Monthly Gas News Commentary: May – June 2017


There is optimism on demand for gas that is driving imports but pessimism on production of domestic gas.  H-Energy, the Mumbai-based oil and gas arm of Hiranandani Group plans to invest more than ₹ 45 billion in the natural gas sector in five years to develop LNG re-gasification units on the west and east coast of India along with pipeline infrastructure. H-Energy is at an advanced stage of setting up an LNG re-gasification unit at Jaigarh port in Maharashtra. As part of its phase-1 plan, the company in 2017 signed an agreement with France-based energy company Engie to charter a FSRU. After phase- 1 of the project stabilises, the company will be setting-up a land based re-gasification plant with an annual capacity of 8 mtpa. Also, the company has already started work on Jaigarh to Dabhol tie-in pipeline which will carry natural gas to the gas grid of GAIL (India) Ltd at Dabhol.  The company has also approached PNGRB, for laying a 700 km pipeline to connect the East coast FSRU to major demand centres in West Bengal.

Fidelity Investments and Morgan Stanley Investment Management have increased exposure to Indian city-gas retailers, as the emphasis on clean fuels burnishes the outlook for the industry. The demand from investors has been so strong that Indraprastha Gas Ltd, which supplies to homes and vehicles in New Delhi, raised the cap on foreign ownership to 30 percent from 24 percent, and may increase it again to almost half. India’s largest city gas distributor Gujarat Gas Ltd, where Aberdeen Asset Management Plc is the biggest non-state investor, and Mahanagar Gas Ltd. have also seen an increase in offshore holdings. India’s gas demand is about a fifth of China’s due to weak domestic supply and poor infrastructure, though the government is trying to change this. Measures have been stepped up to improve air quality in cities by giving priority to distributors such as Indraprastha Gas for accessing cheaper local gas. Offshore holdings in Indraprastha Gas climbed to nearly 25 percent as of March 31, from about 21 percent a year ago, according to data. Aberdeen Asset Management held about 4.6 percent of outstanding shares in Gujarat Gas as of end-April. Foreign holdings in the company have climbed about 3 percentage points to 15.4 percent in the past year. Mahanagar Gas, which sells the fuel in the financial capital Mumbai and its suburbs, has seen stock in the hands of foreign investors increase nearly six times since listing last year. India’s government wants more urban households to use natural gas and LPG for rural users.

The supply side does not share the optimism of the demand side. ONGC has said that producing natural gas is no longer a profitable business for the company as the government-mandated gas price is significantly below the cost of production. The oil major has sought a review of pricing formula from the government. ONGC wants a floor or minimum price of natural gas be fixed at $4.2/mmBtu for the business to be viable. With the current price, it does not make economic or commercial sense for any company to invest in new fields or in augmenting production from existing ones. Fresh investment in unlikely if the price remains below the cost of production. In October 2014, the government adopted a new pricing formula using rates prevalent in gas surplus nations like the US and Canada to determine rates in a net importing country. Prices have halved to $2.48/mmBtu since the formula was implemented. India imports half its natural gas needs and the government is keen to cut import bill by raising indigenous production and ‘Make in India’. The price paid to domestic producers is less than half of the rate paid for import of gas. ONGC produces 80 percent of the 70 mmscmd which makes it the biggest gas producer in India. ONGC lost ₹ 50.1 billion in revenue on natural gas business, and about ₹ 30 billion in profit in just last one year.

GAIL said it has drawn up investment plans of ₹ 300 billion for expansion. GAIL is currently executing gas pipelines worth ₹ 200 billion and another ₹ 100 billion worth of lines are under various stages of evaluation. The pipelines under execution include Jagdishpur-Haldia line that will take the environment friendly fuel to the east. Current projects will be completed by 2019-20, taking GAILs pipeline network to 15,000 km from the current 11,000 km. The company has already spent capex of ₹ 21.8 billion in FY17 and plans to spend ₹ 42.6 billion in FY18 and ₹ 77.04 billion in FY19 towards setting up of pipelines, petrochemical and process plants. GAIL will get charge of the LNG block, while state-owned power producer NTPC Ltd would be the largest shareholder in the power block. The company reported 69 percent drop in fourth quarter net profit of ₹2.6 billion as it wrote down the value of its investment in Dabhol power plant. The company has taken up synchronised development of seven city gas distribution network projects at Varanasi, Patna, Jamshedpur, Kolkata, Ranchi, Bhubaneswar and Cuttack. The first LNG terminal at the east coast is also coming up in Dhamra in Odisha under a joint venture of public and private sector companies.

The oil ministry has formed all-powerful review committees to monitor performance of ONGC and OIL, and will have power to relinquish any oil and gas field for auctioning to private firms. Being dubbed as super-boards, the committees will be headed by the ministry’s upstream nodal authority DGH, and will review and monitor performance of areas given to ONGC and OIL on nomination basis. The two panels, one each for ONGC and OIL, will review from annual work programme and budget to declaration of a discovery as commercial as also reservoir and production performance, monitoring of development activities and collaborations with other explorers. The order follows ministry’s unhappiness with state explorers particularly on delays in projects linked to output enhancement. It has already ordered a detailed review of board of directors of ONGC for a possible revamp of the functional heads. ONGC produced 86 percent of its 26.13 MT of crude oil in 2016-17 fiscal from fields given to it on nomination basis. Natural gas production from nomination fields accounted for 93 percent of the total output of 25.34 bcm. The review committee will meet at least once every three months. Field development plans, feasibility reports of commercial discoveries in nomination fields and monitoring of development activities for early monetisation will also fall within the ambit of the committees. The visible hand of government commanding and controlling the oil sector is unlikely to produce more oil than what the invisible hand of the market can produce.  Even if the invisible hand favours production, nature’s visible hand that dealt India its meagre hydrocarbon has set limits on what can be produced.

The ongoing rupee surge coupled with continuing price reductions of gas will push fuel cost down by around 5 percent, which in turn will lower the gross margins of upstream oil and gas players and deter fresh investment into the sector, Ind-Ra said. For the fifth consecutive time since implementation of the domestic gas pricing formula in November 2014, the government in March lowered domestic gas prices by 0.8 percent to $2.48/mmBtu. The price will be in force from April 1 to September 30, 2017. The price ceiling for gas produced from discoveries in deep-water, ultra-deep water and high pressure-high temperature areas for the period April-September 2017 is $ 5.56/mmBtu on gross calorific value basis, while the domestic prices has been lowered to $2.48/mmBtu on gross calorific value basis for this period. However, it will marginally benefit the midstream entities like GAIL, which will see its trading revenue fall by ₹ 2.5 billion from domestic sales during in 1H of FY18. But since GAIL sells its domestic gases on a cost-plus basis, its gross margins will be protected. GAIL will open a new energy route for India early next year by beginning regular imports of shale gas from the US, adding to New Delhi’s bargaining power with its predominantly West Asian suppliers. GAIL will begin importing gas in ships under a long-term contract from Dominion Cove Point LNG project from March 2018 and has floated tender for chartering ships for transportation. The company has also made a time-swap deal for 1 MT of US gas for FY19 in an attempt to recast its supply portfolio in line with domestic demand. GAIL had in 2013 tied up 2.3 MT LNG supplies for 20 years from Cove Point. It signed another contract for 3.5 MT of LNG with Cheniere Energy Inc’s Sabine Pass project in Louisiana, the supplies from which will begin in December 2018.  The company also holds a 20 percent stake in Eagle Ford Shale of Carrizo Oil & Gas. The contracts with Cheniere and Dominion make GAIL one of the largest holders of LNG portfolio linked to Henry Hub, the US gas price benchmark, and will allow it to market 6 MT of US gas. Both Cheniere and Dominion projects have US energy department’s permission to export gas to countries such as India that do not have free trade agreement with Washington. Regular gas supply from the US at an affordable rate will underline the impact of a rebound in the US fracking industry on global energy trade and widens options for India, giving it leverage against West Asian suppliers.

