommended that a ‘green awareness’ programme is sponsored, including interweaving issues relating to environment in the primary and secondary school curriculum.
    • It is recommended that the MoEF&CC prepare a regional plan for carrying out remediation of polluted sites in consultation with the State Governments and incorporate enabling provisions in the EP Act for financing the remediation task.
    • It is recommended that the Municipal Solid Waste (MSW) management is given requisite attention hitherto. New systems and procedures for handling MSW need to be put in place early for effective management of MSW and with accountability. Cities should set a target of reaching 20% of current levels in 3 years time to work out a mitigation plan.
    • In the light of the fact that vehicle emissions are the major cause of deterioration of air quality in urban areas, it is recommended that a concerted multi-pronged effort is launched to not only to contain it, but to improve the situation in relatively short time.
    • It is recommended that the use of science and technology is encouraged wherever possible and appropriate; approval and enforcement agency should use latest technology to the maximum possible.
    • The MoEF&CC may finalise the CRZ demarcation, and bring it into public domain to pre-empt ambiguity.
    • In view of the key role played by the power sector, as also mining of various minerals in national development, NEMA may have a suitable cell, with specialisation, to speedily deal with environmental approvals in these sectors, with due regard to environmental considerations.
    • It is recommended that all specified type of units employ fully qualified technical personnel to manage their pollution control/ management equipment, and to keep the emission levels within prescribed limits.
    • It is suggested that the MoEF&CC consider reworking standard-setting and revising a system of financial penalties and rewards to proceed to a market-related incentive system, which encourages ‘green projects’.
  3. It is now reported that the government will bring a bill in the budget session of Parliament to amend the five environmental laws – Environment Protection Act, Forest Conservation Act, Water Act, Air Act and Indian Forest Act, to minimize judicial intervention on such issues. Hon’ble Environment Minister (Independent Charge), Mr. Prakash Javadekar, is reported to have said now that the Centre will bring key changes in five green laws in the next session of Parliament. “We should expect a new green regime in 2015”, Minister is reported to have observed, without specifying what would the changes be in the environmental laws.

He aforesaid HAC has felt environmental regulation was driven too much by judicial intervention which was not desirable. It is learned that most of the changes proposed are on the lines of Subramanian Committee recommendations. Also government is going to use satellite for environmental purpose including emissions and monitoring forest areas.

Views are those of the author                    

Author can be contacted at roychowdhury1@gmail.com

Courtesy: Energy News Monitor | Volume XI; Issue 29

INCREASING DIVERSITY IN LNG IMPORT PORTFOLIO

Monthly Gas News Commentary: April 2018

India

The first LNG cargo from Russian energy major Gazprom will land in India in May, following an agreement in January with India’s state-owned gas supplier and developer GAIL (India) Ltd to bring down prices based on a new formula. The contract for a long-term deal mandates that GAIL will purchase about 2.5 mt of LNG from Gazprom per annum. This comes a few weeks after India’s first LNG cargo from the US landed at the Dhabol regasification terminal in Maharashtra. GAIL has already signed a $32 billion deal with the Dominion Energy Cove Point project in Maryland and the Cheniere Energy’s Sabine Pass project in Louisiana for a supply for 20 years. GAIL is in talks with new fertiliser plants for the supply of imported LNG and also trying to market it to anchor customers such as refineries, power plants and petrochemical units near its planned and existing pipelines. GAIL has entered into long-term contracts with global companies to bring LNG from various markets, expecting a rise in demand from the power sector.

GAIL plans to buy 0.5 mt or eight cargoes of LNG from Russia’s Gazprom in 2018/19. GAIL renegotiated the terms of a long-term 2.5 mtpa LNG purchase deal with Russia’s Gazprom in January. This was the third such renegotiation by India with LNG suppliers to make the imported fuel more affordable, using its position as one of the world’s biggest energy consumers to strike better bargains for its companies. India has also renegotiated long-term LNG deals with Qatar’s RasGas and Exxon Mobil Corp as spot prices declined substantially amid a supply glut that turned trading of the seaborne gas into a buyers’ market. The much-delayed Kochi-Mangalore natural gas pipeline, which can open up a substantial latent demand in South India, will be ready by November. GAIL is working on implementing a national gas grid that is aimed at connecting the under-served eastern part of the country to the rest of the nation.

GAIL said it will bring to India only half of the LNG it has contracted from the US as it has either swapped or sold the remaining volumes. GAIL has a deal to buy 3.5 mtpa of LNG for 20 years from Cheniere Energy of the US and has also booked capacity for another 2.3 mt at Dominion Energy’s Cove Point liquefaction plant. The first US cargo arrived at the firm’s Dabhol LNG import terminal in Maharashtra on March 30. Also, the firm’s renegotiated LNG import deal with Russian supplier Gazprom will kick-in from May, with volumes gradually ramping up to fully contracted quantity of 2.5 mt in 5-6 year, GAIL said. GAIL had sold 81-82 mmscmd of gas in 2017-18, which would rise to 91-92 mmscmd because of arrival of US and Russian volumes. The company has swapped half of the 5.8 mtpa of US LNG in a bid to rejig supply portfolio in line with domestic demand. GAIL sold 3.5 mt of the US LNG via time swaps, destination swaps and shipping optimisation.

India and the US decided to set up a joint task force on natural gas with a view to promote strategic and economic interest of the two nations. As a first step in realising the full potential of the Strategic Energy Partnership, the US and India are pleased to announce the US-India Natural Gas Task Force. The task force provides a team of US and Indian industry experts with a mandate to propose, develop, and convey, innovative policy recommendations to the Government of India in support of its vision for natural gas in the economy of India. The work of the task force is expected to advance the strategic and economic interests of both the US and India.

India plans to set up a natural gas trading exchange as early as October this year to prepare for a surge in supply from India’s east coast and a slew of LNG terminals. India currently imports LNG at global rates LNG-AS of around $7.50/mmBtu while the government sets domestic gas prices at $3.06/mmBtu. India plans to increase the share of gas in India’s energy mix to 15 percent by 2030 from below 6.5 percent now. India currently produces close to 90 mmscmd of gas and imports another 70 mmscmd as LNG, according to government figures for 2016-17. In the next three to five years, as natural gas projects from India’s ONGC and a partnership involving BP and RIL ramp up, India’s domestic gas output will be in the range of 140 mmscmd. India’s industrial gas consumers such as power plants and fertiliser makers were disappointed in 2010 after promised gas output from the east coast’s Krishna-Godavari basin fell short of expectations. Many facilities that were built in anticipation of more gas production remain stranded without adequate fuel. The RIL-BP partnership plans to develop three assets off India’s east coast, and ONGC is developing another gas field in the same region.

The PNGRB has sought bids to hire a consultant to help develop a regulatory framework for operationalising the gas trading / exchange hub. Currently, the government fixes the price of the bulk of domestically produced natural gas. The rate, arrived at using price prevalent in gas-surplus nations of US, Canada, UK, and Russia, is $3.06/mmBtu for six month period beginning April 1. In comparison, the cost of imported LNG into India is around $7.5/mmBtu. PNGRB said the oil ministry has asked it to initiate steps for framing of necessary regulatory framework to enable the establishment and operation of a Gas Trading Hub / Exchange. PNGRB would visit USA, UK, and Australia, where the gas trading hub is successfully operating, to decide if there is a need to amend existing regulations. The target for launch of the gas trading hub has been set for October. A hub is used as a central pricing point for a network that could aid better price discovery for domestic as well as imported gas. It isn’t clear if the government would abandon fixing the gas price and allow the rates to be discovered on the hub. India is not only country launching trading hub. China plans to launch a natural gas trading hub in Chongqing this year.

APSEZ said it has entered into a pact with IOC to provide LNG regasification services at its import terminal in Odisha. As per the contract, IOC has booked 3 mtpa regasification capacity spread over 20 years, APSEZ said. IOC plans to supply gas to its refineries in Paradip in Odisha and Haldia in West Bengal. The foundation stone of the project was laid in July 2017 and construction has commenced by infrastructure firm Larsen & Toubro, winning the contract to set up the tankages for gas storage. The terminal is expected to be commissioned during the second half of 2021. APSEZ said the proposed Dhamra LNG import terminal is designed for an initial capacity of 5 mtpa, expandable up to 10 mtpa.

