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


The upward trend in imported PV module prices is likely to affect viability of recently awarded solar projects, rating agency ICRA said. The imported PV module price has been rising over the last 3-4 months, up by about 15 percent, to 35-37 cents per watt in August, from about 30-32 cents in May, ICRA said. ICRA also flagged risk of delays along with cost overruns due to disruption in delivery schedule and dishonouring of price terms agreed earlier by Chinese (original equipment manufacturers) OEMs to Indian independent power producers (IPPs). According to ICRA estimates, a 6 cent per watt jump in PV module price will result in an increase of about 11 percent in capital cost and decline in project internal rate of return (IRR).

Chinese solar modules are seeing a hardening of prices for the first time in years, with the average selling price (ASP) going up in India on a quarterly basis, Mercom India said. According to the clean energy communications and consulting firm, this has posed a significant challenge to India’s solar industry. Developers not just in India, but across the world have been modelling their auction bidding strategies based on the assumed perpetual decline of Chinese module prices. The uptick in price has come after a decline of nearly 5 percent in the second quarter of 2017. Short-term fluctuations do not usually make a huge difference, the firm acknowledged, but cautioned that if module prices continue to rise or even stay flat for a couple of quarters, it will start hurting developers who cannot wait indefinitely to procure the lowest priced panel. High Chinese demand generally firmed up module prices in June before feed-in tariff deadline at the end of the month, it said.

India’s MNRE has issued an order for new set of standard specifications for solar PV modules which will come into force after one year from the date of their notification. As per the order, under the Bureau of Indian Standards (BIS) Act of 1986, any manufacturer who manufactures, stores for sale, sells or distributes solar photovoltaics systems, devices or components will make an application to the bureau for obtaining registration for use of the ‘standard mark’ in respect of the Indian standard.

The domestic solar industry has broadly welcomed the new standards for solar PV modules announced by the government calling it as a positive step to ensure upgradation of quality. The new standards would help significantly in improving the quality of modules manufactured in the country, according to experts. While it is a good step for retail and rural customers who are usually unaware of the quality of the modules they are purchasing, the notification should not become a trade barrier for modules which were already meeting the international standards. New standards issued by the government are at par with the global standards. There could be some cost escalation initially for new solar installations but it will eventually be beneficial as Operational & Maintenance (O&M) costs of solar installations will reduce significantly due to better quality of modules.

Central Delhi could soon be generating up to 20 MW of power on the rooftops. The EESL, a union ministry of power venture, has signed a MoU with the NDMC to install 65,000 solar modules on major buildings located in the areas under the civic body’s jurisdiction. EESL is currently carrying out a field study to assess roof-top solar power generation potential of various institutions before beginning the work of installing the required infrastructure. Based on the findings, the owners of the buildings will be asked to choose between two models. The capital expenditure model will involve the building owners putting in the money and EESL supplying, designing, installing and commissioning the solar set-up. Under the other model, the operational expenditure one, the entire burden, including financing, will be borne by EESL. The buildings that finance the installation of the solar photovoltaic panels will be allowed free use of the power generated, according to the MoU signed by EESL with NDMC. In the second model, where building owners depend on EESL to finance and erect the generation system, the users will be billed a lower power charge of ₹ 3.87/kWh for the use of the energy generated. The company said that EESL would invest ₹ 1.15 billion for rooftop project. Government buildings and private institutions earmarked for the project include Andhra Bhawan, Chhattisgarh Bhawan, Gujarat Bhawan, Hyderabad House, Nirman Bhawan, Maharashtra Bhawan, Mizoram Bhawan and Jeevan Bharti Building. EESL expects to finish the work by the end of the year. The rooftop panels are expected to have a cumulative capacity for 20 MW of solar power, or an annual 30 million units of power.

As per reports poor quality Chinese solar modules, rejected by developers, are being sold in the domestic market at a discount. With their project deadlines approaching, some Indian developers have taken recourse to this route to meet cost pressures and timelines. Modules account for nearly 60% of a solar power project’s total cost. With the average efficiency of a solar panel usually only 16-22%, any sub-standard quality will impact generation. India is also conducting an anti-dumping investigation on solar equipment from China, Taiwan and Malaysia. Major Chinese solar module manufacturers include Trina Solar Ltd, Jinko Solar, JA Solar Holdings, ET Solar, Chint Solar and GCL-Poly Energy Holdings Ltd. Experts said that the quality of imported modules in India has always been suspect.

Experts said air pollution is diminishing India’s capacity to harness power from the sun, undermining billions being invested in renewables as the energy-hungry giant emerges as a solar superpower. New research has found the smog and dust that sickens millions across India every year is also sapping solar power generation by more than 25 percent, far beyond levels previously thought. In the first study of its kind, US and Indian scientists measured how manmade particles floating in the air and deposited as grime on solar panels combined to seriously impair sunlight from converting to energy. This interference causes steep drops in power generation, they found. At present levels in India, it could amount to roughly 3,900 MW of lost energy, six times the capacity of its largest solar farm, a gigantic field of 2.5 million panels. India, the world’s third-largest polluter, is banking on solar to electrify homes for hundreds of millions of its poorest citizens without adding to its sizeable carbon footprint. At the Paris climate summit in 2015, India pledged cuts to its future emissions and vowed to source at least 40 percent of its energy from renewables by 2030, a target it is well on track to exceed. Dust has long been a menace for solar projects in desert states like Rajasthan and Gujarat, where robotic wipers are deployed to ensure panels are cleaned after sandstorms. But the new research confirmed what solar installers had long suspected that choking smog from cars, coal plants, crop burning and trash fires was particularly adept at bleeding energy.

India has barred state authorities from unilaterally cancelling or modifying solar PPAs after six state governments in last two months pushed developers to lower tariffs, threatening to derail projects worth $7.5 billion. The capacity has already more than tripled in three years to more than 12 GW. The government said it will impose a minimum penalty of 50 percent of the tariff if the purchase agreement is arbitrarily scrapped by the state or the developer. Over the last four months, debt-laden power distribution companies in Gujarat, Andhra Pradesh, Uttar Pradesh, Tamil Nadu, Karnataka and Jharkhand were pushing developers to renegotiate signed or previously agreed upon PPAs, risking closure of 7 GW of solar projects, a report from ratings agency CRISIL noted. Indian states and developers had clashed in May after the solar tariff for the 500 MW Bhadla solar power park in the western state of Rajasthan slumped to a record low of ₹ 2.44/kWh for 200 MW. However, the southern state of Andhra Pradesh, which accounts for the highest number of solar projects in the country, is not looking to sign new PPAs in the near term.

The MNRE said its guidelines for tariff-based bidding for procuring solar power would reduce risk, enhance transparency and increase affordability. The MNRE had issued the new guidelines for tariff based competitive bidding process on August 3. The guidelines have been issued under the provisions of Section 63 of the Electricity Act, 2003 for long term procurement from grid-connected Solar PV Power Projects of 5 MW and above, through competitive bidding. Besides, it said, the move will help protect consumer interests through affordable power. It will also provide standardisation and uniformity in processes and a risk-sharing framework between various stakeholders involved in the solar PV power procurement, it said.

The government has implemented new rules for buying power from grid-linked solar power projects through competitive bidding under the National Solar Mission to improve transparency and standardise auctions. These guidelines, prepared by the MNRE, cover the grid-connected PV power projects with a size of 5 MW and above. The norms provide that the minimum PPA tenure will be 25 years that will help ensure lower tariffs. Besides, unilateral termination or amendment of PPA is not allowed. The new framework also contains provision for force majeure. Now, the PPA would have provisions with regard to force majeure definitions, exclusions, applicability and available relief as per the industry standards.

A June order by the power ministry on inter-state electricity transmission charges could affect DMRC’s plan to buy power from one of the world’s largest solar power project at a single site in Madhya Pradesh, forcing both DMRC and the state government to seek relief from the ministry of new and renewable energy. DMRC may have to bear an additional ₹ 0.91/kWh cost due to inter-state transmission charges and losses from the marque project, thereby increasing the tariff from ₹ 3.30/kWh to ₹ 4.21/kWh from the 750 MW plant at Rewa, Madhya Pradesh. The 14 June order of the power ministry limits the waiver of inter-state electricity transmission charges to discoms meeting their renewable purchase obligations. Since DMRC is not a discom, it will have to pay this additional tariff referred to as the Inter-State Transmission System (ISTS) charges. The PPAs for the project were inked on 17 April. The record low-winning bids of ₹ 2.97/kWh at Rewa in February marked a turning point for India’s solar power sector with the delivered cost of electricity to DMRC being ₹ 3.30/kWh. The Rewa project is also India’s first solar project to conduct inter-state sale of electricity with its PPA accepted by the union government as a standard model to help achieve lowest electricity tariff rates through competitive bidding.

The Tamil Nadu Electricity Generation and Distribution Corp (TANGEDCO) has created a record in selling wind power to other states for 2017. The power utility has so far sold 11.938 million units to various states and has also earned a few millions of rupees from the sale. Apart from selling wind power to other states, Tamil Nadu has also evacuated the maximum amount of renewable energy from wind this year. On an average, nearly 3500 MW to 4000 MW of wind power was used by the distribution company to distribute power. Wind power is generally available from evening to early morning. According to Electricity Act 2003, each state has to meet a percentage of power generated there annually through renewable power like wind and solar.

The MNRE signed an agreement on technical cooperation under the “Indo-German Energy Programme Green Energy Corridors (IGEN-GEC)” with Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ). The two countries began collaboration on the Green Energy Corridors in 2013 following Indo-German Consultations held in Berlin. The MNRE is in the process of implementing the first phase of the Green Energy Corridor. Germany has been supporting India in achieving its goal for sustainable development through bilateral cooperation for almost six decade now.

International Water Management Institute (IWMI) managed to fund a pilot project with a view to promote the use of solar power for irrigation purposes. The project which was initiated in Dhundi village in Anand district some two years ago, with a team of six farmers has now managed to generate 100,000 kWh of power, some 45% of which they use for irrigation purposes. The six farmers formed a cooperative and later adopted using of solar irrigation pump, as part of the project. According to IWMI, the pumps have a unique capability to pool and inject surplus solar power to electricity grid, and therefore, farmers earn ₹ 4.63/kWh. The connection of the pumps to state electricity grid has therefore proven to be a major incentive for the farmers. Till date, these pumps have generated nearly 100,000 kWh of green energy of which 43,897 kWh was used for irrigation. Therefore, the cooperative injected more than 52,000 kWh of green energy into the grid and generated an income of around ₹ 400,000 from sale of surplus solar power.