Rest of the World

Asian spot LNG prices edged lower as the early restart of Chevron’s Gorgon production facility in Australia weighed on sentiment, projects offered supply and demand from Japan stayed weak. Spot prices for July delivery LNG-AS were assessed at $5.40/mmBtu down 5 cents from earlier. The early restart of Gorgon’s first production line provided an unexpected boost to Asian supplies after operator Chevron initially estimated the outage would last until mid-June. Project stakeholder Exxon Mobil launched a tender to sell one cargo for delivery in the second half of June days before news of the facility’s restart was made public. The various supply tenders from Angola, Nigeria and Australia, which offered June-loading cargoes, came amid muted summer demand from north Asian buyers. Any downside to Asia spot prices could be capped by relatively firm European demand, including in Spain, traders said. Results from the Nigerian and Angolan sell tender are expected to emerge in the coming days, but Asian LNG market participants said it was unlikely that the cargoes would be sold to Asia given the strength in Atlantic prices.

Japan’s Mitsui & Co Ltd plans to expand its LNG trading operation as demand for the cleaner fuel spurs more spot transactions in Asia. The move comes amid a big shift in the market in Asia, which takes in about 70 percent of global shipments of LNG, with traders and end users increasing their ability to trade in anticipation of a supply influx from Australian and US projects. Mitsui traded 2.8 MT of LNG in the year ended March 31, but will receive more supplies from next year when the Cameron LNG project in Louisiana starts operations. The Japanese company has signed up to take 4 MT of LNG annually from the project, with some of it tied up in term contracts leaving it with volumes to trade. China currently imported about 26 MT of LNG in 2016, up by a third from a year earlier. The company is also looking for buyers for supplies from an LNG project in Mozambique led by Anadarko in which Mitsui has a stake.

With a tanker expected to arrive in Taiwan shortly, the US will increase the number of countries that have received LNG from the Sabine Pass terminal in Louisiana to at least 23 of the 35 that can accept the vessels. The Cadiz Knutsen tanker will go to the Taichung LNG terminal in Taiwan with a load of super-cooled gas from Cheniere Energy Inc’s Sabine, according Genscape shipping data. The increase in US deliveries coincides with the LNG market worries that Qatar, the world’s biggest LNG exporter, could experience problems delivering fuel to some countries after Saudi Arabia and a few other Arab nations severed diplomatic and transport links with the gulf sheikhdom after accusing the country of sponsoring terrorism.

The Netherlands is set to receive its first LNG delivery from Cheniere Energy’s Sabine Pass export plant in the US, according to shipping data. The Arctic Discoverer vessel, with a carrying capacity of 133,500 cubic metres of LNG, departed the facility on the Gulf Coast and is listed as heading for Rotterdam, data shows. Cheniere is currently the only company able to export large cargoes of LNG from the continental US but very few have so far landed on European shores despite analyst expectations of a surge in supply. According to US Department of Energy data, the biggest beneficiary of Sabine Pass volumes has so far been Mexico, followed by Chile, China, Japan, Jordan, India and Turkey. Currently Spain, Portugal, Italy and Malta are the only European countries to have received deliveries. Analysts and some LNG traders expect European imports to improve from this summer due to increased LNG production capacity as markets in Asia and elsewhere struggle to absorb the growing pool of supply. In February Britain received its first ever LNG delivery from Peru aboard the Gallina tanker. Royal Dutch Shell exports LNG from Peru, mostly to Mexico, but due to contractual issues with Mexico’s CFE the oil major had opted instead to divert some cargoes into alternate markets, traders said.

Austrian energy group OMV and Russia’s Gazprom are considering reviving a gas pipeline project through the Black Sea connecting Russia to central and southern Europe. If realized, the project would likely boost the importance of OMV’s Baumgarten gas hub, which distributes around 57 bcm a year. The project would be an extension of the TurkStream pipeline, which Gazprom plans to finish by the end of 2019. The extended line could pump Russian gas to Italy, which currently receives supplies from Baumgarten via the TAG and SOL pipelines. Alternatively, Russian gas could go from western Turkey via Greece to Italy. Russia scrapped the South Stream pipeline project, which would have supplied Russian gas to southern Europe with an undersea pipeline to Bulgaria, in late 2014 because of objections from the European Union on competition grounds.

The government of Australia’s Northern Territory gave the go-ahead to start building a $600 million gas pipeline that could help ease a shortage of the commodity in the country’s east. Jemena, owned by State Grid Corp of China and Singapore Power, was given permission to build the westernmost portion of the 622 km line designed to connect gas fields in northern Australia with the eastern state of Queensland. Australia is the world’s second-largest LNG exporter, but has faced a growing crisis over local gas supply with prices rocketing over the past two years as the commodity is shipped abroad. The company had previously said it planned to begin construction of a compressor station, for which it has already won approval, in May, and that it may eventually extend the pipeline.

ConocoPhillips said that production and exports of LNG from an investment project in Qatar have not been affected by growing Middle East diplomatic tensions. Saudi Arabia, Bahrain, Egypt and the United Arab Emirates cut ties with Qatar, accusing the country of supporting extremism. Qatar has denied the allegations. Concerns have grown that global access to Qatar’s LNG could be cut, especially after some Persian Gulf ports said they would not accept Qatari-flagged vessels. Houston-based ConocoPhillips owns a 30 percent stake in an LNG project operated by Qatargas Operating Co Ltd, part of the state-controlled energy company. Mitsui & Co Ltd owns a remaining 1.5 percent stake in the project, which processes about 3 m/day. ConocoPhillips controls the Golden Pass LNG facility in the US along with Exxon Mobil Corp and Qatar Petroleum.

Qatar has no plan to shut the Dolphin pipeline that transports natural gas to the UAE despite the severing of diplomatic ties between the two Gulf Arab nations. Saudi Arabia, the UAE, Egypt and Bahrain said they would cut all ties including transport links with Qatar, the world’s top seller of LNG, accusing it of supporting terrorism. Doha denies the accusation. Qatar supplies roughly a third of global LNG – natural gas that has been converted into liquid form for export. The pipeline was the first cross-border gas project in the Gulf Arab region. It pumps around 2 billion cubic feet of gas per day to the UAE. Tankers load Qatari crude along with UAE oil as shipping ban eases. The diplomatic dispute has stoked concern that any supply disruption could spill over into global gas markets. Even a partial shutdown would force the UAE to seek replacement LNG supplies. The UAE could cope with Qatar suspending its two to three monthly LNG deliveries by calling on international markets, but Dolphin piped flows are too large to replace fully.