Opportunities are poised to open for private oil and gas producers in CBM extraction. CIL is likely to float global tenders to appoint service providers on this project. Sources in CIL suggested as the Centre had cleared the grey area which previously stalled CBM extraction by the coal behemoth, it will be on the lookout for service providers which can extract the gas from its mines for commercial sale. However, the tender for this selection will depend on the Centre’s policy decision. In 2015, the Centre had approved CIL exploring and exploiting CBM but required it to apply to the petroleum and natural gas ministry. However, the government amended the rule, permitting CIL to explore and harvest CBM without a licence or grant from the petroleum and natural gas ministry.

GAIL said the first phase of the 2,655 km gas pipeline from Jagdishpur in Uttar Pradesh to West Bengal and Odisha will be completed before the scheduled target of December 2018. The company said it has placed pipe-laying order for 530 km between Bokaro in Jharkhand and Angul in Odisha, worth ₹ 7.80 billion. The prestigious 2,655 km long Jagdishpur-Haldia & Bokaro-Dhamra Natural Gas Pipeline project, also known as the ‘Pradhan Mantri Urja Ganga’ project. The project will usher in industrial development in eastern part of India by supplying environmentally clean natural gas to fertilizer and power plant, refineries, steel plants and other industries. It will also provide clean energy to households and transportation in the cities enroute the pipeline. The city gas network laying activity in Varanasi, Bhubaneswar and Cuttack has already commenced. Project activities will start on ground in other cities namely Patna, Ranchi and Jamshedpur by next month, GAIL said. GAIL said the project activities are progressing as per schedule and major contracts for the project have been awarded. GAIL has achieved its annual targeted total capital outlay and has expended around ₹ 40 billion during the fiscal year ending March 2018. The company will be spending its targeted capital outlay of ₹ 64 billion in the current fiscal largely for the 4,000 km of pipeline and city gas projects it is presently executing.

IGL expects its sales volume to industrial and commercial clients rise 20% in 2018-19, after experiencing a similar gain last fiscal year, following a ban on using polluting pet coke and fuel oil in the National Capital Region on rising green concerns. Delhi has been one of the most polluted cities in the world for years now. With smog-filled winter sky becoming an annual feature, the demand for dramatic steps to cut pollution has grown louder with years. IGL plans to use the restrictions on polluting fuel as an opportunity to add as many as 2,000 industrial and commercial customers in 2018-19 to its current base of 3,000. Since most of these clients are likely to be smaller, the sales volume addition is expected to be just 20% over the current volume of 500,000 standard cubic meters a day. IGL is also planning to rapidly expand sales of CNG, used by cars and buses. To tide over the scarcity of land in cities for setting up fuel stations, IGL has begun appointing dealers to set up CNG stations – so far the company owned and operated all its filling stations. Two dealer-owned, dealer-operated CNG stations have been launched while a dozen more are on the way, IGL said. IGL expanded its piped gas connection to households by a record 150,000 in 2017-18. IGL is waiting for permission to take piped gas to homes in Delhi’s cantonment area, which has 30,000 houses of defence personnel and an equal number of civilian homes. For its expansion, IGL is focusing on congested colonies, which had escaped attention earlier but are now being targeted with enhanced security features.

BPCL is planning to hive off its gas business into a separate wholly-owned subsidiary. BPCL, which is present in various segments of natural gas sales and supply, has been strengthening its gas business over the past few years. By hiving off this business as a separate subsidiary, the company intends to sharpen its focus and bring all natural gas-related businesses into one fold. The new unit may be christened Bharat Petroleum Natural Gas Company. BPCL is a co-promoter of Petronet LNG Ltd, along with IOC, ONGC and GAIL. Over the next five years, BPCL has set itself an investment target of ₹ 1 trillion to be spent on all its expansion activities including marketing, refining and strengthening of the gas business. BPCL has been importing LNG and supplying it to customers in the fertilizer, power, city gas distribution, steel and other industries across the country. Its own LNG imports help BPCL mark its presence in the LNG market, apart from being economical for use at its refineries. BPCL also markets LNG by tank trucks from Dahej to some customers such as General Motors, Mahindra & Mahindra Ltd, Modern Insulators Ltd and Tetrapak etc.

PNGRB released new rules on bidding for obtaining a licence to retail CNG and PNG in cities. Under the fresh parameters, future auctions would be conducted by asking companies to quote the number of CNG stations to be set up, while for PNG it would be the number of domestic cooking gas connections to be given in the first eight years of operation. Bidders quoting higher numbers of these would be given more marks. The previous criteria for winning a licence – the tariff charge for transporting CNG and or PNG within the city – has been given just 10 percent weightage under the new regulations. The number of CNG stations and PNG connections to be released command 70 percent of the bidding weightage. Bidders will also be required to quote the length of pipeline they would lay on winning the licence. Entities having experience of at least one year in operation and maintenance of a CGD network and having sufficient technically qualified personnel would be eligible for bidding, as per the terms of the bid. Companies with net worth of no less than ₹ 1.5 billion can bid for cities with population of 5 million and above, while ₹ 1 billion is the minimum requirement for cities with population of 2-5 million. A company with a ₹ 50 million net worth firm is eligible to bid for cities that have less than 1 million population. According to PNGRB, the successful CGD licence bidder would have to enter into a firm natural gas supply agreement with a natural gas producer or marketer in a transparent manner on the arm’s length principle within 180 days of winning a license. The winning company would have eight years of marketing exclusivity in the given city, which is an increase from the current 5-year licences. So far, the petroleum regulator has undertaken eight rounds of bidding. While the last few rounds of CGD have drew lukewarm response, the fourth round was scrapped altogether.

The oil ministry has asked sector regulator PNGRB to look at unbundling of companies like GAIL to resolve the conflict of interest in being both the transporter and marketer of natural gas. The reference to the PNGRB follows a revival of a plan to split GAIL by hiving off gas marketing business into a separate firm, leaving just pipeline transportation with GAIL. Over a period of time more players have come into gas marketing. Gujarat government entity GSPC is a major player in gas marketing and also in gas transportation. The Government had in 2006 issued the Policy for Development of Natural Gas Pipelines and City for Local Natural Gas Distribution Networks which envisaged that in the long run and with the maturing of gas markets, the authorised entities will have transportation of natural gas as their sole business activity and will not have any business interest in the gas marketing or city or local gas distribution networks. GAIL had in the past resisted the split on grounds that its gas marketing and transmission businesses operate at arm’s length, and hence do not need to be separated. GAIL’s marketing business formed 71 percent of its 2016 -17 total sales, and 25 percent pre-tax profit. The government has 54.89 percent stake in GAIL.

Rest of the World

Russian gas giant Gazprom said it has lodged a claim to an international arbitration seeking to cancel its supply and transit contracts with Ukraine. It said talks with Kiev over the contracts had ended without concrete results and it had lodged a claim to a Stockholm arbitration court. The contracts are due to expire at the end of 2019. Gazprom appealed against a previous Stockholm arbitration ruling, which obliged the Kremlin-controlled company to pay Ukraine’s Naftogaz $2.65 billion following a long dispute between the companies over gas delivery. Ukraine is a major transit country for Russian gas supplies to Europe where Gazprom accounts for around 35 percent of the gas market. Gazprom said it would terminate its gas contracts with Ukraine after it lost the court case, escalating a dispute which had left Ukraine struggling to stay warm and which the European Union said could threaten gas flows to Europe.

Russia’s No. 2 oil producer Lukoil has started operations at a $3.4 billion gas processing plant at its Kandym gasfield in Uzbekistan, which is seen as central to its efforts to boost gas production and exports to China. The Russian government said that the gas processing complex, with a capacity of 8 bcm per year, had been launched ahead of schedule. Lukoil has not revealed any data on gas exports to China from Uzbekistan. Lukoil said it has raised a $660 million loan to finance part of the cost of building the gas plant in Uzbekistan. Lukoil is working in the country under a production-sharing agreement that accounts for a quarter of all of Uzbekistan’s gas output. The company plans to double gas production in Uzbekistan to 16 bcm per year by 2020 from 8 bcm in 2017. Lukoil’s total gas output reached almost 33 bcm in 2017.