RIL is considering entering the power-storage business with its partner BP Plc to expand into the country’s growing renewable energy sector. The companies are considering a plan to set up energy-storage projects near solar- and wind-energy installations. A decision on investment and implementation will be taken by December. The push into power storage dovetails with efforts to boost the country’s reliance on renewable power and set it on track to sell only electric cars by 2030. Global oil majors such as Royal Dutch Shell Plc, Total SA and Exxon Mobil Corp are investing in new-energy technologies to improve electricity grids and develop fuels from renewable resources. RIL has been seeking to enter the business since 2009, when it first announced plans for alternative-energy businesses. RIL and BP in June said they were extending their partnership to sell conventional fuels as well as explore opportunities in clean energy. RIL is planning to sell liquefied natural gas at its fuel-retailing outlets and set up charging stations for electric vehicles. LNG and electric-vehicle charging would be an extension of RIL’s current retail fuel business, though the company hasn’t firmed up a business plan as the market is at a nascent stage. India’s solar-power capacity has surged fourfold since December 2014 to about 13 GW. Wind installations reached almost 33 GW from 22.5 GW over the same period.

A Fitch Group Company BMI Research revised upward the non-hydro renewable energy capacity in India to 155 GW from 130 GW by 2026 on the back of higher than expected solar installation and successful wind auctions.  Positive developments in the renewables sector over the last six months, specifically in the wind and solar segments, have led us to upwardly revise our non-hydro renewables capacity forecasts, it said. The BMI Research expects wind capacity to total 35.5 GW by end 2017, up from its previous estimate of just over 31 GW. By 2026, it forecasts the Indian wind capacity to reach 68 GW, a revision from its previous forecast of nearly 54 GW. It has revised its solar forecasts upwards, with solar capacity totalling 19.2 GW by end 2017 and 71.5 GW by 2026. This is from a previous 17 GW and 64.7 GW previously, over the same time period.

Overemphasis on renewable energy would result in reducing viability of coal-fired thermal power plants in India, adding to the massive NPAs of state-run lenders, Chief Economic Adviser (CEA) Arvind Subramanian said. The declining viability of thermal power plants and the rising NPAs of state-run banks, which have lent to power companies “seems a double whammy for the government,” he said. For India, which is struggling to provide basic electricity to about 25 percent of its population, coal will provide about 60 percent of the country’s power needs until 2030, he said. India’s total renewable generation capacity has crossed 57 GW, with an increase of 24.5 percent being registered in the last fiscal year. The capacity addition in solar energy last year stood at 81 percent.

The Centre is set to finalise the creation of a ₹ 160 billion hydropower development fund to revive stalled projects in the country. The power ministry was bringing out the policy to revive the sector that has gone “sluggish”. The policy would include a proposal for considering hydropower as renewable energy, he said.

The CERC did not approve the proposal of the IEX to introduce spot trading of renewable energy on its platform. While the IEX expected the mechanism to provide more options to fulfil RPOs of discoms, encourage new capacity addition and address the uncertainties around signing of long term PPAs  and cost recovery issues for renewable energy players, CERC felt that the current market condition is not yet ready for the product. The proposed G-DAM was based on the existing framework in regular day-ahead-market, which is also known as spot-market in market parlance. IEX said that renewable energy traders could trade solar or wind power in regular spot market if bids in G-DAM were partially cleared. Under the scheme, renewable energy sellers would have got equivalent amount of RECs for bids cleared in the spot market. One REC is treated as equivalent to one thousand units of green electricity. CERC said that since there is no substantial data available which can reflect the quantity of surplus renewable power, it is not advisable to introduce this instrument in the power exchange for trading. CERC also said that G-DAM would come in conflict with the existing products such as feed-in tariff and REC. Renewable energy is traded through the REC mechanism in the spot market. It aims to address the mismatch between availability of renewable energy resources in the states and the requirement of the obligated entities to meet their RPO, which mandates that all electricity distribution licensees should purchase or produce a minimum specified quantity of their requirements from renewable energy sources. REC trading is supposed to take place once in a month in the exchange.

Rest of the World

China’s parliament passed a new nuclear safety law aimed at improving regulation in the nuclear power sector as new projects are built across the country. The law will give more powers to the regulator, the National Nuclear Safety Administration (NNSA), and establish new systems that will improve the disclosure of information on issues like radiation, and prevent or minimise risks from nuclear accidents. China is in the middle of an ambitious reactor building programme aimed at bringing total nuclear capacity to 58 GW by the end of the decade, up from 35 GW now. But weak and opaque governance has long been seen as an industry problem, especially when it comes to determining the precise roles of the government, the military and state-owned nuclear enterprises on issues such as the handling of nuclear materials and the disposal of spent fuel. The new law focused on strengthening China’s nuclear safety regime, and would create “institutional mechanisms” and a “division of labour” among regulators and enterprises to clarify responsibilities for safety.

China has approved a plan to promote the Hualong One nuclear reactor as a single integrated nuclear reactor brand to accelerate its development overseas and to compete with advanced models such as Areva’s EPR or Westinghouse’s AP1000. The CNNC and the CGN have been jointly developing the Hualong One design, while continuing to work separately on their own nuclear reactor design. This variety of reactor brands has delayed the approval of new projects in China and abroad, while China aims to raise its nuclear capacity to 200 GW by 2030. CNNC and CGN will transfer intellectual property rights to Hualong International, their joint venture created in 2016 and will use integrated technical standards when building Hualong reactors.

Saudi Arabia and China are to cooperate on nuclear energy projects following discussions between the two countries on ways to support the kingdom’s nuclear energy programme. Saudi Arabia has been for years trying to diversify its energy mix so that it can export more of its oil, rather than burning it at power and water desalination plants. It launched a renewable energy programme this year with the announcement of the winning bid for its first utility-scale solar project due in November. In addition to that programme, Riyadh is in the early stages of feasibility and design studies for its first two commercial nuclear reactors, which will total 2.8 GW. China’s leading state nuclear project developer CNNC has now signed a MoU with the Saudi Geological Survey (SGS) to promote further existing cooperation between the two sides to explore and assess uranium and thorium resources. Nuclear energy will help Saudi Arabia to develop water desalination plants, of which it is a leading producer.

The price Britain will pay for new offshore wind power has plunged below new nuclear generation for the first time, according to figures from a power auction. The rapidly falling cost of wind power may stoke criticism of the government for promising much higher prices to investors in the long-delayed Hinkley Point C nuclear power plant, the first to be built in Britain for more than 20 years. Britain needs to invest in new capacity to replace ageing coal and nuclear plants that are due to close in the 2020s. Renewables, such as wind power and solar, can only meet part of those needs because of their variable supplies determined by the weather and, for now, there are no large scale energy power storage options. Nuclear plants can offer a steady supply, but plans for Hinkley Point C have been beset by delays and rising construction costs. Britain’s subsidy auction for new offshore wind projects awarded contracts between at 74.75 pounds and 57.50 pounds per MWh depending on the delivery date. The eleven renewable energy projects that won contracts are expected to deliver up to 3 GW of new electricity generation capacity from 2021-2023, with the contracts worth up to 176 million a year, the government said.

The Egyptian government has approved contracts for the construction of the El Dabaa nuclear power plant project. The plant is expected to be built with the participation of Rosatom and will consist of four units, each with capacity to produce 1,200 MW of electricity, and take 12 years to complete. The reactors will use Rosatom’s third generation VVER-1200 design. As for the project cost, the total bill is put at $30 bn and the Russian government proposes to lend $25 bn. Egypt is hoping that private investors will cover the shortfall while it will start repaying its loan from Russia in 2029 over 13 years with an interest rate of 3%.

Coal-dependent Poland aims to build its first nuclear power plant by 2029 to reduce carbon emissions. Warsaw announced the project in 2009, but hit numerous delays due to falling power prices and Japan’s 2011 Fukushima nuclear accident, which eroded public support. Last year, the ruling Law and Justice party (PiS) revived the plan after it won elections in 2015, and said it aimed to build the plant within ten years. Poland’s state-run firms have been busy building new coal-fuelled power plants.

Southern Company said it would seek to complete two unfinished nuclear reactors in the US state of Georgia despite billions of dollars of cost overruns that pushed the main contractor, Westinghouse Electric Co LLC, into bankruptcy. The project known as Plant Vogtle is the first new US nuclear power plant to be built since the Three Mile Island accident in 1979, and completing it would provide hope for a struggling US nuclear industry. Southern said it expected the two reactors to be completed by the end of 2022. The project was initially expected to produce power in 2016.

China’s Trina Solar, the world’s largest maker of photovoltaic panels, is looking to grab a piece of Brazil’s nascent solar power market despite tough economic conditions. Trina opened an office in Brazil this year, aiming to become a major player by focusing on small-scale projects such as those that place solar panels on residential and business rooftops. Trina has ruled out building a plant in Brazil, as some competitors have, preferring to initially import panels from China. Brazil has turned to solar energy later than other countries in Latin America. Heavily dependent on hydropower projects, the country only recently decided to diversify its energy mix by adopting solar-friendly policies. But Brazil’s deepest recession on record, with a total economic contraction of 8 percent for 2015 and 2016, dealt a blow to early solar projects, with some being cancelled outright. Trina’s plan to import all its panels means it cannot tap Brazilian government financing for projects that use locally produced panels.

The EU is likely to reduce the minimum price that Chinese solar panel producers are allowed to sell into Europe after a meeting of trade representatives from EU countries. Chinese solar panel imports have been subject to measures to counter dumping and subsidies since 2013, with an 18-month extension agreed by EU countries earlier this year. Chinese companies that sell below a set minimum prices are subject to import duties. The European Commission has proposed a gradual phasing out of the measures, including a schedule that reduces the minimum import price every three months. The EU and China came close to a trade war in 2013 over EU allegations of dumping by Chinese solar panel exporters.

A bitterly divided US solar power industry descended on Washington to testify before a government panel that has been asked to impose steep tariffs on imported solar panels. The trade case, brought by panel maker Suniva, has created a rift between the sector’s struggling US manufacturers and the much bigger domestic industry that installs and develops solar projects. Suniva filed a petition seeking the tariffs with the International Trade Commission in April, nine days after the company sought Chapter 11 bankruptcy protection. Suniva, which has been majority owned by Hong Kong-based Shunfeng International Clean Energy since 2015, makes panels in Georgia and Michigan. The company contends that a glut of panels manufactured abroad has depressed prices and made it difficult for American producers to compete. The petition has drawn support from an Oregon-based subsidiary of Germany’s SolarWorld AG. Much of the industry, including the powerful Solar Energy Industries Association trade group, has said tariffs on overseas panels would drive up the price of solar power just as it has become competitive with electricity generated by fossil fuels such as natural gas and coal.