The Philippines aims to build a $2 billion receiving and distribution facility for imported LNG, as it seeks to replace depleting domestic gas reserves that now produce a fifth of its power. Construction could be completed by 2020, or four years before the Malampaya natural gas field is depleted. The Philippines’ energy demand will triple by 2040, with electricity requirements anticipated to grow four times from 2015. Chinese and Japanese companies are among the foreign investors who want to help build energy infrastructure, including LNG facilities. Several firms have expressed interest in building LNG facilities in the Philippines, including Manila Electric Company, formerly in talks with Osaka Gas Co Ltd for a joint venture.

Talks over new routes for gas supplies to China from Russia have stalled while Beijing rethinks the balance of its energy needs, including how much LNG it might use. Gazprom, which is already building a gas pipeline from Eastern Siberia to Chin, the Power of Siberia, was in talks over two more routes: the so-called western gas route and a gas pipeline from the Pacific Island of Sakhalin. Gazprom said there were no developments on the two pipelines, whose combined capacity, if built, is seen adding up to another 40 bcm in possible gas supplies from Russia to China per year. The Power of Siberia pipeline, expected to be launched by the end of the decade or in the early 2020s, should bring 38 bcm to China per year. Gazprom managed to clinch the Power of Siberia deal after ten years of painstaking talks with Beijing. Neither Gazprom nor state-owned CNPC immediately responded to requests for comment. According to BP’s energy outlook to 2035, the share of pipeline gas supplies to China, including from Russia, will remain largely unchanged over the ten years from 2025, with the share of LNG and China’s own gas output significantly rising.

Oil majors BP and Eni are deepening their foray into blockchain technology, starting to run blockchain trades in parallel with their live trading systems, according to developer BTL Group. The energy traders, together with Austria’s Wien Energie, had previously tested BTL’s Interbit blockchain platform over 12 weeks, carrying out trades in European natural gas.

Sinopec said it has started building China’s largest natural gas storage and logistics center with the capacity to store up to 10 bcm of gas in Henan province in the central part of the country. The world’s second-largest economy is investing in infrastructure from pipelines to storage tanks as Beijing prepares to switch from coal-fired boilers and heating systems across 28 of its smoggiest cities to natural gas or electricity by October. The storage facility is expected to open in May 2018. The storage facility will be connected to pipelines and supply gas to central China, Beijing and Tianjin.

LNG: Liquefied Natural Gas, ONGC: Oil and Natural Gas Corp, mmBtu:  million metric British thermal units, OIL: Oil India Ltd, FY: Financial Year, mtpa: million tonnes per annum,  bcm: billion cubic meters, mmscmd: million metric standard cubic meter per day PNGRB: Petroleum & Natural Gas Regulatory Board, DGH: Directorate General of Hydrocarbons, MT: Million Tonnes, Ind-Ra: India Ratings and Research, FSRU: Floating Storage and Regasification Unit, US: United States, CNPC: China National Petroleum Corp, UAE: United Arab Emirates

Courtesy: Energy News Monitor | Volume XIV; Issue 2


Merchant Mining: Can We Learn from Past Mistakes?

Ashish Gupta, Observer Research Foundation

Coal auctions are happening in a big way but unfortunately, India has not incorporated lessons learnt from past mistakes. The idea of giving coal blocks to State Public Sector companies so as to prepare the coal sector for the commercial mining is a genuine move. But the way it is being carried out will not produce any fruitful results. Why? The analysis chart is given below:

List of Allotees – Schedule II Mines

No. of Blocks allotted Name of the Allotee Core Business Can be treated as Commercial Miner End Result
1 Damodar Valley Corporation Power & Mining Yes More efficiency
1 Karnataka Power Corporation Ltd. Power No experience in mining No efficiency improvement in coal mining
1 Punjab State Power Corporation Ltd. Power No experience in mining No efficiency improvement  in coal mining
1 Rajasthan Rajya Vidyut Utpadan Nigam Ltd. Power No experience in mining No efficiency improvement in coal mining
5 West Bengal Power Development Corporation Ltd. Power Have some experience in mining through State Utility (West Bengal Mineral Trading & Development Corporation) Some efficiency improvement

List of Allotees – Schedule III Mines

No. of Blocks allotted Name of the Allotee Core Business Can be treated as Commercial Miner End Result
1 Bihar State Power Generation Company Ltd. Power No Continue with same MDO practice and hence no improvement
2 Chhattisgarh State Power Generation Company Ltd. Power No No efficiency improvement
1 Gujarat State Electricity Corporation Ltd. Power No No efficiency improvement
1 Jharkhand Urja Utpadan Nigam Ltd. Power No No efficiency improvement
4 National Thermal Power Corporation Ltd. Power No No efficiency improvement
1 Odisha Coal and Power Ltd. Power No No efficiency improvement
1 Rajasthan Rajya Vidyut Utpadan Nigam Ltd. Power No No efficiency improvement
1 Maharashtra State Power Generation Company Ltd. Power No No efficiency improvement
1 Tenughat Vidyut Nigam Ltd. Power No No efficiency improvement
1 Telangana State Power Generation Corporation Ltd. Power No No efficiency improvement
1 The Singareni Collieries Company Ltd. Mining Yes More efficiency
1 Steel Authority of India Ltd. Steel & Mining Yes More efficiency
1 UP Rajya Vidyut Utpadan Nigam Ltd. Power No No efficiency improvement
1 West Bengal Power Development Corporation Ltd. Power Have some experience in mining through State Utility Some efficiency improvement

One can observe from the above chart that most of the Central/State Utilities that have got coal blocks do not have any prior experience in coal mining. These companies are very efficient in their core business but they will not play a role in achieving the one billion tonne coal output target set for 2019. The reason is that they are not commercial miners. They need to hire Mine Development Operator (MDO) through tendering process which unnecessarily delays mining operations. To achieve efficiency these coal blocks must be given to public sector companies which have some experience in coal mining and should be allowed to operate as merchant miners. The move will infuse competition and increase productivity. The same holds true for private power producers who are treated at par with miners. The idea of auction is not to increase revenue but to optimise the usage of natural resource. This is the area where the government should proceed with diligence. Is anyone listening?

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 45


Monthly Oil News Commentary: May – June 2017


India’s diesel demand is expected to rise to record levels again this year as a slew of infrastructure projects boosts use of the transport and industrial fuel, although a government-induced cash shortage will hold growth to its slowest in three years. Increased fuel efficiency, a fall in commercial vehicle sales, and the use of other fuels for power generation are also expected to dent demand growth for diesel, analysts and traders said. The world’s third largest oil consumer consumed 6.955 MT of diesel in April, the highest so far this year and near a record of 6.958 MT hit in May 2016, the latest government data showed. Still, a weak first quarter is expected to hold India’s diesel demand growth at 1.6 to 3 percent this year (1.63 – 1.65 million bpd), analysts from energy consultancies FGE and Wood Mackenzie said. April sales of India’s commercial vehicles, which consume mainly diesel, fell 23 percent year-on-year. Sales of passenger cars and motorcycles, however, mostly powered by gasoline, have started to recover. Woodmac expects India’s diesel growth to moderate at 3.2 percent a year over 2017 to 2025, down from an average annual growth rate of 3.9 percent from 2010 to 2016. Still India’s diesel demand growth in 2017 accounts for one third of Asia’s demand growth for the fuel, Woodmac said.