Russian said it was ready to consider using Ukraine as a gas transit route after 2020. Germany said that a gas pipeline planned to run from Russia to Germany through the Baltic Sea could not go ahead without clarity on Ukraine’s role as a transit route for gas, appearing to harden her stance on the scheme. The Russian energy ministry said that Novak and Sefcovic had spoken by telephone and discussed the delivery of Russian gas to European markets. ExxonMobil Corp expects to restart production from its Papua New Guinea LNG project at the start of May after it was shut following an earthquake in February, ExxonMobil LNG Vice President Emma Cochrane said. The $19 billion LNG facility, opened in 2014 in a remote location in one of Asia’s poorest and most politically troubled countries, has been closed since the powerful 7.5 magnitude earthquake. The project is considered one of the world’s best-performing LNG operations, despite the challenge of drilling for gas and building a plant and pipeline in the remote Papua New Guinea jungle. Australia’s Oil Search and Santos are Exxon’s main partners in the project. The LNG export terminal may not be able to produce at full capacity at first and will likely ramp up gradually, Cochrane said. Cochrane said the company has recertified the reserves in its P’nyang field in Papua New Guinea, and the reserves are higher than it previously thought. Exxon is likely to take a final investment decision this year on expanding its Golden Pass LNG terminal in Texas – a joint venture between Qatar Petroleum, ExxonMobil and ConocoPhillips, Cochrane said.

One of Russia’s European neighbours is fully embracing US LNG. Lithuania, the Baltic state that used to be completely dependent on gas piped in from Russia, is turning to LNG from Norway to the US to help negotiate better prices from its former Soviet ruler. The country of just 2.8 million people is now the biggest European buyer of US LNG after Spain and Portugal. The US has been trying to encourage Europeans to buy more of its gas and vehemently opposes the expansion of a pipeline directly from Russia to Germany that bypasses Ukraine and other eastern European transit nations. Lithuania signed two agreements with the Freeport LNG project in Texas during a meeting with President Donald Trump in Washington earlier this month, deepening its ties with the US and the rivalry with Russian gas.

CNOOC sold cargoes of LNG on a domestic exchange for the first time, the latest step by China to boost supplies of the clean fuel as the nation shifts away from coal. CNOOC sold 60,000 tonnes of LNG for delivery in July at prices between 3,380 yuan ($537.80) to 3,390 yuan per tonne. It sold another 30,000 tonnes for November delivery at between 4,200 yuan and 4,210 yuan per tonne through an auction on the Shanghai Petroleum and Gas Exchange. Buying forward supplies through auctions like the Shanghai Exchange’s would give factories a chance to lock in prices and gas ahead of the winter heating season. More auctions would also help build liquidity on the Shanghai Exchange. CNOOC is likely to hold another auction next month. China is the world’s third-biggest consumer of natural gas. Shanghai launched its electronic platform in 2015 to create a pricing benchmark for China’s burgeoning gas market.

China’s shale gas production will likely reach 17 bcm in 2020, nearly double the 2017 level, as local oil companies make big progress with drilling technology and cost cutting, consultancy Wood Mackenzie said. Nearly 700 new wells will come on-stream between 2018 and 2020 at three key projects – Sinopec’s Fuling, and PetroChina’s Changning-Weiyuan and Zhaotong – all located in the country’s southwest, and at a total cost of $5.5 billion, Woodmac estimated. The forecast 17 bcm of output in 2020 falls short of Beijing’s goal of 30 bcm, which was slashed by more than half from the government’s initial target set in 2012. That means the world’s No.3 gas user will need to keep its imports of LNG at elevated levels. Woodmac has separately forecast China’s LNG imports will increase by a quarter to nearly 49 mt this year, from record highs in 2017. China produced 9 bcm of shale gas last year, or 6 percent of its total gas output. Despite estimates that China is home to the world’s largest recoverable shale gas resource, its shale formations tend to be deeper, more fractured and located in densely populated mountainous terrains, leading to higher costs and complications in drilling. Shell, which pledged billions of dollars of investment in China’s shale sector, pulled out of shale operations in Sichuan several years ago.

China’s Sinopec group, parent of Sinopec Corp, aims to more than double its receiving capacity of LNG over the next six years and lift domestic shale gas production by two thirds by 2020. The plans are part of the state energy firm’s efforts for clean fuel production to account for half of its total energy supply by 2023. Sinopec will have 60 bcm of natural gas supply capacity, which includes both imports and domestic production, by 2023, the group said. It produced 27 bcm of gas in 2017. The group plans to add new receiving facilities for imported LNG along China’s east coast to a total of 26 mt annually by 2023, up from the current 9 mt including the recently launched terminal in Tianjin.

China has cut resources tax on shale gas production by 30 percent from April 1, the finance ministry said, as the world’s largest energy consumer aims to lift domestic gas supplies. Resources tax on shale production was reduced to 4.2 percent from the previous 6 percent, according to the ministry. The new tax rate will be effective for three years, the ministry said.

US natural gas prices could rise in 2018 after utilities pulled the second biggest amount of gas from storage on record over the winter, even though the season was slightly warmer than normal. That left total stockpiles about 20 percent below usual at the end of the heating season on March 31, and will require companies to add 16 percent more gas than usual into storage this summer just to get inventories back to normal levels before next winter. Some analysts think the market is putting too much weight on rising production to refill inventories this year, and is not worried enough about a projected increase in domestic demand and exports. Prices for gas at the Henry Hub benchmark in Louisiana have averaged less than $3/mmBtu since 2015, versus more than $5 over the prior 10 years, and are expected to remain below $3 through at least 2024 based on current futures trading on the New York Mercantile Exchange. US dry gas production is projected to rise to an all-time high of 2.3 bcm per day in 2018, but US consumption is also expected to hit an all-time high of 2.2 bcm per day in 2018. With exports rising to record highs as well, it does not leave a lot of extra gas to go into storage.

Shell and Inpex are on the final stretch of a years-long race to export gas from offshore northern Australia, where both have spent billions of dollars building the world’s biggest maritime vessels to grab a slice of Asia’s booming LNG market. Anglo-Dutch energy major Royal Dutch Shell and Inpex, Japan’s biggest oil and gas producer, are vying for first gas from two overlapping fields after delays and cost overruns that have plagued both projects. Inpex has the 340 meter-long Ichthys Explorer, a floating LNG production and storage unit, built in South Korea, in parallel with Shell’s Prelude.

Japan’s Inpex Corp and its partners have bought a cargo of LNG to cool their Ichthys LNG plant in Australia ahead of a potential start-up of the much delayed facility. To produce LNG, natural gas is cooled down to around minus 160 degrees Celsius, so facilities must be chilled before production can begin, typically by using fuel from other sites. Taking such a step indicates the plant, in northern Australia’s Darwin, is getting closer to starting output. The LNG tanker ‘Pacific Breeze’ is currently in the Java Sea and expected to reach Darwin on April 26, with a draft of 93 percent, suggesting it is almost full. The ship has the capacity to carry up to 182,000 cubic metres of LNG, according to Inpex. Inpex said the vessel had been chartered to transport LNG bought from another LNG project with the objective of cooling the onshore Ichthys LNG plant ahead of the project’s start-up. Inpex said the vessel’s LNG could also possibly be used as a first export cargo should Ichthys experience further delays in production, but stressed this had not yet been decided. Inpex said in March it had postponed its latest planned start-up to April or May. The start was originally slated for 2016. Exports from new LNG projects including Ichthys are expected to help Australia overtake Qatar to become the world’s largest exporter of the super-chilled fuel by 2019.

Japan’s biggest city gas seller Tokyo Gas Co expects that contracts for LNG cargoes with destination flexibility will spread from the West and Japan to be a common thing worldwide, Tokyo Gas President Takashi Uchida said. Japan’s Fair Trade Commission last June ruled that destination restrictions that prevent the reselling of contracted LNG cargoes breach competition rules. The decision is set to shake up the Asian market for the fuel in the same way as in Europe. LNG exports from the US are also free from destination restrictions. In Japan, only Shizuoka Gas has the capability to re-export fuel by re-loading LNG onto ships. Tokyo Gas and JERA, the world’s top LNG buyer, separately renewed their expiring contracts for the fuel from Malaysia, after decades of jointly procuring gas from the country, due to a difference in procurement strategy, Uchida said. Thanks to the buyer’s market, Tokyo Gas, Japan’s second-biggest buyer of LNG, renewed long-term contract for LNG from Malaysia with destination flexibility “at good terms” last month, he said. Tokyo Gas would increase its ratio of short-term and spot LNG cargoes to long-term contracts out of a total of about 14 million tonnes it buys annually. However, the company would not make a drastic cut in long-term LNG volumes of 50 percent by 2030 as that would be too risky, he said. Tokyo Gas is expected to take the first delivery of LNG from the Cove Point project in the US. state of Maryland some time in April to June. The company has a contract to buy 1.4 mtpa of LNG for 20 years from Cove Point, its first procurement of US shale gas. The company has been arranging with Centrica to exchange a part of its Cove Point offtake with LNG that the British firm procures in Asia Pacific markets, under a location swap deal, to cut transportation costs, but the exact volumes have not been fixed, Uchida said.