US solar installations rose 8 percent in the second quarter as robust utility demand offset a sharp pullback in residential rooftop systems, according to an industry report published. The industry installed 2.39 GW of photovoltaic solar, up from 2.2 GW a year ago, the report by GTM Research and the Solar Energy Industries Association said. Utility projects accounted for 58 percent of the total. Most new projects for utilities were procured voluntarily rather than because of a need to satisfy government mandates, reflecting the low cost of solar. Voluntary procurement is biggest in the Southeast, though solar is growing most rapidly in the Midwest as utilities see it as a complement to wind farms. The non-residential market soared 31 percent to 437 MW, boosted by development of community solar projects in Minnesota and Massachusetts and corporate and industrial demand in California. Community solar plants provide power to more than one customer but are far smaller than utility-scale plants. In both Massachusetts and California, developers rushed to complete projects under solar incentive programs.

The prospect of China banning fossil fuel-powered vehicles is failing to alarm investors in the oil producers likely to lose out. Shares in the listed units of China’s biggest oil companies, PetroChina Co, Cnooc Ltd and China Petroleum & Chemical Corp, barely budged after the government said it’s working on a timetable to end production and sales of vehicles that run on gasoline, diesel and other fossil fuels. By contrast, electric car producers and the companies that supply their components surged. From the Organization of Petroleum Exporting Countries to BP Plc, the world’s biggest oil producers have started to take electric vehicles seriously as a long-term threat to demand. The head of Royal Dutch Shell Plc has warned oil liquids demand could peak in the early 2030s as electrification accelerates.

Argentine biodiesel exports will be priced out of the US market, its leading industry body said, after Washington decided to impose steep duties on imports that it said were unfairly subsidized. The countervailing duties on soy-based Argentina biodiesel could be as much as 64.17 percent, according to the US Commerce Department. Duties of up to 68.28 percent will be imposed on palm oil biodiesel imports from Indonesia. Argentina accounts for two-thirds of U.S. biodiesel imports, which totalled 3.5 billion litres in 2016, according to US government data. Total US biodiesel consumption is about 7.5 billion litres. The Commerce Department’s decision comes after the US National Biodiesel Board (NBB) asked the government in March to impose duties, claiming the imports were below market value and undercutting US biodiesel producers. Argentine biodiesel association Carbio, which represents producers including Cargill Inc and Louis Dreyfus Co, denied there were subsidies on the country’s biodiesel exports and called the duties protectionist. Indonesia exported 420,000 kilolitres of biodiesel to the US in 2016, according to data from the country’s biodiesel producers association, jumped from 270,000 kilolitres a year ago.

Tanzania has invited bids to build a 2100 MW hydroelectric plant in a World Heritage site renowned for its animal populations, despite opposition from conservationists to the long-delayed project. It expected construction of the power plant to be completed within three years. The deadline for bids is October 16, which specifies that work must be completed within a period of 36 months, with a maximum mobilisation period of three months. The government did not say how much the project would cost and how it would raise financing. Investors have long complained that a lack of reliable power is an obstacle to doing business in East Africa’s second biggest economy. Tanzania aims to boost power generation capacity to 10,000 MW on the next decade from about 1,500 MW now by using hydropower and some of its vast natural gas and coal reserves.

Saudi Arabia aims to exceed its target to generate 9.5 GW of electricity from renewable energy annually, to highlight its long-term commitment to green energy. The government has said it plans to generate 9.5 GW of electricity from renewable sources a year by 2023 through 60 projects, involving an estimated investment of between $30 billion and $50 billion.

Emissions by 90 largest carbon producers contributed almost half of global surface temperature increase and roughly 30 percent of global sea level rise since 1880, an international study said. They blame 50 investor-owned carbon producers, including BP, Chevron, ConocoPhillips, ExxonMobil, Peabody, Shell and Total, for roughly 16 percent of the global average temperature increase from 1880 to 2010, and around 11 percent of the global sea level rise during the same time-frame. The first-of-its-kind study published in the scientific journal Climatic Change links global climate changes to the product-related emissions of specific fossil fuel producers. Focusing on the largest gas, oil and coal producers and cement manufacturers, the study calculated the amount of sea level rise and global temperature increase resulting from the carbon dioxide and methane emissions from their products as well as their extraction and production processes. The study quantified climate change impacts of each company’s carbon and methane emissions during two time periods: 1880 to 2010 and 1980 to 2010. By 1980, investor-owned fossil fuel companies were aware of the threat posed by their products and could have taken steps to reduce their risks and share them with their shareholders and the public.

The study, “The rise in global atmospheric CO2, surface temperature, and sea level from emissions traced to major carbon producers”, builds on a landmark 2014 study by Richard Heede of the Climate Accountability Institute, one of the co-authors of the study published. Heede’s study, which also was published in Climatic Change, determined the quantity of carbon dioxide and methane emissions that resulted from the burning of products sold by the 90 largest investor-and state-owned fossil fuel companies and cement manufacturers. The study led by Ekwurzel found that emissions traced to the 90 largest carbon producers contributed to approximately 57 percent of the observed rise in atmospheric carbon dioxide, nearly 50 percent of the rise in global average temperature, and around 30 percent of global sea level rise since 1880.

PV: photovoltaic, MNRE: Ministry of New and Renewable Energy, MW: megawatt, GW: gigawatt, EESL: Energy Efficiency Services Ltd,  MoU: Memorandum of Understanding, NDMC: New Delhi Municipal Council, kWh: kilowatt hour, PPAs: power purchase agreements. DMRC: Delhi Metro Rail Corp, discoms: distribution companies, RIL: Reliance Industries Ltd, LNG: liquefied natural gas, NPAs: non-performing assets, IEX: Indian Energy Exchange, CERC: Central Electricity Regulatory Commission, RPOs: renewable purchase obligations, G-DAM: green day-ahead-market RECs: renewable energy certificates, CNNC: China National Nuclear Corp, MWh: megawatt hour, US: United States, CGN: China General Nuclear Project Corp, EU: European Union

Courtesy: Energy News Monitor | Volume XIV; Issue 15


Moon Shadow will Enhance Green Power Systems – How German Energy Turnaround Manages Solar Eclipse

Thomas Elmar Schuppe, CIM Integrated Expert on Energy, Observer Research Foundation

A solar eclipse is admittedly a rare event. On Friday morning March 20, 2015, the moon will partially block out up to 80% of the sunlight for the first time in the era of renewables dominating German power generation capacities. This event has been widely characterized as the unprecedented stress test for the German energy system by challenging particularly the utilities and electricity grid operators to guarantee supply stability and to avoid blackouts.

In a bigger picture and against the backdrop of long term considerations according to the slow evolvement of structural changes in established power generation systems, natural phenomena as well as disasters will make inroads indeed occasionally but with some regularity over time. From the perspective of electricity generation system there are two reasons why we should give greater weight to these natural interferences: (I) Severe natural disasters like heavy storms and rains, floodings but also longer lasting droughts on the other hand are expected to increase over time triggered by the advancing effects of global climate change and local weather patterns; (II) with increasing share of renewables in total power generation of one system or country, the consequences are becoming more significant, i.e. the ramifications for Indian power supply will be larger if 100 GW of solar power capacity might be impacted (as the government plans to install till 2022 as part of total targeted renewable energy capacity of 175 GW) or some 3 GW of today, and even worse as the share of renewables will rise in total electricity generation. For example, the share of renewables in German electricity production has risen in an impressive manner to more than 26% in 2014, thereof about a fifth from photovoltaic (PV). According to Fraunhofer ISE (2015) the installed nominal capacity of PV was about 38.5 GW and the number of installations about 1.4 million in Germany end of 2014. Therefore, with PV is the largest single generation source among all types of power generation capacity in Germany and  consequently of utmost importance for German electricity supply as well as associated overall generation system stability requirements.

The impact of the eclipse is set to be strongly dependent from local German weather conditions on that morning between 9.30 a.m. till 12 p.m.. Based on accurate weather forecasts the system operators will have quite a good lead time to prepare accordingly for appropriate balancing mechanisms. Due to Wetter online (2015) there is a quite good probability of a clear sky for the eastern and southern parts of Germany whereas north-western stretches are likely to experience overcast sky (see graph).

A recent study by HTW (2015) illustrates the solar irradiation strength under clear weather conditions and how it might be affected by the eclipse: within a short timeframe the maximum strength of global solar irradiation might be drastically reduced by about factor five.

Expected Course of max. Solar Irradiation Strength Without and With Eclipse Impact

(Berlin, March 20, 2015, 6 a.m. – 6 p.m.)

Source: HTW (2015), compiled by author.

However, to which extent weather conditions impact might turn out to be considerable is shown in the simulations below: Exactly one year ago the cloudless sky ensures that almost the full specific PV output could have been realised in comparison with a cloudy day (left figure). Almost the same scope is illustrated by taking three different days within less than a week period: For example, at March 20, 2014, max. PV output has been at around 64% whereas four days before it was down to only about 9%.

Simulation of the Scope of PV Output according to Sky Conditions and at Different Days (March 2014)

Source: HTW (2015), compiled by author.

In the upshot overall German PV capacity over the course of the day (see figure below) is expected to reach at a clear day 17.5 GW (and 2.4 GW at overcast sky resp.) just before the start of the eclipse, then crushing down to a minimum of 6.2 GW (0.7 GW) just within one hour, before shooting up to about 24.6 GW (3.6 GW) at noon. This is about the fourfold level than about one hour before.

Expected Course of PV Capacity in Germany: Clear Day vs. Overcast Sky
(Berlin, March 20, 2015, 6 a.m. – 6 p.m.)

Source: HTW (2015), compiled by author.

As a result, two critical situations need to be handled within 2-3 hours: (1) When the moon passes in front of the sun, electricity production from solar plants are expected to collapse quickly according to cloud exposure, (2) when the sun appears back out of the moon shadow, the actual production is expected to rise even more because at noon the irradiation is most powerful. About 15 GW of PV output differences from one hour to the next will have to be balanced by the system operators, demand side variations left out of consideration.

All over Europe the power producer and network operator prepare for the showdown with nature’s constellations. Since European electricity grids are well interconnected failures in one region would impact other regions, however, this large grid offers extensive balancing opportunities as well. Preparations for intensive communication and cooperation are on the way, German TSOs will stay in touch all the time throughout the eclipse and have already secured additional balancing power.

HTW (2015) concludes that the balancing can be done through various measures at the generation and demand side. However, from a mere technical point of view, in Germany the fluctuations could be completely offset be pumped storage hydro power stations alone, even on a clear day with maximum requirements: Initially electricity is produced by floating the water downhill through the turbines and in the second phase the pumps draw much power from the grid to back up the water basin for storage. In addition, the use of flexible power plants like– particularly – fast starting gas power plants and besides some of the hard coal power plants could back up compensation.