India’s gasoline consumption has flattened out in recent months after tremendous growth between 2014 and 2016. India’s motorists consumed 581,000 barrels of gasoline per day between February and April, according to the PPAC. Gasoline consumption rose by 4 percent compared with the same period a year earlier, a sharp slowdown from the 14 percent increase between 2015 and 2016. Gasoline consumption growth has been slowing since the middle of 2016 after surging for the previous two years. Consumption growth for most other fuels used for cooking and transportation has also been slowing for the last nine months. Demand for LPG and kerosene used for cooking, heating and lighting as well as diesel used for transport all show signs of levelling off or actually falling in the first four months of 2017. The slowdown may have been compounded by the demonetisation. Demonetization resulted in a sharp slowdown in sales of the cheaper motorcycles favoured by first-time buyers in rural areas. Rising crude oil and refined fuel prices over the last year are also likely to have constrained the growth in consumption and other fuels. Retail gasoline prices rose by around 10 percent between January 2016 and January 2017 while diesel prices climbed by almost 8 percent, according to data from the oil ministry. India’s emerging urban and rural middle class is relatively sensitive to increases in the cost of fuel so rising prices have curbed demand growth. Despite the recent slowdown in consumption growth for gasoline and other fuels it is too early to determine whether the deceleration is temporary linked to demonetization and price rises or something more lasting. But India has been one of the most important sources of oil demand growth during the slump so any prolonged slowdown in consumption growth would make the task of global market rebalancing harder.

India has for the first time ever signed a contract to import LPG from Iran as it looks at additional sources of cooking fuel to meet rising domestic demand. State-owned oil firms will import one VLGC or 44,000 tonnes/month for an initial six-month period. India imports almost a MT of LPG every month to meet rising demand that has been further fuelled by the government drive to give free gas connections to poor women. LPG consumption in 2016-17 rose 9.8 percent to 21.55 MT. Of this, 11 MT came from imports. India mainly imports LPG via term contracts from major Middle Eastern producers Saudi Aramco, Qatar’s Tasweeq, Abu Dhabi National Oil Co and Kuwait Petroleum Corp. LPG imports will rise over the next three years to 16-17 MT as the government pushes for making available cooking gas cylinders to the poor and wean them off polluting fuels. The country is looking to import LPG from Bangladesh. India had imported 8.8 MT of LPG in 2015-16. Imports last year made India the world’s second-largest importer of LPG, behind China. It overtook Japan, which imported 10.6 MT. The government launched a programme to provide free cooking gas connection to poor women with a view to cut on use of firewood and polluting fuels like dried cow dung. LPG demand is projected to grow by 9.7 percent to 23.7 MT in the current fiscal and is likely to touch 35 MT by 2031-32. A record 34.5 million LPG connections were given during the fiscal ended March 31, 2017, including 22 million free connections to poor women. This has taken the number of LPG consumers to 200 million. As many as 60 million connections have been given in last three years, taking LPG to 72.84 percent of the population. The government is targeting giving out 30 million connections including 15-20 million under the free LPG connection scheme during the 2017-18 fiscal and another 40 million in the following year. This would help take LPG coverage to 95.49 percent of the population.

Oil companies will have to take a collective hit of about ₹ 250 billion a year after the roll-out of GST since most of their output is outside the ambit of the new system. From July 1, India will roll out GST that includes most goods and services but excludes crude oil, natural gas, petrol, diesel and jet fuel. The exclusion of these goods from GST is part of the trade-off Centre conceded to address states’ fear of losing out on revenue from taxes on oil sales, a key source of their income. Other oil products such as kerosene, LPG and naphtha are included in the GST. This means oil companies will have to comply with both the old and the new tax regimes. But the tax credit can’t be transferred between the two systems. So the GST paid by an oil company on the procurement of plant, machinery and services will not be creditable against the excise duty and value added tax on the output such as crude oil, petrol and diesel not covered by GST. All downstream companies such as IOC, BPCL and HPCL will together have to bear an impact of about ₹ 150 billion. Analysts said higher tax burden for oil companies will have an inflationary impact on the overall economy. Under GST, 5 percent tax rate will apply to subsidised kerosene and LPG used for domestic cooking. At present, most major states have 5 percent tax on kerosene. Many states impose no tax on cooking gas while others levy up to 5 percent.

The Indian basket of crude oils closed below the psychologically important $50/bbl mark as geopolitical tensions in the West Asia raised market concerns. Crude prices continued on their downward spiral following the OPEC cartel’s decision to extend output cuts. The Indian basket, comprising 73 percent sour-grade Dubai and Oman crudes, and the balance in sweet-grade Brent, closed trade at $48.58/bbl. It had previously closed lower at $48.53/bbl. While the OPEC and non-OPEC producers agreed to extend until March 2018 their ongoing oil output cuts, India has reached an understanding with the global oil cartel to establish a joint working group to serve as a forum for “producer-consumer dialogue” to address mutual concerns.

The Aadhaar card has now been made mandatory for government subsidy on purchase of kerosene and benefits of Atal Pension Yojana. Those availing kerosene subsidy or contributing for the pension scheme will now be required to furnish proof of possession of Aadhaar number or undergo the enrolment process to get the benefits. The last date to get the Aadhaar or enrolment for getting it will be September 30, in case of Kerosene subsidy. It has been also decided to link the Aadhaar number with the ration card issued to households availing the benefits or with the bank account for cash transfer benefit. The oil ministry has introduced Direct Benefit Transfer through which subsidy is transferred directly to the bank accounts of the beneficiaries, who purchase the PDS kerosene at non-subsidised rate.

The government will formulate a policy this year to bring private capital and technology to substantially increase crude oil production in major oilfields such as Mumbai High that were given to state-run firms ONGC and OIL without an auction or a production sharing contract. The new policy, in which private companies will be able to bid for EOR contracts in line with best global practices, will be announced in the current fiscal year. All nomination fields will be covered by the policy but ‘a case-by-case evaluation’ would be made to decide which field can gain from private capital and technology. If state-run firms can raise output to a certain level using EOR in some fields, those may not be auctioned. EOR techniques, which require heavy investment, are used to extract more crude from depleting fields by using gas, heat or chemical injections to push up oil from difficult traps. Most of India’s producing fields are ageing and can use EOR methods to boost output. Applying EOR techniques is capital-intensive, time-consuming and requires technological knowhow. A state oil firm executive said different fields require different EOR techniques and methods need to be tested in laboratories before being applied to wells. It can take about three years to take a laboratory solution to wells. In recent times, Cairn India has undertaken these techniques with good results. The government has been pushing state firms to use EOR techniques to raise output.