The long-delayed Browse gas project off Western Australia has gained key support, with partners in the North West Shelf LNG plant aiming to agree on a tariff by end-June to handle Browse gas, Woodside Petroleum said. Browse is seen as a key source of growth for Woodside but has been stuck on the drawing board for years as plans for onshore and floating LNG development estimated at $30 billion to $45 billion were scrapped. The plan now is to develop the giant gas field to feed the North West Shelf plant, Australia’s biggest LNG plant, when its current gas source runs dry in the 2020s. Just two years ago, the market had been expected to remain in oversupply until around 2023, but that has changed following a sharp jump in gas demand in China.

Chevron Corp will proceed with the second stage of its giant Gorgon LNG export plant off the northwest coast of Western Australia, the company said. Chevron and its joint venture partners plan to sink 11 new wells in the Gorgon and Jansz-Io fields and build offshore pipelines and subsea structures to pipe the gas to the nearby 15.6 mtpa LNG plant on Barrow Island. The $54 billion Gorgon project came on stream in March 2016 but suffered numerous unplanned shutdowns in its early stages. Gorgon Stage Two is part of the original Gorgon development plan which includes the expansion of the subsea gas network required to maintain long-term natural gas supply to Barrow Island. Chevron leads the development of the Wheatstone natural gas project, manages a one-sixth interest in the North West Shelf Venture and operates Australia’s largest onshore oilfield on Barrow Island.

BP plc announced that, together with its partner Oman Oil Company Exploration & Production, it has approved the development of Ghazeer, the second phase of the giant Khazzan gas field in Oman. The final investment decision for Ghazeer follows the successful start-up of Khazzan’s first phase of development in September 2017. This project, which started production ahead of schedule and under budget, is now producing at design capacity of around 1 billion cubic feet of gas per day and around 35,000 barrels per day of condensate, BP revealed. Ghazeer is expected to come onstream in 2021 and deliver an additional 28.3 million cubic meters of gas and over 15,000 barrels of condensate per day.

Finland has approved the construction of the Nord Stream 2 gas pipeline through Finland’s economic zone, the Finnish government and Russian gas exporter Gazprom said. The pipeline between Russia and Germany, which would run for around 375 km across Finland’s economic zone through the Baltic Sea, still requires a construction permit from local Finnish authorities. Nord Stream 2, planned to run from Russia across the bed of the Baltic Sea to Germany, would double the existing Nord Stream pipeline’s current annual capacity of 55 bcm. Eastern European and Baltic states fear the pipeline could 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. Germany has approved the pipeline and the project is currently collecting permits from Russia, Sweden and Denmark.

South Korea expects its natural gas demand to rise to over 40 mt in 2031, driven by higher household and industrial consumption of the fuel, the energy ministry said. The world’s third-largest LNG importer had previously forecast natural gas demand falling to 34.65 mt of LNG equivalent in 2029 from 36.49 mt in 2014 due to lower power generation demand. The increased demand forecast of 40.49 mt of LNG in 2031 from estimated 36.46 mt in 2018 comes as South Korea shifts away from coal and nuclear fuel. Reflecting the country’s growing gas demand over the next 13 years, South Korea also plans to spend about 5.8 trillion Korean won ($5.48 billion) by 2031 on expanding its gas supply infrastructure including storage tanks and pipelines. Household and industrial consumption of LNG is expected to grow by 1.24 percent annually to 23.40 mt in 2031 from 19.94 mt in 2018. For power generation, it is expected to increase to 17.09 mt of LNG in 2031 from 16.52 mt in 2018. To ensure gas supply security, South Korea also seeks to diversify gas supplies and have more flexible LNG contracts that do not include restrictive destination clauses or take-or-pay terms. Most of the long-term LNG contracts include the destination clauses that prevent buyers from reselling excess cargoes to other markets, and Asian LNG buyers have been vocal about the removal of the restrictive clauses. South Korea imports most of its LNG through the country’s sole LNG wholesaler Korea Gas Corp. Last year, South Korea imported 37.55 mt of LNG, mainly from Qatar and Australia.

LNG: liquefied natural gas, mt: million tonnes, US: United States, mtpa: million tonnes per annum, mmscmd: million metric standard cubic meter per day, mmBtu: million metric British thermal units, RIL: Reliance Industries Ltd, PNGRB: Petroleum and Natural Gas Regulatory Board, UK: United Kingdom, APSEZ: Adani Ports and Special Economic Zone, IOC: Indian Oil Corp, CBM: coal-bed methane, CIL: Coal India Ltd, km: kilometre, IGL: Indraprastha Gas Ltd, CNG: compressed natural gas, BPCL: Bharat Petroleum Corp Ltd, ONGC: Oil and Natural Gas Corp, PNG: piped natural gas, CGD: city gas distribution, GSPC: Gujarat State Petroleum Corp, bcm: billion cubic meters, CNOOC: China National Offshore Oil Corp

Courtesy: Energy News Monitor | Volume XIV; Issue 47

2015: It will be different for energy

Lydia Powell, Observer Research Foundation

2015 is likely to be very different for energy. What exactly will be different and for whom is difficult to articulate precisely. But there is a big clue in the price of oil and its impact on global economies. If the collapse of oil prices is the straightforward consequence of the geo-political game between OPEC and the United States then oil prices are likely to return to their upward trend. In this case the usual lament over high oil prices, growing subsidies and widening fiscal deficit could be expected in India. However if the fall in oil prices is the result of a more fundamental change in global economy, then the consequences would not be straightforward for India.

There is a belief that the collapse in oil prices is bad news for oil revenue dependent oil exporting countries but good news for oil importing countries such as India. In the very short term this is true. Low oil prices have enabled India to reduce subsidies on petroleum products. Low oil prices have also contributed to keeping inflation under control.  But in the longer term the benefits of low oil prices are unlikely to be positive. To begin with, the benefits of low oil prices to consumers are likely to be less than the adverse impact of high oil prices. When oil prices rose in 2014, businesses added surcharges to their prices almost overnight.  They are yet to pass on the benefits of low oil prices by way of discounts and rebates.  Business will keep profits to themselves as long as it is possible to do so. For its part, the Government has already claimed a share of the benefits by increasing its tax take from petroleum products.

It is likely that businesses and the Government are not passing on the benefits of low oil prices to consumers because they know that these prices are unsustainable in the longer term. They are probably aware that the fundamentals of oil extraction have not changed. Low oil prices are definitely not the result of the return to the era cheap easy to extract oil. Oil available now is expensive and it is difficult to extract. If so, then why are current oil prices not reflecting this reality?

No one knows the answer yet but according to some observers it is because the World is beginning to see the limits to growth. For a very long time the price of commodities including oil has been close to the cost of production, at least for the marginal producer. Now the price of commodities is close to what consumers can afford. This is not necessarily a good thing. As long as oil prices remain low, much of this difficult to extract oil will be left in the ground. This development is not what one would have expected going by the general expectations for the future of energy. It was generally believed that once half the World’s oil is extracted, the remaining oil would be extracted much more slowly and at greater cost because of geological reasons. The higher cost of oil extraction would lead to development of substitutes. People would demand less oil because substitutes are available at lower cost. This would have been a happy situation because demand for oil would have run out before oil ran out.

This is not what is happening now. People are demanding less oil not because substitutes are available but because their wages have not increased sufficiently to purchase more oil (or other forms of energy).  High cost oil producers such as tight oil producers in the United States are not drilling as much as they used to before the crash in oil prices despite claims to the contrary. Reuters news indicates that new permits for drilling in the USA fell by 40% in November 2014. Transocean, the owner of the world’s largest fleet of deep sea drilling rigs is reported to have taken a charge of over $ 2 billion on account of a drilling rig glut. As drilling rates fall, cash flow will slow down for shale and tight oil drillers. This in turn will lead to debt default. The consequences of these debt defaults could be transmitted to the rest of the world through the interconnected banking system.  Faltering debt could be a sign of the difficulty in the World’s ability to borrow from the future. If the World cannot borrow from the future, it can only mean that the World economy is beginning to shrink rather than grow. India cannot claim to be an exception to this trend and no macho leader can do anything about it.