At the end of the day it turned out that the impact of the eclipse for the German power system could have been worse, which is – to tell the truth – above all a merit that belongs to the accurate and vigilant preparations of the system operators. The chart below shows data provided by European Energy Exchange (EEX (2015)) tracking the actual solar power generation from German power companies during the eclipse day: solar power capacity fell from 13GW to about 6GW as the eclipse began, then rocketed up to almost 20 GW within an hour. The whole system could be balanced by activating other energy sources without significant complications, doubts of interrupted supplies proved unfounded. However, power prices in Germany fluctuated considerably, but that’s what they are intended to: to send veritable signals to the market with respect to shortage of the commodity. According to Platts (2015) the German power for delivery the hour starting 10 a.m. for Friday (the peak of the partial solar eclipse) jumped 63% on Thursday to 49.41 Euro/MWh in the day-ahead auction on Epex Spot (European Power Exchange for power spot trading in Germany, France, Austria and Switzerland).

Actual Course of PV Capacity in Germany on March 20, 2015.

Source: EEX (2015).

It was the region’s first major eclipse since 1999; the next eclipse of this magnitude is not due in northern Europe until 2026. Notwithstanding Agora Energiewende (2015), a German think tank dealing with the Energy Turnaround, emphasises that the solar eclipse this year is only a foretaste of what is to come: with increasing shares of fluctuating renewable energy, the power system must become more flexible. In 2030 it is expected that imbalances of -10 to +15 GW will occur more often more often within one hour (as right now during the eclipse). Therefore, the whole generation mix and all other flexibility options must be aligned to these requirements. The most important options to realise flexibility are

  • Demand-side management
  • Flexible conventional power generation plants (e.g. natural gas fired)
  • System adaptive renewable power generation plants (to become more system service friendly)
  • Enhanced market integration and larger interconnected electricity networks
  • Larger storage and better storage technologies
  • Moderate reduction of Renewable generation feed in, Power-to-Gas, Power-to-Heat and Power-to-X (industries) solutions.

India has seen it last total solar eclipse in July 2009 (see figure). The next total one is scheduled for March 2034. By now India’s share of solar power generation in the overall electricity system is still negligible: with less than 3 GW of total installed solar-power capacity its share doesn’t exceed 2 % of power generation at present. However, the Ministry of New and Renewable Energy (MNRE) has set the course for the future and proposed to scale up grid connected solar power targets to an immense 100 MW by 2022. Even if this heroic target might not be realised, the share of solar power in total Indian electricity generation can be expected to increase steadily for various reasonable reasons. China is currently showcasing how fast a country can make inroads in solar generation and has led the world in solar installations for the last two years. It’s on its way to reach far more than 30 GW of solar power capacity by the end of 2014, about 40 times more than it had in 2010.

Indian’s power industry as well as the decisive institutions in politics and research should grasp the opportunities and learn from the European experiences in transforming the whole generation industry within few decades. Especially observations from the German Energiewende (energy turnaround) offer various starting points that ought to be taken into consideration for future planning purposes in India. The lessons learnt from the eclipse are only one module in a set of wide challenges and experiences in the German laboratory of greening the power sector. The information assembled will enhance the understanding of what will be important in a case of the eclipse, for example. India has the unique chance to avoid some of the painful restructuring experiences and to do it in a better way. This is particularly valid for long-term planning: today is important to bring the future structure of a sustainable power plant complex right on track. That is for example, to care also for system stability, appropriate balancing mechanisms and storage options, well balanced system of base load and flexible peak load (back up) power generation, demand side management, interconnected grids and market integration and pricing.

See also:

Energy News Monitor, Vol. X Issue. 17

Brown clouds looming on the green energy horizon in Germany

Thomas Elmar Schuppe, 08 October 2013

Energy News Monitor, Vol. XI Issue. 26

The German Energiewende turns around Market Structures and Prices (part I)

Thomas Elmar Schuppe, 09 December 2014

Energy News Monitor, Vol. XI Issue. 34

The German Energiewende turns around Policy Framework (Part II)

Thomas Elmar Schuppe, 03 February 2015


AG Energiebilanzen (2015), Bruttostromerzeugung in Deutschland ab 1990 nachEnergieträgern, Stand: 27. Februar 2015.

Agora Energiewende (2015), Die Sonnenfinsternis 2015:Vorschau auf das Stromsystem 2030. Herausforderungenfür die Stromversorgung in SystemenmithohenAnteilenan Wind- und Solarenergie, March 2015.

Bloomberg (2015a), Eclipse Tests European Power Grid Flooded by Solar Farms, by Stefan NicolaWeixinZhaRachel Morison, March 19, 2015,

Bloomberg (2015b), Look What Today’s Eclipse Did to German Solar Power Output, by D. Bennett, March 20, 2015,

EEX European Energy Exchange (2015), Actual Solar Power Generation (chart), valid for 2015/03/21,

Financial Times (2015), Eclipse puts Europe’s fears over solar power cut in the shade, by P. Clark and A. Ram, March 20, 2015,

Fraunhofer ISE (2015), AktuelleFaktenzurPhotovoltaik in Deutschland, Fassungvom 7.1.2015.

HTW HochschulefürTechnik und Wirtschaft Berlin (2014), Einfluss der Sonnenfinsternis im März 2015 auf die Solarstromerzeugung in Deutschland, Oktober 2014.

Platts (2015), German power price for eclipse hour up 63%, spot down on stand-by units, March 19, 2015,

Spiegel Online (2015), ExtrembelastungdurchSonnenfinsternis: Stresstestfür die Energiewende, March 16, 2015,

Wetteronline (2015), Sonnenfinsternis gut zusehen, 19.03.2015. .

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 40

Jharkhand Coal Washeries: Facts

Ashish Gupta, Observer Research Foundation

Studies conducted ·         Before World War I, Prof. William Galloway conducted washing experiments on Assam coals.

·         Sometime later, Prof. Henry Louis of Newcastle conducted similar tests on Jharia coals.

·         In 1920, E.C Evans, a London based chemist conducted another similar tests on Jharia coals.

·         All of them were of the view that washing of Indian coal was not feasible.

Breakthrough Study ·         Mr. A. Farquhar, scientist from TATA conducted washability study during 1918 to 1924 on Jharia coals and come to the conclusion in 1938 that Bhowra, Jamadoba, Malkera coal can be washed economically.

·         Subsequently, TATA decided to construct two washeries: a) West Bokaro coal washery, 1951 b) Jamadoba washery, 1952

Setting up of the Board ·         After many washability studies were conducted, it was decided to set up a Coal Board in 1952.

·         Subsequently, the Coal Washing Committee suggested to construct four central coal washeries at the Raillway Marshalling yards at Patherdih, Dudga, Kargali and Bhojudih by the Second Five Year Plan.

Central  Washeries ·         The first central washery Dudga (I) was constructed in 1962 for washing Jharia coals. Subsequently another washery Dudga (II) was also constructed in 1968. When Dudga (I) completed its life span, it was converted to non-coking coal washery in 1998. It has the capacity to produce 2.5 Million Tonnes/ Per Annum (MT/PA).

·         Bhojudih central washery was constructed on south eastern fringe of Jhari Coal Fields and was one of the most successful in the country. This is due to the fact that coal quality was good. After then the good quality coal reserves depleted in Jharia southern mines and so the performance was also deteriorated. It has a washing capacity of 1.7 MT/PA.

·         The Patherdih central washery was constructed in 1964, again for washing Jharia coals. The washery faced several operational problems due to oversize lumps. The washing capacity of this washery is 1.6 MT/PA.

Key Facts ·         The Kargali washery, 1959 was constructed with Japanese collaboration with Hydraulic Medium Drum (2 stage) process. The washery was installed to reduced the overall washing coal cost. It has a washing capacity of 2.7 MT/PA.

·         Durgapur and Chasnalla washeries were installed in 1968 and 1969 respectively and were meant for captive coking coal sectors.  Durgapur was to supply washed coal to Durgapur Steel Plant whereas Chasnalla was linked to IISCO. Both washeries have washing capacity of 1.5 MT/PA.

·         In 1970 the Kathara washery was installed with Russian collaboration but due to excess capacity the washery worked at dauntingly low capacity since commissioning.  The washing capacity is 3 MT/PA.

·         Gidi washery was constructed in 1973 with Polish collaboration for delivering non coking wash coal for the Railways. But as the consumption of coal reduced for the railways, the washery was converted to coking coal washery. It can wash 2 MT/PA.

·         After the formation of Bharat Coking Coal Limited (BCCL) in 1972, two washeries – Sumadih in 1981 and Moonidih in 1983 were constructed for the government pit head plants. They were also erected with Polish collaboration and were expected to produce 2 MT/PA. Unfortunately these two washeries never achieved their production target. Both washeries have the washing capacity of 1.6 MT/PA.

·         Under the leadership of an eminent mining engineer, K. S. R. Chari, few more washeries units were proposed and consequently a washery in Barora was constructed in 1985 and another in Mahuda was constructed in 1986 as pit head units for Jahria coal fields. But due to substantial locking of coal at Barora washery area, it was dismantled in 1990s even though Mahuda was quite successful on account of easily washable coal availability from Raniganj coal areas. Mahuda washery had 0.6 MT/PA capacity.

·         Rajarappa washery was constructed in 1987 by the side of Rajarappa River but effluent pollution has been an issue for this washery. It can produce 3 MT/PA washed coal.

·         Piparwar washery which was constructed in 1997 was by and large had the most modern design and had the capacity to produce 6.5 MT/PA.

·         Nandan project washery was installed in 1984 at the Western Coalfield Limited. The uniqueness of this washery was that it was fully automatic and could produce 1.2 MT/ PA of washed coal.

·         BCCL installed Madhuban washery in 1998 but since the coal quality was poor it limited the operational capacity of the washery. It was therefore temporarily transformed to wash non-coking coal but recently it has reverted back to washing coking coal. The washery has a capacity of 2.5 MT/ PA.

·         Bina washery was constructed in 1999 as the first non-coking coal washery in the country at the Singrauli coal field. But since the National Thermal Power Corporation could not decide on the price of washed coal and so the washery had to remain idle for many years. Currently the washery is supplying washed coal to Dadri power plant. It can produce 4.5 MT/ PA washed coal.

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 41


Monthly Power News Commentary: August – September 2017


Reeling under accumulated debts with an obligation to pay fixed charges to the independent power producers (IPPs) in the state, the PSPCL has moved the PSERC, seeking permission to levy additional surcharge on the open access consumers who buy electricity from other sources. In its petition before the regulator, the PSPCL has sought that additional surcharge be made applicable on to the open access consumers for the period between October 1, 2017 to March 31, 2018. The PSPCL has also produced relevant data before the commission for computation of the surcharge. The PSERC has admitted the petition and asked the power corporation to publish a public notice inviting suggestions and objections from the general public and stakeholders on the issue. The PSPCL has contended that it has adequate generating capacities to meet the entire power demand, including the open access consumers, during the said period. In October 2016 – March 2017 period, the PSPCL had to pay about ₹ 41 billion as fixed cost. The corporation submitted that as per the Section 8.5 of the National Tariff Policy the surcharge was applicable under the existing circumstances.