IOC and its partners are in talks to buy 49 percent stake in Russia’s Vankor cluster oilfields to consolidate their presence in the energy-rich Arctic region. IOC, OIL and BPRL is looking at buying a stake in Suzunskoye, Tagulskoye and Lodochnoye fields, collectively known as Vankor Cluster, sources privy to the development said. OVL, is also interested in the fields. OVL may possibly take 26 percent in proportion of the stake it bought in the main Vankor oilfield. OIL-IOC-BPRL may take 23.9 percent stake in line with its holding in the main Vankor field. Last year, OVL first acquired 15 percent stake in Russia’s second biggest oilfield of Vankor for $1.268 billion and then bought another 11 percent for $930 million. The 26 percent stake would give OVL 7.31 MT of oil. The consortium of OIL-IOC-BPRL acquired 23.9 percent stake in the field at a cost of $2.02 billion, giving them 6.56 MT of oil. Besides, the OIL-IOC-BPRL consortium has taken another 29.9 percent stake in a separate Taas-Yuryakh oilfield in East Siberia for $1.12 billion. The investments have taken the total outlay in Russia this year to $5.46 billion. These investments will give India 15.18 MTOE. The investment made compares to $28.48 billion investment by Indian companies overseas in the past 50 years, giving it about 10 MTOE.

Saudi Aramco is said to be ‘strongly interested’ in a refining project with Indian state refiners. India, one of the world’s largest energy consumers, has sought to diversify its supply of not only crude but also gasoline and other refined products. India, which has repeatedly pressed OPEC members for oil price stability, has offered staff and other technical assistance to Aramco.

Iraq replaced Saudi Arabia as top crude supplier to India in April as refiners moved to boost their processing margins by purchasing the cheaper Basra Heavy oil grade, ship tracking and trade flow data showed. India’s April imports from Iraq topped 1 million bpd for the first time, up by about a third from March and 8 percent from a year ago, according to ship tracking data. Indian refiners in recent years have invested heavily in modernising plants to more efficiently process low-grade crudes into diesel and gasoline, helping to boost operating margins and giving greater flexibility in the oil grades they can buy. India’s crude mix is highly diverse as a result, with just over 15 percent of its flows stemming from Africa in April, nearly 13 percent from Latin America, and most of the rest coming from the Middle East. Saudi Arabia, usually India’s main supplier, shipped about 750,000 bpd to the South Asian nation in April, a decline of about 5 percent from the previous month and 8 percent from a year ago, the data showed.

Rest of the World

Saudi Arabia’s dilemma is shown quite neatly by its decision to raise crude oil prices for Asian refiners even though the kingdom is steadily surrendering market share in China, its biggest customer. Saudi Aramco, the state-owned oil company, lifted the OSP for its benchmark Arab Light grade to Asian refiners by 60 cents a barrel for July shipments. Arab Light cargoes for July will now be sold at a discount of 25 cents a barrel to the Oman-Dubai crude price, up from a discount of 85 cents for June shipments. Saudi Aramco sets the OSP based on recommendations from customers and after calculating the change in the value of its oil over the past month, based on yields and product prices. The Saudis are leading the efforts to lower output by a combined 1.8 million bpd, a move that aims to drain inventories by enough to lift prices over the longer run.

Saudi Arabia has notified at least two Asian refiners of its first cuts in crude allocations for regional buyers since an OPEC output reduction took effect in January. Saudi Aramco has told Asian buyers it is curtailing supplies for June to meet its commitments for the output cut. The notification of the reductions in June allocations signals added urgency among members of the OPEC as evidence mounts that the output cut has so far failed to rein in a global glut in crude. OPEC has previously kept supplies to clients in high-growth Asian markets steady, while cutting allocations to Europe and the United States. Saudi Aramco will reduce oil supplies to Asian customers by about 7 million barrels in June, as it keeps to the production agreement and trims exports to meet rising domestic demand for power during the summer. Seven million barrels is roughly two days of oil imports into Japan, the world’s fourth-biggest importer. Aramco and other producers typically issue monthly notices to refineries and other buyers with contracted supplies outlining their intended allocations to each customer. Usually they keep volumes at previously agreed levels but sometimes will reduce or increase the supplies depending on market conditions.

OPEC and non-members led by Russia decided to extend cuts in oil output by nine months to March 2018 as they battle a global glut of crude after seeing prices halve and revenues drop sharply in the past three years. Oil prices dropped more than 4 percent as the market had been hoping oil producers could reach a last-minute deal to deepen the cuts or extend them further, until mid-2018. OPEC’s cuts have helped to push oil back above $50 a barrel this year, giving a fiscal boost to producers, many of which rely heavily on energy revenues and have had to burn through foreign-currency reserves to plug holes in their budgets. Oil’s earlier price decline, which started in 2014, forced Russia and Saudi Arabia to tighten their belts and led to unrest in some producing countries including Venezuela and Nigeria. The price rise this year has spurred growth in the US shale industry, which is not participating in the output deal, thus slowing the market’s rebalancing with global crude stocks still near record highs. OPEC and non-OPEC agreed to extend cuts by the same 1.8 million bpd. The exact split between OPEC and non-members will likely be different after Equatorial Guinea joined the organization, reducing the number of participating non-OPEC nations to 10. Despite the output cut, OPEC kept exports fairly stable in the first half of 2017 as its members sold oil from stocks. OPEC produces a third of the world’s oil. Its production reduction of 1.2 million bpd was made based on October 2016 output of around 31 million bpd, excluding Nigeria and Libya. OPEC has a self-imposed goal of bringing stocks down from a record high of 3 billion barrels to their five-year average of 2.7 billion.

OPEC is still debating whether to extend oil output cuts by six or nine months, UAE said.  Oil producers agree they need to do whatever is necessary to restore balance to the crude market but any decision on output cuts must satisfy all parties, Kuwait said. But Kuwait stated that it must be an agreement that meets the satisfaction of everybody, and if necessary, it may be possible to increase the quantity that is cut, but it is too early to wade into this subject. Kuwaiti did not expect OPEC oil producers to discuss any deepening of their oil output reduction target as the oil market had already absorbed a rise in shale oil output a nine-month extension to the agreement that has seen 22 oil producers target a reduction of 1.8 million bpd for the first half of 2017.

Iraq agreed with Saudi Arabia on the need for extending OPEC crude output cuts for a further nine months. It also agreed on the need to extend OPEC cuts for a nine-month period. Existing output curbs by OPEC and non-OPEC producers were due to last for the first six months of 2017.

Turkmenistan is likely to join an OPEC -led cut in oil supply aimed at supporting prices, sources in OPEC and the industry said, potentially enlarging the output reduction slightly. The OPEC, Russia and other producers agreed last year to curb production by 1.8 million bpd for six months from January 1. Oil prices have since gained support but global inventories remain high, pulling crude LCOc1 back toward $50/bbl and putting pressure on OPEC to extend or possibly add to the cuts at least until the end of 2017. Turkmenistan is a small producer, pumping about 250,000 bpd.