Views are those of the author                    

Author can be contacted at lydia@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 29

OIL PRICE INCREASE

Monthly Oil News Commentary: March – April 2018

India

India’s oil import bill is likely to jump by a quarter to $87.7 billion in the current fiscal year which ends this weekend as international oil prices have surged. India had imported 213.93 mt of crude oil 2016-17 for $70.196 billion or ₹ 4.7 trillion. For 2017-18, the imports are pegged at 219.15 mt for $87.725 billion (₹ 5.65 trillion), according to the latest data available from oil ministry’s PPAC. India relies more than 80 percent on imports to meet its oil needs. During first 11 months of current fiscal (April 2017 to February 2018), the country imported 195.7 mt crude oil for $63.5 billion. The basket of crude oil that India imports averaged $55.74 per barrel in the April-February period as compared to $47.56 a barrel in 2016-17 and 46.17 in 2015-16. Every dollar per barrel change in crude oil prices impacts the import bill by ₹ 8.23 billion ($0.13 billion).

India is aiming to drive harder bargains with global oil producers, including Saudi Arabia, during bilateral meetings at a conference of energy ministers, leveraging its strength as the world’s third-biggest crude importer. Key producers from the OPEC threatened by the rising output from new and non-OPEC countries, are trying to secure a foothold in India where refining capacity is set to surge to 8 million bpd by 2030 from 5 million bpd. Iran has offered to increase a discount on freight prices to Indian state refiners to double its sales to the companies, which control about one-third of India’s refining capacity. Saudi Aramco raised the credit limit for some Indian refiners last year so that they could lift more crude without providing explicit financial guarantees. India’s footprint in global energy markets will increase “materially” from 2018 to 2040, making it the largest growth market for global energy, BP Plc said in its energy outlook report in February. India last year began buying oil from the US to cut its dependence on the Middle East, whose share of overall imports fell to 64.1 percent in the fiscal year of 2016/17 from about 80 percent in the 2007/08 fiscal year, government data showed. India and China, the traditional rivals, plan to jointly leverage their buying power to influence the crude oil pricing. China and India are world’s second- and third-largest oil consumers and heavily dependent on import. India has been raising its voice against the Asian premium, a practice under which Asian refiners pay a higher price for oil than their Western counterparts. This is not the first time that India and China have spoken about leveraging their purchasing power to influence crude prices but previous efforts frittered due to uneasy relations India and China share and the keen competition they experience in business.

India produced 32,642 mt crude oil in the eleven months between April 2017 and March 2018, a marginal 1 percent decline as compared to the output in the same period last fiscal (April-February 2016-17), and a record seven year low, according to the PPAC data. In February 2018, oil production dipped 2.36 percent to 2,731 tmt. The dismal performance is attributed to lower than expected output from key wells operated by state-run ONGC, OIL and fields operated by private companies. The lower output dampens the prospect of achieving the government’s target of 10 percent reduction in energy import dependence by 2022. India records lowest crude oil production in seven years PPAC data showed February’s oil production dipped due to poor performance of fields under ONGC and under PSCs.

The foreign acquisition unit of India’s ONGC has filed an arbitration claim against the government of Sudan in a London court, the company said, seeking to recover dues pending for years from a project hit by the breakaway of South Sudan in 2011. ONGC had filed a claim for $98.94 million, in what they said was a first for the South Asian nation’s top oil and gas explorer against any government. At the centre of the dispute is ONGC’s 25 percent stake the company acquired in the GNOP in Sudan in 2003. Other stakeholders include China’s China National Petroleum Corp with a 40 percent stake and Malaysia’s Petronas with a 30 percent share. The current arbitration is only for a part of pending dues that add up to about $425 million. ONGC has sued the government as the contracts were backed by sovereign guarantees. OVL’s stake in the GNOP comprised Blocks 1, 2 and 4, and the firm also agreed to build a 1,500 kilometre pipeline to Port Sudan on the Red Sea. But in 2011 South Sudan broke away from Sudan, after decades of civil war, and took control of blocks 1A, 1B and a part of block 4. Meanwhile, because of years of trade sanctions imposed on Sudan by the US – only lifted in 2017 – Khartoum found it difficult to secure oil for its refineries, and asked foreign companies including OVL to sell their share of oil from the blocks to the African nation. In 2016, OVL signed a separate agreement with Sudan for the sale of its share of GNOP oil. Sudan has not yet paid $90.81 million to ONGC for purchases of oil in 2016 and 2017. OVL had expected Sudan to clear the dues after lifting of the US sanctions last year.

Demand for diesel in India is set to hit a record in 2018 as the government targets massive infrastructure spending in the fiscal year that starts April 1. Diesel consumption growth in calendar 2018 may be more than double last year, analysts and traders said, aided by an expected regular monsoon this year that should boost demand in the world’s third-largest oil consumer for diesel used in harvesting and other farming, leading to higher rural spending. India’s average monthly diesel consumption was about 6.6 mt or about 1.6 million bpd, in 2017. That was up about 3.1 percent from 2016, when average monthly consumption was 6.4 mt. Meanwhile India’s diesel exports in February were up 32 percent to 2.31 mt year-on-year.

Over 400,000 poor families in Tripura will be provided free cooking gas or LPG connections under the PMUY to ensure clean energy access to all and to protect the health of rural women, IOC said. 2 million LPG connections would be given to Telangana households by next year under the PMUY. LPG distribution points in the state would be increased to 1000 from the existing 707 for quicker and efficient delivery system of gas cylinders. The overwhelming response to the PMUY initiative coupled with its efficient implementation and monitoring made the centre revise the initial target of releasing five billion connections to eight billion by 2020. 90 million new LPG connections have been distributed in the last four years, including 3.5 billion connections provided under the PMUY. Launched in May 2016, under the scheme government provides LPG connections to BPL families with a support of ₹ 1,600 per connection.

Ahead of polls, government-owned companies decided to defer recovery of loans that free-LPG connection beneficiaries had taken for buying cooking gas refills. Over 36 million poor women have been given free LPG connections since June 2015. While the ₹ 1,600 cost of LPG connection is borne by the government, the cost of buying LPG stove and refill (gas cylinder) was to be borne by the beneficiaries. To help poor, oil firms provided interest-free loan to fund the cost of LPG stove and refill to beneficiaries. IOC said about 70 percent of the PMUY customers availed interest free loan facility provided by OMCs towards financing LPG stove and/or first LPG cost. To recover the loan, the oil companies were pocketing the subsidy government gives to all LPG consumers. Giving details of the deferment of loan recovery, IOC said the scheme shall be applicable for all the existing PMUY LPG connections who have taken loan for stove and/ or first LPG cost from OMCs. All PMUY customers who have outstanding loan as on March 31, 2018 will have a deferred recovery of the outstanding amount up to 6 LPG refills. The government raised the target of providing free cooking gas connection to poor women households to 80 million from previously stated 50 million.

India is the world’s second largest importer of LPG after China and remains ahead of Japan as the drive to provide clean cooking fuel to millions of poor families boosted household demand by nearly 8% in 2017-18. India beat Japan in 2016 to become the world’s third-largest consumer of crude oil after the US and China. Both IEA and OPEC see India as the main driver of growth in global oil demand for the next decade. Available data indicate India’s imports of LPG – a byproduct of refining industry – in 2017-18 surpassing 11 million tonne in 2016-17 on the back of the Ujjwala scheme adding volume to overall demand.

Almost six months after a massive fire broke out at an LPG bottling plant of HPCL at Cherlapally in Hyderabad, the government’s decision to give a go-ahead for night shifts at such plants has raised safety concerns in the industry. This decision came after LPG demand increased considerably on the back of government schemes such as the PMUY over the past two years. LPG consumption in India increased 10 percent from 19.62 mt in 2015-16 to 21.54 mt in 2016-17. It is expected to touch 23.5 mt in 2017-18. The higher number of hours has helped bring down waiting time for a refill. It was as high as 15 days earlier in the Northeast and in Kerala but has come down to four or five days.

HPCL received the environment clearance for setting up of a new LPG plant with bottling and storage facilities in East Champaran, Bihar that will entail an investment of ₹ 1.364 billion. This will be the third LPG plant in the state. Currently, HPCL has only two LPG plants in Bihar at Patna and Purnia with a bottling capacity of 50,000 cylinders per day. As per the proposal, the HPCL wants to construct mounded storage vessels with a capacity of 1,050 tonnes and bottling capacity of 120 tonnes per annum in an area of 30 acres in Panapur and Kubeya villages in East Champaran district. The purpose of the project is to increase rural penetration of bottled LPG cylinders in Bihar in a safe and environmental-friendly way. At present, the HPCL is meeting the demand through sharing filling capacity from other LPG bottling plants/private bottlers. The government’s aim is to increase the LPG penetration to 75 percent by addition of 55 million new LPG connections till 2019-20.