State-owned discoms in Rajasthan are delaying LPS to wind power generators even after the state regulator directed them to clear all the dues within three months. The regulator had sent the directions in an order. The discoms have started disbursing payments against the principal amount due to power producers. However, the discoms are looking for a 50% discount on the pending late payment surcharge. In a meeting between the wind industry and distribution company, it was decided that the dues on the principal amount would be cleared within seven working days. Payments of about ₹ 1 billion have already been cleared and another ₹ 500 million will be paid in the ongoing week by Jaipur discom. Wind energy producers selling power to Rajasthan discoms had claimed that the latter are forcing them to sign consent for accepting only 50% of the LPS on long pending dues. When such consents are not signed, generators informed the RERC that discoms are not releasing the payments of even the principal amount. A segment of the industry had apprised RERC about the situation, stating that Rajasthan discoms have neither paid for the electricity supplied, nor have they paid any late payment surcharge. RERC directed the discoms to clear the dues, including LPS, to renewable electricity generators within three months.

Tamil Nadu has reduced electricity tariffs for industrial and commercial consumers. The Tamil Nadu Electricity Regulatory Commission (TNERC) has brought down CSS to the range of ₹ 1.6-2.5/kWh, the lowest among industrial states. The National Tariff Policy 2016 suggested a new formula for determination of CSS and capped it at 20 percent of the tariff. It also introduced an additional surcharge for these consumers when they shifted to sources other than the state’s discoms. Thus, while states where the industrial rates were low increased tariffs, Tamil Nadu, where commercial consumers were already paying high rates, decided to reduce the burden. CSS is levied by state discoms to recover the cost of supplying subsidised power to a section of the population. In the last financial year, CSS across a dozen states increased 30 percent to 600 percent. In a group captive scheme, one party develops a power plant and many commercial consumers benefit from it. The Commission also did not levy any additional surcharge on industry or increase energy and demand charges.

The Delhi Electricity Regulatory Commission (DERC) announced a hike in the “fixed charge” component of the electricity tariff for hi-end users, while maintaining that the usage charges will remain same as before. The electricity tariff is constituted of two components, fixed charge and energy charge. The fixed charge remains constant irrespective of the energy consumed, while energy charge varies according to the usage. The electricity regulator reduced the fixed charge for the low-end users having an electricity connection of 1 KW. Such users will now have to pay ₹ 20, instead of the earlier charge of ₹ 40 earlier, it said. There is no change in the fixed charge being paid by users with 2 KW connection, who will continue to pay ₹ 40 as before. All the changes are meant for domestic connections and not commercial ones.

IBA has sought the power ministry’s intervention to ensure that electricity tariffs are not renegotiated as that would hurt economic viability of projects and may lead to rise in bad loans. It draws attention toward states-owned power discoms which are looking to cancel or renegotiate the PPAs with coal based and renewable energy developers on the ground that tariffs contracted earlier were very high. It said that Uttar Pradesh has recently cancelled a few PPAs and also there were instances in the past where the developers were asked to voluntarily offered discount over the quoted tariff to facilitate of offtake from their plant. It further said the risk related to such tariff revision in the renewable sector is much higher and pointed out that in the recent auction for wind power projects some states have started renegotiating for downward revision of tariffs. The IBA has asked the power ministry to take up issues concerning power sector with the state government and discom and ensure that PPAs are neither cancelled nor renegotiated. States, IBA said, should be asked to honour commitments to renewable projects implemented under the state policy by executing PPAs/procuring power in a timely manner. It said that developers should not be pressurised to voluntarily offer reduction in tariff as it affects loan repayments decided on the basis of agreed price.

India is aiming to help its ailing power distribution companies by buying five million smart meters for two of its northern states in a global tender to be conducted later this month. Energy Efficiency Services Ltd (EESL), the government agency responsible for running the country’s energy efficiency programs, will conduct the tender.  If successful, the program could be adopted by a large number of states, he said. For India, smart meters represent a possible game-changer by handing power distribution companies the ability to address billing inefficiencies that have contributed to their losses and debt burden. A smart-meter is an electronic device that records electricity consumption at short intervals and communicates it back to a utility for monitoring and billing. Most of India’s power discoms lose money on every unit of power sold due in part to theft, inadequate billing and selling below cost to poor and agricultural consumers. State-run distributors held combined debt of ` 4.3 trillion ($67 billion) as of September 2015, the latest year of available data. The debt levels limit their ability to adequately meet the power demands of existing customers or add new consumers in a country where millions of households don’t have electricity, but where power plants also remain underutilized. The average technical and commercial losses at discoms in 24 states who’ve signed up under a reform plan currently stand at 21 percent, according to the government. Last year, the Indian government said it’s aiming to outfit approximately 35 million customers with smart meters by the end of 2019.

Niti Aayog doesn’t seem to be content with the plan to make India move around in electric cars and buses by 2030. The government’s policy think-tank has now offered the Centre something to chew upon: make kitchens in cities with reliable power supply — think Mumbai, Kolkata and Delhi — switch over to ‘electric cooking’ and free up gas connections for the poor. But it seems to build upon the Narendra Modi’s government’s progress towards fulfilling its promise of 24×7 affordable power supply. Uinterrupted 24×7 power supply is still limited to a few cities.

TPDDL, the Tata Power subsidiary that distributes power in Delhi, launched a mega drive to rollout smart metering services for its consumers. The firm is rolling out 250,000 smart meters in the first phase of its Advanced Metering Infrastructure (AMI) project. A smart meter enables two-way communication between the meter and the central system giving consumers greater control over use of electricity by providing detailed information about usage and consumption patterns helping them in planning expenses better. The meters also help in faster outage detection and restoration of service. Smart meters also help pave the way for a smart grid which will act as a backbone for the Smart City Mission. The first phase of the project is being implemented in partnership with the global energy management firm Landis+Gyr. The Phase will include putting up 50,000 Three Phase Meters and 200,000 Single Phase Meters. Its rollout will happen between March 2018 and March 2019. TPDDL is also planning a second phase which will have 500,000 Single Phase and 50,000 Three Phase Meters, due to get started from April 2019. The total replacement and completion of 1.8 million smart meters will be done by 2025.

After a relief of over two years for consumers, the PSERC has started the process to hike power tariffs. Revision of tariffs is likely in view of the poor financial health of the PSPCL, which is reeling under a debt of over ₹ 250 billion. The PSPCL has already filed a petition seeking a hike of around 20% in power tariff. The deferring of tariff hike has added to the financial burden on the PSPCL. The income from the sale of electricity was the main source of revenue for the corporation and the authorities had almost run out of other options. As per the MYTP, there is a total revenue deficit of ₹ 115.75 billion, including ₹ 59.98 billion carried forward from the previous years, which had been mentioned as a major reason for seeking the tariff hike. In the MYTP, the corporation has shown a deficit of ₹ 61.30 billion for 2018-2019 and ₹64.06 billion for 2019-20. Last year, the PSPCL had sought a tariff hike of 19.72% amounting to ₹ 1.56/kWh to bridge the revenue gap. The corporation had estimated revenue receipts of ₹ 261.21 billion against the estimated expenditure of ` 312.62 billion. However, the tariff hike was denied by the state government. With the Chief Minister Amarinder Singh announcing power to industries at ₹ 5/kWh, the PSERC will work out the cost of the electricity supply and ask the government to pay the subsidy for the gap. Last year the average cost of supply had been worked out at ₹ 5.97/kWh.

Power generators stayed away from bidding for Gujarat government’s tender to acquire 1,000 MW of cheap electricity by selling coal at lower rates after the government allowed flexibility in utilisation of domestic coal amongst power generating stations. Gujarat Urja Vikas Nigam had floated a tender for 1,000 MW to be supplied to the state for nine months beginning October 2017, wherein the independent power producers must quote a price lower than the ceiling price of ₹ 2.82/kWh and get coal that was originally allocated for the state. But the power producers said the ceiling of ₹ 2.82/kWh makes the bid unviable, raising concerns over other such tenders which are in the pipeline.

In an attempt to improve availability of cheap coal to power plants which are lying idle or running at low capacity, the government approved flexibility in utilisation of domestic coal among power generating stations. This move allows states to consider the aggregate coal available to it and sell it to more efficient power plants. Maharahstra too has invited bids for similar tender and its ceiling price is even lower at ₹ 2.80/kWh.

The GMR Group, which owns a 220 MW gas based power plant in Andhra Pradesh’s Kakinada, will sell its barge-mounted power plant to a buyer for $63 million. GMR Energy Ltd will enter into a definitive agreement with the buyer soon. According to GMR, the plant is operational since November 2001 and redeployed at Kakinada since April 2010. The company is exploring various commercial options for the plant, which did not generate power since 2013 due to shortage of natural gas. According to the latest investor presentation of GMR Infrastructure, said the project cost of the plant was $90 million (₹ 6 billion).

An Indian company has won the tender for construction of 1000 Electricity Transmission and Trade Project for CASA. The company, which has won the tender Afghanistan’s Ministry of Water and Energy, said it will complete the construction of the project in three years. The construction phase of the project will cost around $404 million, of which 80 percent will be funded by the World Bank and the remaining 20 percent will be paid by the Afghan government. The CASA-1000 project will include a 750 km high voltage direct current (DC) transmission system between Tajikistan and Pakistan via Afghanistan, together with associated converter stations at Sangtuda (1,300 MW), Kabul (300 MW) and Peshawar (1,300 MW). The 477 km 500 kilovolt alternating current facility will run between the Kyrgyz Republic (Datka) and Tajikistan (Khoujand).

Tata Power said it has become the first power utility to introduce a QR code based bill payments system in India. The company said though this functionality of bill payments through a QR code has been introduced in other service industries, it will be launched in the power industry for the first time in India by Tata Power. According to the company, the QR code linked to (UPI will be printed on the electricity bills. The customers can scan the QR code with BHIM app or any other UPI linked bank app and pay their bills without any hassle, it said. The bill details will be displayed on the app, post which the customer can authorise the payment within a few seconds and his bill will be paid instantaneously. Some of the advantages of QR code service are that the consumer need not visit any Tata Power bill collection/ customer relation centre or any other payment avenues and can make the payment from the comfort of his home/office or on-the-go. Besides, all bill details will be auto captured while scanning the QR code and the consumer has to pay using a single tap on his smartphone. The consumer also need not remember his debit/credit or net banking account and IFSC code details.