US shale production is expected to rise for the sixth consecutive month in June, government data showed, as producers continued to increase drilling activity because of higher oil prices. June output is set to rise by 122,000 bpd to 5.4 million bpd, according to the US EIA’s drilling productivity report. That would be the highest production since May 2015. In the June figures, the EIA revised its December numbers up to 4.79 million bpd. That would mean the December to June production in US shale gained by nearly 617,000 bpd. In the Permian play located in West Texas and New Mexico, oil production is expected to rise by 71,000 bpd to a record 2.49 million bpd. In the Eagle Ford region, located in South Texas, output is set to rise by 36,000 bpd to 1.28 million bpd, the most since April 2016. Production in the Bakken play in North Dakota is forecast to rise 5,800 bpd to 1.03 million bpd, its second monthly rise. US natural gas production was projected to increase to a record 1.4 BCM/day in June. That would be up almost 16 MCM/day from May and be the eighth monthly increase in a row. The EIA projected gas output would increase in all of the big shale basins in June.

Global oil inventories in floating storage have declined by one-third since the start of the year, the OPEC said. The drop in stockpiles is the latest sign that output cuts by major producers have helped deplete a global glut. Global oil markets will reach a supply-demand balance in late 2017 or early 2018 if a pact to cut output is extended.  OPEC and other producers including Russia pledged to cut output by 1.8 million bpd in the first half of the year to lift oil prices. But global inventories remain high, pulling crude back below $50/bbl earlier this month and putting pressure on OPEC to extend the cuts to the rest of the year. Novak told the agencies that OPEC countries and other leading oil producers would discuss extending the deal in the second half of the year or “maybe further than that”. The parameters of the deal to be unchanged, meaning deeper cuts were unlikely. Russia would keep output cuts of 300,000 bpd from the level of October 2016 as stipulated by the December 2016 deal. Russia’s oil output forecast of 549-551 MT for this year remained the same but could change depending on the outcome of oil producer nation talks in Vienna.

Oil pricing agency S&P Global Platts said it will not automatically include Qatari-loading crude in its Middle East benchmark after Saudi Arabia and some other Arab states cut ties with Doha, a move that disrupted traditional shipping routes. Saudi Arabia, the UAE, Egypt and Bahrain said they would sever all ties including transport links with Qatar, escalating past diplomatic disagreements. Platts’ move is unlikely to have a significant impact on the broader oil market because Qatar is one of the smaller producers in the OPEC. Platts said it would continue to assess and publish independent values for other Qatari-loading crudes during the review. It said that the process would not immediately impact existing nominations for cargoes loading in June and July against trades previously reported in the Platts pricing process, known as the market-on-close.

Oil traders and analysts are expecting large volumes of crude to draw from storage tanks across the US in what would be the most tangible sign of an inventory overhang reduction that has punished prices over the last two years. A reduction would show the market is finally reversing course after years of stock builds that left a worldwide overhang of half a billion barrels of crude oil and refined products. Supplies have remained stubbornly high for months, disappointing traders who were expecting OPEC cuts to help rebalance the market. But traders interviewed said seasonally unusual spring drawdowns in the US, record refining runs, and big exports to Asia and Latin America as signals that sharp declines in crude stocks could be coming. Some traders said that they expect as much as 10 million barrel per week in draws soon, although others forecasted three to four million barrels a week. US crude stocks peaked at 533 million barrels in March, and were at 516 million barrels as of last week, according to the US EIA.

US President Donald Trump’s proposal to sell half of the US SPR will likely have little impact on OPEC’s efforts to reduce a global oil glut, Goldman Sachs said. The White House budget, delivered to Congress, aims to start selling SPR oil in fiscal 2018, which begins on October 1. Under the proposal, the sales would generate $500 million in the first year and gradually rise over the following years. Goldman Sachs said such sales would only average around 110,000 bpd annually through 2027, 66,000 bpd between 2018-2020 and just 25,000 bpd this year. Goldman Sachs said the proposed SPR sales would increase the logistical strains on the US Gulf Coast, which is already struggling with higher shale production. The US SPR, the world’s largest, holds about 688 million barrels of crude oil in heavily guarded underground caverns in Louisiana and Texas. Congress created it in 1975 after the Arab oil embargo caused fears of long-term motor fuel price spikes that would harm the US economy.

The plan to sell off half the US emergency crude oil stockpile to help balance the budget faces opposition in Congress, with lawmakers from both parties worried the proposal would undermine the drilling industry and make the country vulnerable to supply shocks. News of the proposal had briefly sent oil prices tumbling on concern it would oversupply the market, but prices recovered and finished slightly higher on hopes that OPEC and other countries would extend supply cuts. US oil imports from the producer group OPEC have fallen to less than 3.2 million bpd in 2016 from more than 5.4 million bpd in 2008, according to the US EIA.

Amid the frenetic activity of American shale oilfields recovering from a two-year recession sit a handful of oil towns that seemed impervious as many producers went into bankruptcy and the economy around them sank. Occidental Petroleum Corp and a few other oil producers with wells near this town on New Mexico’s border with Texas steadily pumped low-cost oil through the downturn, using a technique that has been heralded worldwide as a way to reduce carbon emissions and boost oil output. Such a move could extend by decades the producing life of hundreds more wells, increasing oil supply which would be a drag on prices. To date, the technique has been employed only at conventional oilfields, rather than on shale deposits. Some firms are studying how to put the technique to work in shale drilling, too. The drilling method harnesses the carbon dioxide produced during the extraction of oil or from power plants, and forces it back into the fields. That boosts the pressure underground and drives more oil to the surface. The technique, one of several so-called EOR strategies used to prolong the productive lifespan of oilfields and increase output, underpins around five percent of US oil output, or about 450,000 bpd according to energy consultancy Advanced Resources International. EOR can help firms to produce between 30 percent and 60 percent of all the oil held in a reservoir. That’s far more than the 10 percent usually recovered from initial traditional drilling, according to the Department of Energy.

Statoil has interrupted drilling in the Barents Sea in the Arctic region after a court issued a temporary injunction in a technology dispute with a small Norwegian firm, Statoil said. The Stavanger court has prohibited Statoil from using its Cap-X drilling technology after Norwegian firm NeoDrill said it was based on its patented Conductor Anchor Node technology, which NeoDrill has been developing since 2000. Statoil stepped up exploration efforts this year, focusing on the Barents Sea. According to the Norwegian Petroleum Directorate the area could hold two-thirds of all undiscovered resources off the Norwegian coast. Statoil said it was unclear when Statoil could restart drilling at Blaamann, but the firm expected to complete all five wells in the Barents Sea it had planned for this year. Statoil said it planned to use Cap-X technology to drill all five wells in the Barents Sea, including the Korpfjell well in formerly disputed border area with Russia. When presenting the Cap-X technology to the public in April 2016, Statoil said it started its development in 2013 to help to develop resources in the Barents Sea.

US freight movements have started increasing again, which should help boost consumption of distillate fuel oil in 2017 and 2018. The tonnage of freight moved by road, rail, barge, pipeline and air cargo has been increasing year on year since October, after stagnating for much of 2015/16. Freight movements hit a new record in February, before slipping slightly in March, according to the US Bureau of Transportation Statistics. Most freight is hauled by equipment that uses diesel engines, or jet turbines in the case of air cargo. Freight is therefore the main driver for consumption of fuels refined from the middle of the crude oil barrel, including distillate fuel oil and jet fuel. The US EIA forecasts that distillate consumption will increase by 80,000 bpd in 2017 and a further 90,000 bpd in 2018.