Prices of non-subsidised LPG have been reduced by ₹ 35.50 per cylinder, and that of the subsidised one by a marginal ₹ 1.74, according to OMCs, even as public sector Indraprastha Gas Ltd hiked the rates for piped and CNG supply to cities in the national capital region. As per the revised rates announced by IOC that are effective from April 1, a 14.2 kg non-subsidised cooking gas cylinder now costs ₹ 653.50 in Delhi, as compared to ₹ 689. Similarly, the non-subsidised LPG cylinder now costs ₹ 676 in Kolkata, ₹ 625 in Mumbai and 663.50 in Chennai. The price of the subsidised cylinder, which a consumer has a quota of 12 per year, was also cut marginally by ₹ 1.74. The 14.2 kg cylinder now costs ₹ 491.35 in Delhi as against ₹ 493 earlier. OMCs revise LPG and ATF, or jet fuel, prices on the first of every month. Jet fuel prices have been cut by ₹ 231 in Delhi and now sells at ₹ 61,450 per kilolitre. Prices vary with airports depending on local taxes. Jet fuel per kilolitre now costs ₹ 65,985 in Kolkata, ₹ 61,025 in Mumbai and ₹ 61,615 in Chennai.

An inclusion of petrol and diesel in the GST framework will help consumers pay a rational price for the fuel, according to the federal government. Following a rapid rise in the international rates to which local prices are linked, diesel is selling at record rates in the country and petrol at four-year peak. Diesel was sold for ₹ 64.69 per litre and petrol for ₹ 73.83 a litre at IOC outlets in Delhi. Petrol and diesel prices have gained ₹ 10.74 and ₹ 11.36 per litre respectively in the last nine months in which crude oil has gained $21.87 per barrel to about $70/barrel. Heavy duties imposed by the Centre and states is key to petrol and diesel being so expensive in the country. In Delhi, petrol bear about 100% and diesel 69% levies comprising excise duty and VAT according to the oil ministry’s PPAC data. The highest rate of tax applicable to products under GST is 28%. Since fuel sale is a major source of revenue for states as well as Centre, it’s difficult to imagine them agreeing to cut rates sharply on petrol and diesel. Petrol, diesel, natural gas, crude oil and jet fuel are currently not included in GST. Experts observed that the federal government support to inclusion of petroleum products under GST is aimed at eliminating state role in influencing retail price of petroleum products and also eliminate a large source of revenue for them.

India has proposed to build a pipeline from Myanmar’s east coast to deliver oil products, mainly diesel, to Myanmar. A working group has been formed by Myanmar and India to look at issues such as security, land and oil storage, and how to price the fuel and the oil’s specification. Myanmar currently imports about 100,000 bpd of diesel and gasoline mainly from Singapore, and produces only 12,000 bpd of oil locally. The country has invited investors to build refineries but high land cost is one of the main issues to overcome. The country has also held its first round of talks with China and Bangladesh to discuss building an electricity transmission grid across borders to ease power shortages.

Indian state refiners plan to almost double oil imports from Iran in 2018/19, drawn by incentives offered by Tehran, potentially helping Iran increase its share in the world’s third-biggest oil importer. Iran is pushing to retain its oil customers in Asia, offering better terms than other Middle Eastern suppliers including Saudi Arabia, even as the threat looms of potential further US sanctions on the OPEC member. Tehran recently deepened freight discount to firms in India, its second-biggest oil client after China, in return for higher volumes. In the current fiscal year to March 2019, state refiners IOC, MRPL, BPCL and HPCL plan to import 396,000 bpd Iranian oil. All four refiners imported about 205,600 bpd Iranian oil in the previous fiscal year. Iran, which used to be the second-biggest oil supplier to India before sanctions, has been gradually growing back its market share in New Delhi since the lifting of sanctions against the Islamic state in 2016, becoming the No. 3 supplier to India in 2016/17 after Saudi Arabia and Iraq, government data shows. State refiners, which account for two-thirds of India’s 5 million bpd refining capacity, last year curbed imports from Iran in protest at Tehran’s move to grant development rights for the giant Farzad B gas field to others.

IOC the nation’s largest fuel retailer, announced it has acquired Royal Dutch Shell’s entire 17 percent stake in Makhaizna oilfield in Oman for $329 million. The equity of IOC in the oilfield will feed Indian refineries with an additional 1 mt of crude oil. The Mukhaizna oilfield is the single-largest producing oilfield in Oman contributing around 13 percent of the total Omani crude oil production of 120,000 barrels per day. IOCL Singapore Pte Ltd, a wholly-owned subsidiary of IOC has made the acquisition with 1 January 2017 as the effective date of transaction.

IOC said it plans to invest about ₹ 1.43 trillion to nearly double its oil refining capacity to 150 mt and boost petrochemical production by 2030. The company currently owns and operates 11 out of the country’s 23 refineries. Its refineries have a total capacity of 80.7 mtpa. IOC is investing ₹ 166.28 billion in upgrading its refineries to produce Euro-VI emission norm compliant petrol and diesel as against Euro-IV fuel being produced now. This investment cycle would be completed by 2020, the company said. Besides, the company is investing ₹ 156 billion in expansion of petrochemical projects and another ₹ 746 billion in raising the capacity of its existing refineries. The company said another ₹ 365 billion worth of projects are in pipeline but haven’t been approved by the company board as yet. India’s current refining capacity of 247.6 mtpa exceeds consumption but with demand growing at a compounded annual growth rate of 3.5-4%, it will need to add more capacity to meet the rising fuel needs. IOC plans to raise the capacity of its Panipat refinery in Haryana to 25 mtpa from current 15 mtpa, while Koyali refinery in Gujarat would be expanded to 18 mtpa from 13.7 mtpa. While 3 mt will be added in IOC’s Barauni refinery in Bihar, a 1.2-mtpa capacity addition is planned for Uttar Pradesh’s Mathura refinery to take its capacity to 9.2 mtpa. IOC is also looking at adding a 9 mtpa capacity to its subsidiary Chennai Petroleum Corp Ltd. India is targeting blending of up to 10 percent ethanol in petrol to cut reliance on imports to meet oil needs.

The Supreme Court asked the Centre to look into the possibility of rolling out the BS-VI fuel in 13 metro cities by April 2019, besides introducing it in the national capital from the beginning of the next month. The Centre had earlier informed the top court it had advanced by two years the deadline for supply of the Euro-VI petrol and diesel and would start it in Delhi from April 1, considering the “serious pollution levels” in the national capital and adjoining areas. On February 21, the Centre had informed the apex court that it will introduce Euro-VI fuel in Delhi by April 1. The top court had earlier directed the Centre to clear its stand on the availability of Bharat Stage (BS)-VI emission standard compliant fuel in Delhi.

Rest of the World

Global oil supply remains a concern amid OPEC and Russian-led output reductions, with production falling from mature oilfields while demand growth remains strong, the International Energy Agency (IEA)’s Executive Director Fatih Birol said. This was despite forecasts of rising oil output from non-OPEC producers, led by the US, which is expected to be able to meet two-third of global oil demand growth over the next five years, he said. First, global oil consumption is still growing strongly, gaining 1.5 million bpd this year, driven by petrochemical, industrial and aviation demand, he said. Second, some older, maturing fields are in decline. Investments in oil and gas exploration remain low, Birol also said, even though global oil prices have returned to 2014 levels. While efforts by the OPEC and Russia to cut output has helped drain excess global supplies, the industry remains wary that growing US shale oil production could cap price gains. Another big worry was the halving of Venezuelan oil production since former President Hugo Chavez took office in 1999, Birol said.

OPEC and its allies look set to keep their deal on cutting oil supplies for the rest of 2018, although some producers are starting to worry that high prices may be giving too much stimulus to rival output. OPEC, Russia and several other non-OPEC producers have curbed output since January 2017 to erase a global glut of crude that had built up since 2014. They have extended the pact until the end of 2018, and meet on June 22 to review policy. The deal has boosted oil prices LCOc1, which topped $71 a barrel this year for the first time since 2014. They were close to $70. But it has also encouraged a flood of US shale oil, fuelling a debate about how effective the curbs are.

OPEC members will need to continue coordinating with Russia and other non-OPEC oil-producing countries on supply curbs in 2019 to reduce global oil inventories to desired levels, Saudi Arabian said. OPEC and non-OPEC countries struck a production supply agreement in January 2017 to remove 1.8 million bpd from global markets and end a supply glut. The cuts helped lift oil prices to current levels of around $65 per barrel. The oil producers will convene in June in Vienna to discuss further cooperation. It was unclear what oil supplies would need to be in 2019. OPEC would do better to leave the oil market slightly short of supplies rather than ending too early the output cut deal. Saudi Arabia and Russia have spearheaded efforts to reduce global oil stockpiles to their five-year average, ending years of oversupply sparked by the rapid rise in production from shale oil producers in the United States.