Farmers whose agricultural land is acquired for erecting high-tension power transmission towers will now get compensation. Uttar Pradesh Electricity Regulatory Commission (UPERC) has recently issued a direction in this effect. Currently, only crop compensation is awarded to farmers on whose land power transmission towers are erected. However, no land compensation is awarded in the state. This is despite the fact that the land which is covered by the tower base of an electric tower cannot be used for any useful purpose. The Commission’s directive is in concurrence with the already laid down guidelines issued by the Union power ministry with regard to “reasonable and appropriate” compensation to landowners as they suffer on account of such erection of high-tension power lines on their land. The directive was issued in the wake of several petitions in favour of land compensation due to erection of transmission lines. While states such as Odisha, Maharashtra, Uttarakhand, Punjab, West Bengal, Bihar, Karnataka, Kerala, Jharkhand have already adopted these guidelines of the Union government, Uttar Pradesh is yet to implement the same. A parliamentary panel has recommended that a village should be declared electrified only after providing power connections to all households. At present, all those villages with 10 percent families with electricity connection can be declared electrified under the government’s rural electrification programme. The Centre has electrified 14,125 villages out of 18,452 identified electrified villages in the country under the rural electrification programme so far, as per its web portal. The panel said that a village should not get a tag of being electrified in any case when the household coverage is less than 80 percent. The panel also pitched for segregation of commercial and technical losses to reduce quantum of aggregate technical and commercial losses.

Rest of the World

China’s state planner, the NDRC, will launch a pilot scheme to allow the spot trading of electricity in eight regions as part of long-planned reforms to liberalize the power market. These scheme will take effect in Guangdong, Inner Mongolia, Zhejiang, Shanxi, Shandong, Fujian, Sichuan and Gansu, the NDRC said. The new pilot program came after the country previously allowed trading of long-term electricity contracts. The NDRC said spot trades will be launched by end of 2018.

China said it will set new power transmission prices by the end of October, in its latest effort to liberalise the power market and promote trading of electricity across different regions. Beijing has made a series of moves to open up the country’s monopolised power market since late 2015, including launching a power trading scheme for eight provinces and reducing power distribution prices. Power grid operators charge utilities transmission fees to transport electricity within a region as well as between regions. The NDRC said it will announce transportation prices on the major West to East power grid by October and revisit prices every three years. Under recent market reforms, utilities in western regions, such as Xinjiang and Ningxia, are now able to sell electricity on the east coast, but they complain transmission fees are too high, which makes them uncompetitive with local utilities.

PSPCL: Punjab State Power Corp Ltd, PSERC: Punjab State Electricity Regulatory Commission, discoms: distribution companies, LPS: late payment surcharge, RERC: Rajasthan Electricity Regulatory Commission, CSS: cross-subsidy surcharges, kWh: kilowatt hour, KW: kilowatt, IBA: Indian Bank’s Association, PPAs: power purchase agreements, TPDDL: Tata Power Delhi Distribution Ltd, MYTP: multi-year tariff petition, MW: megawatt, CASA: Central Asia and South Asia, UPI: Unified Payments Interface, NDRC: National Development and Reform Commission

Courtesy: Energy News Monitor | Volume XIV; Issue 14


Monthly Coal News Commentary: August 2017


Though most of the news on coal was negative BMI Research, a unit of Fitch Group lightened the mood with optimistic projections. According to BMI, coal will remain the foremost fuel preference for India’s power sector and is expected to account for around 68 percent of the total power mix by 2026. It said India’s power sector will expand rapidly over the coming decade, driven by underlying economic growth, electrification efforts and power sector reform implemented by the government. The report said overall, reform in the mining sector since 2015 has drastically improved the availability of coal for the power sector. However, feedstock volatility will remain a downside risk to coal-fired power generation over the coming years.

On the other hand, academics suggested grim prospects for coal. In the last two years, coal consumption has slowed to its lowest level in two decades. Tim Buckley, the Asia energy finance director for the Cleveland-based Institute for Energy Economics and Financial Analysis, lays out a scenario where India’s coal consumption might come close to peaking within the next decade if not sooner.  India is the world’s third-largest carbon emitter and relies on coal-fired power plants to produce most of its energy. The rate of increase in coal consumption in India is now the slowest it’s been since 2000, apart from an anomalous 1% rate of growth in 2011. Last year, it dropped to 1.5% from the decade’s average of 6%. This year, it is slightly higher at 2.8%. By washing coal before it’s burned, India’s power plants now burn less to produce the same amount of power. India is also now policing rail shipments more rigorously to reduce coal theft. And new plants are required to use so-called supercritical technology that further raises the efficiency of coal burned while also reducing pollution. Thanks to such efficiency boosting measures, the amount of coal needed to deliver a 6% rate of growth in electricity demand will drop even further, and may be near flat, Buckley said.

Things are not looking good on the import front as well. China’s imports of coal from the seaborne market surged again in July, providing a stark contrast to a fourth consecutive monthly decline for India. India, which gave back the title of the world’s top coal importer to China last year, has a stated policy of reducing coal imports to zero and is boosting domestic production and efficiency of distribution toward that end. It’s further likely that much of the reduction in India’s imports have been for lower-quality Indonesian coal, which would struggle to find buyers elsewhere. This makes watching China’s imports key for the outlook for prices, since this appears to be driving the market more than India’s slumping appetite for coal. Import of coal saw a decline of 6.37 percent to 191.95 mt in 2016-17 on higher production CIL that saw the country move to a regime of surplus coal. Comparatively, in 2015-16 fiscal, coal imports stood at 203.95 mt, as per official data by the government. As against the demand of 884.87 mt of coal, the total domestic production stood at 659.27 mt. The ongoing fiscal also shows a declining trend, especially of thermal coal. Thermal and steam coal imports have fallen 17.37 percent at the top 12 major ports to 29.82 mt during April-July this fiscal, according to the IPA. The ports, under the control of the Centre, had handled 36.09 mt of thermal and steam coal during the same period of the previous fiscal. Handling of coking coal, used mainly in steel-making, has also dipped 4.45 percent to 16.51 mt, as per the latest data released by the IPA. These ports had handled 17.27 mt of coking coal in April-July period of 2016-17. Together, they handled 46.33 mt coal during April-July this fiscal as against 53.36 mt in the same period of the previous year. India is the third-largest producer of coal after China and the US and has 299 bt of resources and 123 bt of proven reserves, which may last for over 100 years. The country has 12 major ports – Kandla, Mumbai, JNPT, Marmugao, New Mangalore, Cochin, Chennai, Ennore, V.O. Chidambarnar, Visakhapatnam, Paradip and Kolkata (including Haldia) which handle approximately 65 percent of the country’s total cargo traffic.

Taking not of the decline in demand growth, CIL has decided to shut nearly 100 unprofitable mines over the next two-three years. Of this, 37 will close operations this year. Last year, CIL closed down over 15 mines. A recent study showed that about 15 mines are highly profitable and 90 others can be made profitable. The company said opening new mines and shutting unviable ones is a continuous process. CIL began with 750 mines but now has 394. Low grade coal extracted from mines that produce less than 1 mtpa are generally considered unprofitable as the scale of operation in them do not support the cost involved visà-vis the price its coal fetches. CIL has also been recently hit because the Coal Controller of India downgraded 50% of its 394 mines, meaning they are fetching lower prices for the coal produced compared to what they were fetching in 2016-17. CIL expects a hit of about ₹ 100 billion annually as a result of downgrading.

The Centre’s programme of ensuring coal for stressed power units has failed to generate much interest on the part of power developers. Not a single bid was put in in the first tender called by Gujarat to provide the cheap coal earmarked for the state. Private developers who buy this coal have to sell power at ₹ 2.82/kWh or less. They will get coal after they bid for a discount on the notified rate. The reverse auction was held for procuring 1,000 MW. The aim is to reduce the cost of fuel for ailing distribution companies and effectively distribute domestic coal.

Extending the deadline for submitting bids by 20 days did not change the outcome. It is believed that the cap on tariff was not viable. In May last year, the Cabinet had approved the proposal for allowing flexibility in utilising domestic coal among power-generating stations. Under the new policy, the coal requirements of a state will be clubbed and assigned to the respective state/state-nominated agencies. The state will award coal linkage in accordance with the need, efficiency, and the cost of power to power plants in its jurisdiction. The policy also allowed for coal swaps between inefficient and efficient plants and from plants situated away from coal mines to the pit head to minimise the cost of coal transportation, leading to reduction in the cost of power. For the centrally owned power plants, coal linkages of CGS will be clubbed and assigned to the company owning the CGS. In the case of state/central generating plants, the deciding criteria will be plant efficiency, coal transportation cost, transmission charges, and the cost of power. IPPs have to bid for coal linkages. The basis of bidding would be the source of coal, quantity, the amount of power generated, and the delivery point for the receipt of power.

According to data from the CEA, coal-powered GSECL plants’ power sale price range between ₹ 2.92–₹ 5.42/kWh. In the first quarter of FY18, the average plant load factor of thermal power plants of GSECL was 45.4% only. They produced 585 million units of power in the period against the target of 6,055 million units. To meet the state’s demand of about 8,000 MW, the state imports about 1,600 MW from other sources, while the rest is generated from within the state. The state has also opened tenders to purchase 500 MW of power between September 16 and October 15. It has also invited bidders for 500 MW each of wind and solar power. Gujarat will sign 25-year power purchase agreements with the lowest bidders in the respective renewable segments.

The government has annulled the fifth round of coal mines auction due to poor response from bidders. According to the government, the fifth round of coal blocks auction has been annulled as there was not good response from the bidders because the steel industry is in a bad shape. Six coking coal blocks were to go under the hammer in the fifth round, five of which are in Jharkhand and one in Madhya Pradesh. The six coal mines are: Brahmadih, Choritand Tiliaya, Jogeshwar and Khas Jogeshwar, Rabodih OCP and Rohne in Jharkhand, and Urtan North in Madhya Pradesh. In December 2015, the government annulled the fourth round of coal mine auctions planned for January 2016 on account of tepid response from bidders in sectors such as steel besides depressed commodity prices and adverse market conditions. The Centre earlier announced that it would auction six coking coal mines. CIL which produced 55.22 mt of coking coal last fiscal is eyeing 59.77 mt of metallurgical coal in the ongoing financial year. CIL, which accounts for over 80 percent of the domestic coal production, is eyeing 63.55 mt coking coal in the next fiscal and 72.30 mt in 2019-20. In FY16, India imported 43.51 mt of coking coal and 43.71 mt of fuel used in steel-making in FY15.