China’s state-owned refiner CNPC has started receiving crude oil through its Myanmar-to-China pipeline. The pipeline starts at Kyauk Phyu in Myanmar’s west and enters China at the border city Ruili and is a joint investment by CNPC and the Myanmar Oil and Gas Enterprise. The oil will supply the new Anning refinery in the Yunnan province. The refinery was built with the capacity to process 13 million tonnes a year (260,000 bpd) of crude.

Activist investor Elliott Management upped the pressure for strategic changes at BHP, calling for an independent review of the mining giant’s petroleum business. Elliott, which has built up a 4.1 percent stake in BHP’s UK listed arm and is urging changes to boost shareholder value, said there were clear signs that the market was receptive to a new strategy for BHP. Elliott has been pushing for BHP to collapse its dual-listed structure, spin off its US oil and gas assets, and boost returns to shareholders since tabling its proposals on April 10 – all of which BHP has rejected. Analysts at Deutsche Bank and Citi have said BHP could unleash billions of dollars by selling part or all of its petroleum business, although Citi cautioned this would bring only a one-off benefit to shareholders and the company should focus on how to grow value for shareholders.

GST: Goods and Services Tax, Indian Oil Corp, BPCL: Bharat Petroleum Corp Ltd, HPCL: Hindustan Petroleum Corp Ltd, PPAC: Petroleum Planning and Analysis Cell, VLGC: Very Large Gas Carrier, bbl: barrel, ONGC: Oil and Natural Gas Corp, OIL: Oil India Ltd, EOR: Enhanced Oil Recovery, MT: Million Tonnes, LPG: liquefied petroleum gas,  bpd: barrels per day, OVL: ONGC Videsh Ltd, BPRL: Bharat PetroResources Ltd, MTOE: million tonnes of oil equivalent, CNPC: China National Petroleum Corp, BCM: billion cubic meters, MCM: million cubic meters, OSP: official selling price, OPEC: Organization of the Petroleum Exporting Countries, UAE: United Arab Emirates, US: United States, EIA: Energy Information Administration, SPR: Strategic Petroleum Reserves

Courtesy: Energy News Monitor | Volume XIV; Issue 1


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

Part I

The ongoing Energiewende in Germany (“energy turnaround”) is not only turning around the structure of the energy market and prices – particularly in the power generation sector ‑ but also requires considerable transformation of the utilities’ business models. This series of articles about the world’s experimental laboratory in the matter of greening the energy industry intends to catch up with recent structural and legislative developments that tackle the German electricity markets. It will also focus on evolving new business models, which might also serve as a blue print for any other energy market in motion towards more decarbonised and smarter energy systems.  

By establishing the German Renewable Energy Act in 2000, Germany has triggered the Energiewende, an ambitious restructuring program of the German energy industry with the aim to decarbonise the energy system in the long-run: the share of renewables (REN) was set to achieve 80% in electricity generation by 2050. On top of this the German government has decided to phase out nuclear power plants finally by no later than 2022 as a consequence of Japan’s Fukushima Daiichi nuclear disaster in 2011.

As the policies have been in place for such a long time, some considerable structural changes have taken place in the German power generation sector. Nevertheless various issues within this ambitious program that are no yet satisfactorily settled are leaving the Energiewende in an ongoing state of experimental mode, a showcase worthy of being narrowly observed around the globe. The restructuring process is far from self running; it requires attentive monitoring and is constantly challenging the policy makers to set proper incentives according to the legislative framework. On the other hand the numerous and diverse market players in the German industry are continuously forced to react and adapt their business models to the ongoing change of the structural and economical market conditions in order to safeguard their investments and appreciate the shareholder value.

Against this backdrop the most important structural developments and outcomes that are going to influence the German energy sector as a whole and the transformation process in particular shall be highlighted in the following.

The share of REN in German electricity production has risen in an impressive manner from about 7% to 24% in 2013 (and probably to more than 28% in 2014) by squeezing fossil fuels and nuclear energy out of the power market: as shown in Figure 1 the share of nuclear generation went considerably down from 30% in 2000 to 15% in 2013, hard coal fell from 26% to below 20%, even natural gas lost ground in recent years and declined to a share of about 10%, whereas the share of lignite has been counter-intuitively stable to date. Besides the share oil-fired power generation has been stable but more or less negligibly throughout that period.

Figure 1: Development of Power Generation Shares in Germany (2000-2013)

Source: Agora Energiewende (2014) based on data from AG Energiebilanzen

Current data for the 1st half of 2014 (as shown in Figure 2) disclose an even higher share of REN, which together with hydro and biomass adds up to 31% of total generation (and  49% of capacities) driven by high generation share from wind and solar. Although the contribution of natural gas went drastically down to a mere 6% in generation in the first six months of 2014 the capacity share remains significantly higher at 17%.

Figure 2: Net Power Generation Share of Fuels in Germany (Market Shares 1st Half Y14)

Source: ISE (2014), compiled by author. Generation shares in red numbers, capacity in grey

The structural changes so far are not yet in accordance with the intended outcome of the Energiewende: first and foremost much more renewables (due to strong subsidies), no more nuclear power stations (not authorized anymore) and beyond that, declining shares of lignite (brown coal) and hard coal power stations as well as oil (all environmentally unfavourable). Natural gas power stations stayed over as the wild card, although assigned to play a key role in Germany’s electricity generation transition due to its fast and flexible availability as an operational back-up to provide system stability for the fluctuating or intermittent generation patterns of solar and wind power.

As opposed to this especially the use of the old base load lignite power stations has grown significantly in recent years while gas’ share dramatically went down with even the most modern and efficient CCGT plants now seriously under-utilized, in cold reserve or even mothballed. As fuel switching is heavily influenced by the relative fuel costs and CO2 prices this unwanted development has been particularly determined by relative high gas prices compared to coal in combination with low carbon emission allowance prices at the EU Emissions Trading Scheme.[1] The high deployment of REN running at zero fuel costs and increased running of cost competitive coal power stations are actually overstocking the German wholesale trading market and has yielded a record (net) electricity export level, which is going to jeopardise even gas-fired power generation in neighboring countries like the Netherlands.

Germany’s temporary fallacious path towards cheap-black and expensive-green based power generation has as well yielded again in a rising carbon footprint of Germany. Figure 3 demonstrates that the carbon emissions linked to electricity generation are on the rise despite the continuously growing share of REN (the so called Energiewende Paradox). As a result the German Federal Environmental Agency (2014) has recently stated that overall CO2 emissions in Germany have increased by 1.2% in 2013 and are still more or less flat lining above the lows seen in 2009.