China is taking its first steps towards paying for imported crude oil in yuan instead of the US dollar, a key development in Beijing’s efforts to establish its currency internationally. Shifting just part of global oil trade into the yuan is potentially huge. Oil is the world’s most traded commodity, with an annual trade value of around $14 trillion, roughly equivalent to China’s gross domestic product last year. A pilot program for yuan payment could be launched as early as the second half of this year. Regulators have informally asked a handful of financial institutions to prepare for pricing China’s crude imports in the yuan. China is the world’s second-largest oil consumer and in 2017 overtook the US as the biggest importer of crude oil. Its demand is a key determinant of global oil prices. Under the plan being discussed, Beijing could possibly start with purchases from Russia and Angola, one of the people said, although the source had no details of anything in the works. Both Russia and Angola, like China, are keen to break the dollar’s global dominance. They are also two of the top suppliers of crude oil to China, along with Saudi Arabia.

China’s launch of its crude futures exchange will improve the clout of the yuan in financial markets and could threaten the international primacy of the dollar, argues a new from UBS Asset Management. Already, Unipec, the trading arm of Asia’s largest refiner Sinopec, has inked a deal with a western oil major to buy Middle East crude priced against the newly-launched Shanghai crude futures contract. This helps cement the exchange’s viability and challenges the petro-dollar system, in which oil deals are executed in dollars. This would decrease demand for the greenback and boost US inflation. China surpassed the US in 2017 to become the world’s largest oil importer. Nevertheless, the existing price benchmarks – Brent and WTI crude – are both in dollars, and importers across the world must buy dollars in order to conduct oil deals. But the move to trade oil in yuan will diminish the role of the greenback in global financial markets, argues Briscoe. Pricing oil in renminbi and launching a trading hub will raise China’s prominence and integrate it further in global markets.

Shanghai crude oil futures fell further and were at parity with the US market, as state oil majors and local traders piled on more bearish bets amid concerns about domestic refinery demand. The latest drop takes the fall since the contract’s launch to 10 percent, underperforming the dominant western benchmarks and raising questions that refiners in the world’s top crude importer were pushing to bring down import costs. For a second day, trading volumes were skewed to the overnight session, with more than 50,000 lots, equal to 25 million barrels of oil. Another factor that could limit demand from the teapots for the Shanghai contract is that the teapots still need to apply for crude import quotas for the second half of the year, China-based traders said. Furthermore, selling pressure from China’s large state-owned oil companies, who are the primary crude buyers for the country, could explain the recent decline in prices.

US shale oil production is expected to increase in May for the fourth consecutive month, US EIA data showed, boosted by record production in the prolific Permian Basin of West Texas and New Mexico. Total oil output is set to rise by 125,000 bpd to 7 million bpd, the EIA said. Production in the Permian Basin is expected to jump by 73,000 bpd to 3.2 million bpd, the largest according to records dating back to 2007. The expanding production there has led to bottlenecks as pipelines transporting the crude have filled more quickly than expected. Bakken output is expected to rise by 15,000 bpd to 1.2 million bpd, the highest since July 2015. In the Eagle Ford shale fields, production is set to rise by 24,000 bpd to 1.3 million bpd, the most since May 2016.

Russia’s oil output edged up in March to an 11-month high of 10.97 million bpd slightly above a limit agreed under a global supply pact, the energy ministry data showed. It was the first increase in Russian output since December and the highest level since output of 11 million bpd in April 2017. Under an agreement by members of the OPEC and other producers that came into effect last year, Moscow pledged to cut output by 300,000 bpd from a baseline of 11.247 million bpd based on its output in October 2016. The energy ministry said that in March it cut output by around 280,220 bpd from the October 2016 level. Russian output in March rose from 10.95 million bpd in February. Russian oil pipeline exports in March stood at 4.163 million bpd, slightly up from 4.162 million bpd in February. The current global supply deal lasts until the end of 2018. According to the energy ministry data, Russia’s largest oil company Rosneft and No.2 producer Lukoil both increased their output by 0.1 percent last month from February.

Fourteen companies have expressed interest in oil and natural gas exploration and development contracts to be auctioned by Iraq on April 25, the oil ministry in Baghdad said. The 14 have bought a package containing the bidding documents and terms of the contracts for the 11 exploration blocks to be auctioned, it said. The blocks, located in border areas with Iran and Kuwait, and in offshore Gulf waters, were to be auctioned in June. That date was brought forward to April 15 and then postponed to April 25 to give bidders more time. The oil ministry announced measures to reduce the fees paid to oil companies in the contracts to be auctioned. The new contracts will exclude oil by-products from the companies’ revenue, establish a link between prevailing oil prices and their remuneration, and introduce a royalty element. Oil companies operating in Iraq currently receive a fee from the government linked to production increases, which include crude and oil by-products such as liquefied petroleum gas. The new contracts offered by Baghdad will also set a time limit for companies to end gas flaring from oilfields they develop. Iraq continues to flare some of the gas extracted alongside crude oil at its fields because it lacks the facilities to process it into fuel. Iraq hopes to end gas flaring by 2021. Flaring costs the government nearly $2.5 billion in lost revenue each year and could meet most of its unmet needs for gas‐fired power, according to the World Bank.

Asian oil traders are stumped by how Saudi Arabia derived its OSP for May after the world’s top oil exporter unexpectedly raised the price for its flagship Arab Light crude sold to Asian refiners. State oil giant Saudi Aramco deviated from its usual pricing formula by increasing Arab Light’s official selling price for May by 10 cents per barrel to a premium of $1.20 a barrel to the average of Oman and Dubai quotes. Market participants were expecting a cut of between 50 cents to 60 cents a barrel in a survey. Some predictability in how producers set their prices allow refiners to plan their purchases. Saudi Aramco typically sets the Arab Light crude price each month based on the price curve between the first-month and third-month cash Dubai prices published by S&P Global Platts.

Iraq is studying the possibility of building crude oil storage facilities in South Korea and Japan as part of a plan to increase sales to Asian clients, Iraqi state-oil marketer SOMO said. SOMO received offers from Exxon Mobil, Total, Japan’s Sumitomo and China’s Unipec, to take part in marketing Iraqi crude, he said. Iraq plans to stop loading crude from its southern port of Basra for three to four days in early April due to maintenance. Iraq has 10 million barrels in oil storage capacity in the southern region, he said. Iraq’s crude output should not exceed 4.360 million barrels per day in compliance with a deal between oil exporting nations to curb supply in order to lift prices. March oil exports won’t exceed 3.426 million bpd. Russia kept its spot as the largest crude oil supplier to China in February, data showed, a role it held in January and for the past two years on an annual basis. Russia supplied 5.052 mt or 1.32 million bpd last month, up 17.8 percent from a year earlier, data from the Chinese General Administration of Customs showed. Saudi Arabia regained its No. 2 ranking after losing out to Angola in January, with February supplies coming in at 4.635 mt or 1.21 million bpd, down 2.9 percent on year but up from 1.01 million bpd in January. The hefty Russian shipments, which gained 21 percent for the January-February period over a year earlier, came after a second East Siberia-Pacific Ocean pipeline started commercial operation in January, along with expanded domestic connections in China.

ONGC: Oil and Natural Gas Corp, OIL: Oil India Ltd, PSCs: Production Sharing Contracts, GNOP: Greater Nile Oil Project, mt: million tonnes, PPAC: Petroleum Planning and Analysis Cell, OPEC: Organization of the Petroleum Exporting Countries, tmt: thousand metric tonne, OVL: ONGC Videsh Ltd, US: United States, PMUY: Pradhan Mantri Ujjwala Yojana, IOC: Indian Oil Corp, LPG: liquefied petroleum gas,  BPL: below poverty line, OMCs: Oil Marketing Companies, HPCL: Hindustan Petroleum Corp Ltd, CNG: compressed natural gas, ATF: aviation turbine fuel, GST: Goods and Services Tax, VAT: Value Added Tax, bpd: barrels per day, MRPL: Mangalore Refinery and Petrochemicals Ltd, BPCL: Bharat Petroleum Corp Ltd, mtpa: million tonnes per annum, WTI: West Texas Intermediate, EIA: Energy Information Administration, OSP: official selling prices

Courtesy: Energy News Monitor | Volume XIV; Issue 46

Indian Energy Sector in 2014: A Review

Ashish Gupta, Observer Research Foundation

Power

The year started with political flip-flop over energy prices due to elections in the country. All parties struggled to establish their positions and the issue of power and petroleum product prices were gaining significance in party positions. In the case of Delhi, the subsidy for residential consumers consuming up to 400 units of electricity was withdrawn from 31st March, 2014. The government also rolled back the decision to increase diesel prices even though it committed to increase the same by Rs 0.50/litre every month. But as petrol prices were deregulated, it was reduced by Rs 0.75/litre (excluding state levies) from 1st April 14 in Delhi though it was revised upwards by Rs 0.60/litre (excluding state levies) from 1st March 14. While the already unpopular monthly hike in diesel rates was put off during the election season. In the later part of the year, the Delhi Electricity Regulatory Commission withdrew the up to 7 percent power tariff hike announced earlier, attributing the roll-back unconvincingly to the requirement of ‘some more inputs on price of fuel’ from the generation companies supplying power to the capital. What was the reason for the multiplicity of positions? Partly political perhaps but mostly unknown!