UP has sought the Centre’s help so that some private and state-owned power plants can come out of critical coal-stock scenario. UP has requested the centre to increase the quantum of coal supply to private power plants such as 1,980 MW Lalitpur plant and 1,200 MW Roja plant and state utility-owned generating stations such as 665 MW Harduaganj plant and 1,140 MW Parichha power plant. It has also asked the CEA to include IPPs in the state in the ‘critical’ category. This would make CIL supply sufficient coal to such plant so that they have comfortable fuel stock, just the way CEA has included some state utility and NTPC Ltd plants in the list.

Coal supplies are expected to improve significantly beginning 2018, riding on the completion of key rail projects in Odisha, Chhattisgarh, Madhya Pradesh, UP and Jharkhand. In Odisha, the CIL financed 53.5 km Jharsuguda-Barapali rail link is expected to be ready by December; paving the way for moving nearly 80 mt of additional fuel from the vast Ib Valley reserves in Sundergarh district. The Railways is on course to resuming work on the 30 km Talcher-Angul loopline to pace up supplies from the Talcher coalfields. The project has been stalled the last five years due to land acquisition issues for a 3 km stretch. The Railways has finally made some headway in land acquisition. The project is now expected to be completed next year. The loopline will help circular movement of rakes, thereby increasing the pace of evacuation from Talcher by 50-60 percent. CIL now despatches 30-35 rakes a day from Talcher. The loopline is expected to increase this to 50 rakes a day. According to CIL, construction is apace and should link up the opencast mines at Chhal and Baroud by next year, adding approximately 20 mt to the miner’s annual throughput. This line is to be extended to the prolific Gare Palma coalfields. The coal ministry has asked the Railways to double the 25 km single-line connectivity between Shakti Nagar in UP and Karela in MP. Karela is located on the Katni-Chopan line connecting eastern India with the North. This will help improve supplies by approximately 30 mt annually from Northern Coalfields, a subsidiary of CIL.

CIL said that 62 coal projects, out of 120 ongoing projects, were not running on schedule mainly due to delay in obtaining forest clearances, acquiring land and issues related to rehabilitation and resettlement. Out of 71 non mining projects, 27 are delayed. As many as eight coal mining projects for an ultimate capacity of 56.25 mtpa and a total capital investment of ` 89.31 billion have been sanctioned by CIL board during the last financial year.

CIL is looking to offer tentatively close to 138 mt of coal through various e-auction schemes in the current fiscal, according to miner’s e-auction calendar from 2017-18. The e-auction schemes include spot, special forward for power and exclusive for non-power sector. The miner’s seven fully owned subsidiaries ECL, BCCL, CCL, NCL, WCL, SECL and MCL, have given their “tentative” and “provisional” offer for the schemes during the current financial year, which may be revised in accordance to the bidding of coal and as per demand. Of the total tentative amount, SECL would likely offer close to 30 mt while CCL plans to offer around 46 mt. Similarly, WCL is expected to offer around 19.54 mt, MCL to offer about 16.77 mt and NCL to 12.75 mt. BCCL and ECL are expected to offer around 6.36 mt and 7.3 mt respectively. SECL in its offer said that it had already offered 14.3 mt in the first quarter of FY 18 for various e-auction schemes. It also said out of the total offering in the year, it would likely to offer 18.3 mt for spot e-auction, 8.6 mt for special forward for power sector and 3.2 mt for exclusive e-auction for non-power sector. Similarly, CCL said it would tentatively offer 16 mt for special forward, 10 mt for exclusive, 4 mt for special spot and 16 mt for spot e-auctions during August 2017 to March 2018 period.

Rest of the World

China’s state planner, NDRC said it will force power companies to beef up stockpiles of coal during peak demand seasons as part of draft rules setting out the government’s new inventory system. During winter and summer, power companies’ coal inventories must be five to 10 days above normal levels, the NDRC said as it outlined the draft policy. The policy is the latest effort by Beijing to ensure sufficient supplies of coal during periods of high demand, and comes after the government had to scramble last year to avert a national power crisis following government-enforced cutbacks in coal output. The NDRC will now seek feedback from the industry until September 10.

China Shenhua Energy Company Ltd has suspended operations at two large open-pit coal mines in northern China, it said, a move that could benefit producers across the border in Mongolia. Shenhua Energy, the listed unit of the state-owned Shenhua Group, China’s biggest coal producer, announced that the Ha’erwusu and Baorixile mines in Inner Mongolia had been temporarily suspended as a result of “land requisition” delays. The two mines produced more than 50 mt of coal in 2016 and over 30 mt from January to July this year, the firm said. Coal is Mongolia’s biggest export product. The country’s total coal earnings rose fourfold to $1.28 billion over the first half of 2017 because of China’s ban on North Korean imports and port restrictions. Mongolia’s largest coal producer, the state-owned Erdenes Tavan Tolgoi, said that it produced 5.9 mt in the first seven months of the year, or 4.6 times more than the same period of 2016.

China’s trade with North Korea fell in July from a month earlier, as a ban on coal purchases from its isolated neighbour slowed imports amid growing pressure from the United States to rein in Pyongyang’s missile program. The world’s second-largest economy imported and exported goods worth $456 million in July, down from $489 million in June, according to data from China’s General Administration of Customs. The data indicates that China’s move to halt North Korean coal imports in February has crimped Pyongyang’s ability to raise hard currency through exports.

Glencore said it was looking to sell a second Australian coal mine, part of the Swiss-based resource giant’s rethink on how it deploys capital as its reins in debt and commodities prices rise. Together with its Japanese joint venture partners, Itochu Corp and Sumitomo Corp, Glencore said it would start a “sales process” for its Rolleston mine, which produces thermal coal used for making electricity. The mine, though, is geographically removed from Glencore’s main collieries, leaving it less economic from a shipping standpoint. Merrill Lynch has been appointed as sole financial adviser on any deal, Glencore said. In May, Glencore also put its wholly-owned Tahmoor coking coal mine in Australia up for sale, citing a desire to concentrate on mining thermal coal. Glencore isn’t the only Australia seller of coal mines.

Net profit at Polish coal mines increased in the first half of the year compared to a year earlier amid higher coal prices and restructuring. Coal stocks put aside at the mines declined to 1.9 mt from 5.2 mt a year earlier, the agency said. Coal output fell to 32.7 mt in the first six months of 2017 from 34.3 mt last year. The ruling Law and Justice party (PiS) has simplified the structure of Poland’s biggest coal miner PGG, formerly known as Kompania Weglowa, and bailed it out with the help of state-run utilities, including the biggest power producer PGE. As a result, the number of employees in the Polish coal mining industry fell by 3,000 people since the start of 2016 to 81,700 as of end June 2017.

Colombia’s coal output fell 6.95 percent to 21.4 mt in the second quarter from a year earlier, the national mining agency said. The Andean nation, the world’s fifth-largest coal exporter, produced 23.07 mt in the second quarter of 2016. The sector is seeking to produce 95 mt this year. The biggest players in Colombia’s coal industry are Drummond Co, Glencore Plc, Murray Energy Corp’s Colombia Natural Resources and Cerrejon, which is jointly owned by BHP Billiton, Anglo American PLC and Glencore.

Burning coal for power looks set to remain the backbone of Germany’s energy supply for decades yet, an apparent contrast to Chancellor Angela Merkel’s ambitions for Europe’s biggest economy to be a role model in tackling climate change. Merkel is avoiding the sensitive subject of phasing out coal, which could hit tens of thousands of jobs, in the campaign for the September 24 election, in which she hopes to win a fourth term. Although well over €20 billion are spent each year to boost Germany’s green energy sector, coal still accounts for 40 percent of energy generation, down just 10 points from 2000. To avoid disruption in the power and manufacturing sectors, coal imports and mines must keep running, say industry lobbies, despite the switch to fossil-free energy. He also stressed it was crucial for steel manufacturing in Germany, the seventh biggest producer in the world, that use a quarter of the country’s coal imports. Utilities such as RWE, Uniper and EnBW with coal generation on their books fire back by saying their output is covered by them holding carbon emissions rights.

CIL: Coal India Ltd, kWh: kilowatt hour, MW: megawatt, mt: million tonnes, bt: billion tonnes, IPA: Indian Ports Association, CEA: Central Electricity Authority, GSECL: Gujarat State Electricity Corp Ltd, CGS: central generating stations, FY: Financial Year, UP: Uttar Pradesh, R&R: rehabilitation and resettlement, km: kilometre, NDRC: National Development and Reform Commission, ECL: Eastern Coalfields Ltd, BCCL: Bharat Coking Coal Ltd, CCL: Central Coalfields Ltd, NCL: Northern Coalfields Ltd, WCL: Western Coalfields Ltd, SECL: South Eastern Coalfields Ltd, MCL: Mahanadi Coalfields Ltd

Courtesy: Energy News Monitor | Volume XIV; Issue 13


Monthly Gas News Commentary: August 2017


GAIL (India) Ltd is seeking to renegotiate price of the LNG it has contracted from the US following a similar one with Australia, to reflect current market realities. GAIL has signed three time-swap deals to sell some of its US LNG as it rejigs the supply portfolio in line with domestic demand. Under the deals, the company will buy LNG from international companies this year and sell equivalent amount of Henry Hub-indexed volumes during 2018-19. It is also seeking destination swaps to cut shipping costs of US LNG. GAIL has a deal to buy 3.5 mtpa of LNG for 20 years from Cheniere Energy of US and has also booked capacity for another 2.3 mtpa at Dominion Energy’s Cove Point liquefaction plant. GAIL had contracted LNG from US to meet the demand of growing Indian economy with power sector being considered as a major buyer. But electricity produced using imported LNG is not finding buyers due to cheaper alternatives including renewables, leading to stranding of significant capacity out of 25,000 MW of installed gas based power plants. Under the agreement, it will get 15 cargoes or about 0.8 mt of LNG from an unnamed trader this year. In return, GAIL will sell 10 cargoes or about 0.6 mt next year from Sabine Pass on the US Gulf coast. GAIL had separately signed a deal with Royal Dutch Shell to sell about 0. 5 mt of its US LNG. The LNG that GAIL will receive this year between April and December under the time-swap deal will be at oil-linked prices. The sale of US gas next year will be at a premium to its pricing formula on a FOB basis. GAIL is trying to market LNG to anchor customers such as refineries, steel plans along planned and existing pipelines. It is also in talks to supply LNG to new fertiliser plans and expect firm agreements in 2017.

GAIL had agreed to pay Cheniere a price of $3/mmBtu plus 115 percent of the final settlement price for the New York Mercantile Exchange Henry Hub natural gas futures contract for the month in which the relevant cargo is scheduled. GAIL wants the fixed portion to be lowered to bring down landed cost of LNG to around $7-8/mmBtu against the present $9.7/mmBtu. LNG in the spot or current market is available for less than $6/mmBtu. GAIL had previously sought reopening of the August 2009 deal for import of 1.44 mtpa of LNG for 20 years from Australia’s Gorgon project. In 2015, India renegotiated price of the long-term deal to import 7.5 mtpa of LNG from Qatar, helping save ₹ 80 billion.

Experts said that GAIL was praised for being one of the first agencies to sign for what was presumed be cheap US gas supplies is now being criticised for being hasty.

The government will seek global investor participation for its ongoing mega oil O&G auction during the international SPE Offshore Europe conference to take place in Aberdeen, UK next month. A special event by the Indian government will show case the OALP, NDR and the latest investment opportunities in the Indian O&G sector. The move by the government has the potential to attract investors in the auction which has already received over 45 EoI in more than a month, according to the DGH. The oil ministry is offering over 85 percent of the country’s 3.14 million km2 of hydrocarbon sedimentary area under the new bidding mechanism of OALP and a revamped exploration policy HELP. The new OALP bidding mechanism under HELP allows investors to bid for acreages throughout the year. The current auction under HELP follows the just-concluded DSF bidding rounds under which 31 blocks were awarded to around two dozen mostly small-sized firms.  Experts were uncertain about the response to the initiative in an environment of low oil prices and declining demand growth for oil.

ONGC plans to double gas production to over 100 mmscmd in the next 5-6 years. Despite tumbling oil prices in the last three years, ONGC not only sustained production from existing fields through incremental inputs but has also taken large meaningful and calculated investment decisions to ensure sustained volumes and financial growth. Government is targeting increase in share of gas in the energy basket from 6.5 percent to 15 percent in the next few years. 17 projects with a combined capex of ₹ 760 billion have been approved in the last three years. Its flagship project includes Cluster-II in Bay of Bengal block KG-DWN-98/2 (KG-D5). The project would produce about 25 mt of oil and 50 bcm of gas over the life of the project with peak production of 4 mt of oil and 5.5 bcm of gas. This would be equivalent to 17 percent and 24 percent of ONGC’s current standalone oil and gas production, respectively. During the last three years, ONGC completed 15 production related projects (including 8 brownfield and 7 greenfield) with capital investment of 540 billion.

The CCI is investigating at least seven cases of alleged abuse of dominance by GAIL in dealing with its customers, the outcome of which could potentially redraw the rules of the gas marketing business in India. The Commission has clubbed for investigation two cases from this year and five from the previous year in which customers – Rathi Steel, Mohan Meakin, Rico Auto, Omax Autos and Rico Castings -have alleged GAIL abused its dominant position by incorporating unfair terms and condition in the GSA and imposing ToP liability. ToP requires customers to pay for 90% of the contracted volume even if it lifts less in a year although the un-lifted amount can be taken later. GAIL has denied allegations by customers. The investigation would examine almost every aspect of GAIL’s procurement, price determination, the way company imposed take-or-pay liability on all customers in 2015, and how it commits ToP liability to its upstream customers. The complainants have alleged that many of the provisions related to the quality of gas or the purchase terms favour GAIL more than customers. The most important dispute is linked to the imposition of the take-or-pay liabilities on customers for the year 2015, when changes in the global market had made long-term gas more expensive than spot, encouraging more consumers to switch to spot where possible.

Rest of the World

China has beaten expectations in its drive to help clear the nation’s notoriously smoggy skies by burning less coal and oil in favor of cleaner natural gas. Gas consumption has risen 15 percent in the first half of the year, including a 27 percent jump in June, as industrial customers shift toward the fuel and as distributors add more residential users. That surge during the traditionally low-demand part of the year raises the possibility that the country may find itself short of gas when winter hits. China’s drive to use more natural gas and renewables has seen coal’s share of the energy mix drop to just below 60 percent during the first half of the year, according to the National Energy Administration. It accounted for 64 percent in 2015, and the government is aiming for 58 percent by 2020. China’s natural gas demand will rise to 620 billion cubic meters a year by 2030, China National Petroleum Corp said. The country used 206 bcm last year, according to the National Development and Reform Commission. China’s gas prices are set by regulators, and they’re among the highest in the world by a major gas consumer.

China is likely to build two shale gas bases in the south of the country and open up tenders for more O&G exploration blocks in the world’s biggest energy producer. China is likely to start commercial production of shale gas in southern city of Anye in Guizhou province and Yichang in Hubei province. The steps come as China ramps up its exploration efforts as crude oil production from ageing wells drops. Beijing is also on a mission to lift natural gas consumption to help combat smog. In the north of the country alone, China’s crude oil and gas exploration efforts cover a vast 500,000 km2, with new natural gas and light crude reserves having already been discovered there. In the shale gas expansion, China is seeking to encourage private firms to take part in a tender for shale gas exploration right in Guizhou.

South Asia, long a backwater for energy markets, is emerging as a hotspot for LNG, with Pakistan and Bangladesh set to join India as major consumers, helping to ease global oversupply that has dogged this market for years. Only India and Pakistan currently import LNG in South Asia, taking in a combined 25 mt or 8 percent of global demand last year. But with a fast growing population, strong economic growth and soaring energy demand, more import projects are being developed, lead by Pakistan and Bangladesh. Pakistan only started importing its first LNG in 2015, and surprised some in the industry by developing its first terminal within schedule and budget. A second is about to become operational and a third is expected to be completed next year.  Bangladesh expects to import around 17.5 mt of the LNG  per year by 2025. The country expects to begin bringing in LNG cargoes via two floating import terminals by July next year. Bangladesh was in talks with Qatar’s RasGas and Indonesia’s Pertamina for long-term supply deals, while it also planned to import significant amounts of its future demand via the freely traded spot market.

Asian spot LNG prices rose as South Korean importers and Taiwan showed appetite amid a flurry of cargo offerings from projects across Asia and the Atlantic. Spot prices for September delivery rose to $5.90/mmBtu 15 cents above. Korea Gas Corp, one of the world’s biggest LNG importers, is expected to seek several cargoes via tender, alongside smaller peer SK E&S. Chevron’s new Wheatstone LNG project is due to export first LNG in September, according to trade sources, while the fourth production line at Cheniere Energy’s Sabine Pass plant appears to have begun liquefying gas, based on higher feed-stock flows.

New US sanctions will make it harder for Russia to build two gas export pipelines to Europe but the projects are unlikely to be stopped. Gazprom’s two big pipeline projects may go ahead, although at a higher price and with some delays. The Kremlin, dependent on oil and gas revenues, sees the pipelines to Germany and Turkey – Nord Stream 2 and TurkStream – as crucial to increasing its market share in Europe. It also fears that Western partners – needed to develop the deepwater, shale and Arctic gas deposits that will fill the pipelines – will be scared off by sanctions.  While some US measures remain discretionary, they may take aim at the planned twin pipeline to the existing Nord Stream 1 link connecting Russia’s gas fields with Germany via the Baltic Sea, which could keep future US shale gas deliveries away. Nord Stream 2 is due to be completed in 2019 with a likelihood of helping Moscow boost its oil and gas revenue and market share in Europe, where gas resources are dwindling. European buyers could compete with those in Asia for LNG if they wanted to secure supply from the world market, where US cargoes were some 50 percent more expensive compared with European references prices. Comparing the full costs of US LNG at the US trading point Henry Hub with gas prices on the Dutch TTF for the coming months US prices are not competitive.  US domestic prices are cheap but it has to add liquefaction, shipping and regasification costs. The German Chancellor described Nord Stream 2 as a purely economic project, while Poland has challenged it in court and is seeking more US LNG to try to break its reliance on Russian supplies.

The US has succeeded in its efforts to keep countries from signing up to Russian gas as the development in Lithuania shows. Lithuania received its first spot shipment of LNG from the United States, the result of a deal aimed at reducing dependence on Russia and consolidating relations with Washington amid increased tension in the region. The government estimates it will import half of its gas consumption in 2017 as LNG, mostly from Norway’s Statoil. The rest will be imported via a gas pipeline from Russia. Gas prices in Lithuania dipped in 2014 as it opened the LNG terminal, ending the gas supply monopoly of Russia’s Gazprom. Polish state-owned trader PGNiG received its first US LNG shipment in July.

The last massive component of Australia’s $180 billion LNG construction boom arrived, stepping up a race between Anglo-Dutch giant Shell and Japan’s Inpex to start chilling gas for export in 2018. Company reputations are at stake, as well as first access to overlapping gas fields and Australia leapfrogging Qatar as the world’s largest exporter of LNG. The Ichthys Venturer, a floating production, storage and offloading facility, travelled 5,600 km from a South Korean shipyard and will be moored 220 km off Western Australia to handle condensate from the Ichthys field. Japan’s top oil and gas explorer, Inpex Corp, is running Ichthys, both the country’s biggest overseas investment and first LNG megaproject. First production, due by March 2018, will be more than a year behind target. Costs have ballooned more than 10 percent to $37 billion since the project’s approval in 2012. Nearby, Royal Dutch Shell’s $12.6 billion Prelude project – the world’s largest FLNG facility – is also behind schedule. Shell lost out on becoming the first producer of FLNG when Malaysia’s Petronas started up a smaller FLNG facility this year.

Egypt is planning to import 80 cargoes of LNG during the 2017-18 financial year that began in July, down from the 118 cargoes imported last year. Egypt has been trying to speed up the development of recent gas discoveries with a view to halting imports by 2019. Egypt expects to increase its LNG production by 28 mcm/day by the end of the current financial year to reach 6about 175 mcm/day. Gas production will get a big boost from Italian national oil company Eni’s Zohr field, discovered in 2015 with an estimated 850 bcm. That field is expected to come into production at the end of 2017 and will save Egypt billions of dollars in hard currency that would otherwise be spent on imports.

LNG: liquefied natural gas, FLNG: floating LNG, mtpa: million tonnes per annum, FOB: free on board, mmBtu:  million metric British thermal units, mt: million tonnes, bcm: billion cubic meters, mcm: million cubic meters, km: kilometre, MW: megawatt, LPG: liquefied petroleum gas, O&G: Oil and Gas, SPE: Society of Petroleum Engineers, DGH: Directorate General of Hydrocarbons, NDR: National Data Repository, GSA: Gas Sale Agreement, CCI: Competition Commission of India, DSF: Discovered Small Fields, OALP: Open Acreage Licensing Programme, EoI: Expression of Interest, HELP: Hydrocarbon Exploration & Licensing Policy, ONGC: Oil and Natural Gas Corp, mmscmd: million metric standard cubic meter per day, ToP: take-or-pay, TTF: Title Transfer Facility, UK: United Kingdom, US: United States

Courtesy: Energy News Monitor | Volume XIV; Issue 12