Civil Nuclear Energy

On the Nuclear energy front, the share of nuclear energy has declined from 4% (2012) to 3.4% (2013) due to dramatic increase in generation from other sectors. In April 2013 a bilateral safeguards agreement was signed between the Department of Atomic Energy (DAE) and the Canadian Nuclear Safety Commission (CNSC), allowing trade in nuclear materials and technology for facilities which are under IAEA safeguards. A similar bilateral agreement with Australia was signed in 2014. Both were signed essentially for uranium supply. Despite this the nuclear energy sector cannot claim to have made significant progress.

The Atomic Energy Regulatory Board (AERB) was criticised for playing a subordinate role to the Atomic Energy Commission (AEC) as the AERB is mandated to inspect the working of AEC. Therefore, how far the government’s decision to institutionalize another regulatory authority such as the proposed ‘Nuclear Safety and Regulatory Authority’ would help in bringing transparency is not clear. Apart from this, many sites have been proposed for civil nuclear power but none have made progress excluding Kudankulam where one unit went critical but is yet to produce power at full potential as some tests are yet to be performed. The Kudankulam projects got the approval in 1988 with an estimated cost of US $ 2.6 billion and till date only one unit has started working partially with cost escalation to US $ 3.4 billion. These delays and cost overruns are draining the exchequer. Low public acceptance for civil nuclear projects means public agitation will continue and there will be more cost overruns. Despite many issues which need to be resolved particularly Section 17 (b) and Rule 24 of the Civil Nuclear Liability Act but the civil nuclear industry is optimistic. How far this optimism is justified and to what extent nuclear energy will contribute to India’s energy security is still very uncertain.

Climate Change

Climate Change remained the hottest topic during 2014 because the crucial decisions were to be made at Lima in 2014 and concluded in Paris in 2015. The Lima outcome was not considered a great success but India’s biggest gain was the renewed solidarity among the 134-country developing economies group – G77 plus China and the successful strategizing by the Likeminded Developing Countries (LMDC) group. The group suffered a setback when the Philippines, reportedly under pressure from developed countries, backed out.  It was grudgingly accepted by all that ‘common but differentiated responsibility (CBDR)’ that took into account historical responsibilities would remain a basic and fundamental principle of future negotiations.  However it was clear that rich nations continued to be unwilling to open their pockets either to share financial resources or offer technological assistance.

Indeed measures must be adopted to combat climate change, but the ‘dos’ and ‘don’t’ should not be restricted to developing nations only. Climate change deliberations are put forward on the basis of sustainable growth in the energy sector. But sustainability is also interlinked with affordability; therefore an inclusive approach for adopting various sources of energy where sustainability is complemented with affordability, viability and accessibility is required. India’s climate morality has already begun at home; the question remains open on the climate morality of rich countries.

Renewable Energy

On the renewable energy front, India made reasonable progress with total installed capacity of 31,692 MW. The government announced solar power generation target of 100,000 MW by 2022, up from the 20,000 MW goal planned by the UPA government. Finance Minister Arun Jaitley allocated ` 1,000 crore for the solar power sector in Budget 2014-15. The government also aimed to construct Ultra Mega Solar Power Projects or high capacity plants in the radiation rich states of Rajasthan, Gujarat, Tamil Nadu and Ladakh. Apart from that, a package of incentives have been announced (except wind) including fiscal concessions such as 80% accelerated depreciation, concessional custom duty for specific critical components, excise duty exemption, income tax exemption on profits for power generation etc. State Electricity Regulatory Commissions in Andhra Pradesh, Haryana, Punjab, Madhya Pradesh, Maharashtra, Rajasthan, Tamil Nadu, Gujarat, Kerala, Punjab, Orissa and West Bengal have announced preferential tariffs for purchase of power from wind power projects.

Having said that, the Jawaharlal Nehru National Solar Mission was launched on the 11th January, 2010 by the then Hon’ble Prime Minister has flourished but not at the pace envisaged. The important question remains why JNNSM, after so much genuine efforts, did not pick up? On the contrary, most of the renewable projects awarded under state programs have flurished. Gujarat is a classic example as it offered much higher tariff.

During the year it became very difficult for the government to strike a balance between imported content and indigenous components. Empowering the indigenous renewable industry was a key objective but overseas companies were not in favour of Domestic Content Requirement (DCR) and claimed that it went against global trade practices. On the other hand indigenous companies wanted some protection through DCR as they were (and continue to be) vulnerable to Chinese silicon and American thin film manufacturers. Apart from this claims were made during the year that renewable energy had reached grid parity but the ground reality suggests otherwise. Claims of grid parity must be seen in the context of financial viability. Interestingly renewable energy projects are part of infrastructure financing but this priority provision has not been sufficient to change the negative perception of renewable energy sources by financial institutes.

The government has taken all possible measures to promote renewable energy whether through subsidies or through Viability Gap Funding. The only thing that is missing is the lack of proper monitoring system. The early exit clause has made the situation worse. During the year we have witnessed that Renewable Purchase Obligation (RPO) was once again not fulfilled by most of the discoms. The answer is in the balance sheets of the discoms which show clear illiquidity. RPO is no longer a matter of obligation but the question is of financial viability. Central Electricity Regulatory Commission also passed an order to penalize the CMDs/ MDs of dicoms at the personal level if the obligation is not fulfilled. These are very encouraging orders but adopting the stick approach is not a feasible solution. The need of the hour is to make the power sector financially strong so that they will take the obligation willingly and not forcefully.

Coal

On the coal front, the year started with clubbing of coal, power and renewable under one Ministry head which was a much desired decision. Coal cess was increased from Rs 50/tonne to Rs 100/tonne to finance green activities. Between April 2014 and Oct. 2014, Coal India’s overall production increased by 6.6 percent but remains at only 97 percent of the desired target of 259.85 million tonnes. Coal shortages started creeping in but fortunately by the end of the financial year the situation eased a little. However there are inconsistencies in the figures quoted by various agencies on coal imports. The media and even some of the experts exaggerate the figure and show a trend of steep growth in imports. The situation worsened after the Supreme Court judgement which came in September 2014. It resulted in the cancellation of 214 of the 218 coal blocks allocated by the successive governments since 1993 and gave the companies awarded coal blocks just six months to wind up their operations. In the wake of these challenges, the Government announced that Indian coal production must touch a target of1 billion tonnes by 2019. Unfortunately until the structural issues are addressed in a time bound manner, this ambitious target is unlikely to be met.

In order to counter the coal shortages and to give private sector more freedom in the coal sector, the government came out Coal Ordinance 2014. The Government is looking to supersede the Coal Mines Nationalisation (Amendment) Bill 2000 which is still pending in the Parliament. Though the ordinance has been approved by the Lok Sabha (lower house) it is yet to be approved by the Rajya Sabha (upper house).

In 2014 reform narratives continued to be equated with tariff hike. Most power distributers have sought and continue to seek tariff hike in the name of reform or costly coal imports. But the recent imported coal scam estimating a loss of Rs 29,000 crore (Rs 290,000 million) unearthed by the Directorate of Revenue Intelligence has raised questions over this strategy. Are companies claiming to be using imported coal just to justify higher tariff? The question remains open. The solution is real reforms but unfortunately that is unlikely to happen in the coal sector. But it is probably time for those promoting the narrative of shortage of energy in India to revise their stories!

Views are those of the author                    

Author can be contacted at ashishgupta@orfonline.org

Courtesy: Energy News Monitor | Volume XI; Issue 30