Figure 3: CO2 Emissions from German Power Generation

Source: Agora Energiewende (2014) based on data from the German Federal Environmental Agency (Umweltbundesamt)

Besides structural displacements in power generation, the development of the electricity price is the most important outcome and benchmark one should bestow consideration upon. Although the costs of renewables have dropped substantially, the electricity price for end consumers has risen more or less continuously since the start of the restructuring program (Figure 4). Electricity prices for households as well as for industry have more than doubled between 2000 and 2013, which can mainly be attributed to the significant increase in taxes, charges and levies. Price rises in recent years have been particularly driven up by the surge of the levy for the EEG (German Renewable Energy Sources Act). The mere costs of electricity (generation, transport, distribution (green area in graph below)) have even been constant or slightly falling in recent years. According to the BDEW, the proportion of the end consumer price accounted for by state charges (presently more than 52%) has drastically increased since 1998. Since the surcharge is kept at a lower level for some industrial customers through increasing exemptions from the charge in order to survive the challenge of global competitiveness, the costs for private customers have been driven up more steeply (right hand figure in graph below). The overall burden required by the renewable surcharge in Germany (EEG-Umlage) has risen to more than 20 bn Euro per year by now.

Figure 4: Development of End Consumer Electricity Prices in Germany (Index 1998=100)

Source: BDEW German Association of Energy and Water Industries []; compiled by author

However, in contrast to end user prices that are burdened by various taxes and duties (especially for households), wholesale prices are relatively low and internationally competitive due to the excess supply plus from REN and coal-fired power stations. Electricity prices at the EEX, the German Electricity Exchange, have been decreasing from over 80 Euro/MWh base load in 2008 (blue line in Figure 5) by more than 50%.

Figure 5: Wholesale Electricity Prices in Germany (EEX Future Base-/Peak load 2007-2014)

Source: BDEW German Association of Energy and Water Industries [] based on EEX

A recently published comparison of household electricity prices (incl. taxes and levies) reveals the large gap that has opened up between European prices in general and German prices in particular in contrast to American prices: In 2013, the average household price in EU countries was more than double the rates in the U.S. The German price was even more than triple the U.S. rate. Together with Denmark Germany exhibits the highest prices in Europe, both countries with ambitious goals in decarbonising their energy sectors.

Figure 6: Household Electricity Prices (incl. Taxes) in Europe and the U.S. (2013)

Source: EIA (2014)

The fundamental policy shift to launch the Energiewende in 2000 the German energy system has already undergone a considerable restructuring towards renewable energy. Nevertheless some goals clearly failed so far, first and foremost in the matter of the Energiewende Paradox that actually causes rising carbon emissions. On the other hand, there is an ongoing and rising discontent because of the overall cost burden associated with the higher than expected payouts through the Feed-in Tariff system (EEG-Umlage) and its allocation to different sectors. To tackle these weak spots of the restructuring process German lawmakers have initiated a reform of the German Renewable Energy Act that has entered into force on 1 August 2014. Furthermore, the German government has recently approved a renewed climate protection law. Both legislative reforms can be expected to have wide-reaching influence on the Energiewende progress and intentionally fix or correct the most severe flaws and undesirable developments in the time to come.

Part II

The German Energiewende turns around Policy Framework

The legal framework for the Energiewende in a broader sense is set by international legislation like the commitments due to the ratification of the Kyoto-Protocol as well more stringently by the policies of the European Union (EU) to achieve the completion of the internal energy market and the efforts to combat climate change that are wrapped up in Energy and Climate Packages.

Beyond that, the German Government has decided to be at the forefront of international climate policy and set even more challenging regulations to meet Germany’s responsibility as a leading industrial country for a sustainable development and climate protection: At national level, Germany is making inroads with the transformation of its energy system and has set ambitious targets for reducing greenhouse gas emission.

However, it turned out over time that some unintended developments have challenged the Renewable Energy Act from 2000, that should to be tackled by the adoption of the reform of Germany Renewable Energy Act (EEG = Erneuerbare-Energien-Gesetz) from August 2014. This article shall help to catch up with the state of play of the legal framework in Germany that stipulates the terms of the ongoing restructuring process of the German energy industry, starting with a glance on international agreements towards more national regulations.

Some crucial characteristics of main climate legislations and agreements with their associated obligations are compiled in Figure 1 as a synopsis. The illustration compares different greenhouse gas (GHG) reduction paths over time (starting from upper part) as well as intended goals for renewable energy share (lower part). Based on the Kyoto Protocol, EEG and the EU’s framework for energy and climate (denoted in the clouds above) the GHG timelines for Germany (orange lines) and the EU (blue lines) are plotted and specified.

In contrast, the outcome of the recent agreement on climate change between the U.S. (green line) and China (red bar) are indicated and altogether challenged by the IPCC mitigation pathway zone that is expected to likely limit warming to below 2°C relative to preindustrial levels (grey lines). These ‘sustainable’ scenarios are characterized by far-reaching global anthropogenic GHG emissions cuts by 2050 and emissions levels near zero or below in 2100.

Since most climate legislation in Europe and Germany comes along with expansion goals of renewable energy the intended pathways for Germany and Europe and actual shares are demonstrated in the lower part of the diagram (dotted lines).

Figure 1: Timelines of “Climate Obligations” [1990-2050]

Source: Compiled by author based on given sources.

As one out of 192 Parties (191 States and 1 regional economic integration organization) Germany has ratified the Kyoto Protocol to the UNFCCC that is the first international agreement to set binding obligations to limit and reduce GHG emissions. As part of the EU’s burden-sharing agreement Germany is committed to reduce its GHG emissions by 21 % during the period from 2008-2012 compared to 1990 levels. According to the German Environment Ministry Germany already has considerably surpassed its GHG reduction commitment since 2009, even if GHG emissions have temporarily increased thereafter. Recently Germany has become the first large EU member state to start ratifying the extension of the Kyoto Protocol treaty for the second commitment period (2013-2020), even though the emission reduction targets therein are not considered as sufficient.

As shown in Figure 2 Germany has quite successfully achieved to cut down its climate footprint since 1990 by now: GHG emissions have decreased by about one quarter within the last two decades and therefore complied with the Kyoto-protocol. More than 80% of the overall emissions of greenhouse gases can be attributed to be energy related, which fell by 23% from 1990 until 2012. However, since the low in 2009 the continuous slump has come to a temporary standstill for the time being.

Notwithstanding the negative developments in recent years initial estimations for 2014 are indicating that the Energiewende is getting back on track. As indicated in Figure 2 (bright yellow bar) CO2 emissions (and overall energy consumption as well) are expected to fall significantly by about 5%, of which more than the half can be attributed to the power generation sector.

Since the slump is largely influenced by mild weather condition the temperature-adjusted drop is expected to be more in the order of one percent. Moreover the structure of electricity generation usage points in the intended direction: significant decrease of lignite (-3%) and hard coal (-12%) on the one hand, strong growth (+3.3%) of renewables overall and especially photovoltaic (+14%) on the other hand. Thus the share of renewables at the gross electricity consumption is expected to rise by 2% to 27.3%.

Figure 2: Emissions of Greenhouse Gases in Germany (1990-2012, est. 2013/14, Goals)

Source: German Federal Environmental Agency (2014), AG Energiebilanzen (2014). Amendments by author.

In Europe the overall legal framework that applies to energy markets and climate protection is most widely predefined by the EU policies. Building upon the commitments made under the Kyoto Protocol the EU adopted the climate and energy package (“20-20-20” targets) as binding legislation for member countries that aims to ensure the ambitious climate and energy targets for 2020:

  • 20% reduction in GHG emissions by 2020 (compared with 1990 levels);
  • 20% rise in the share of renewables of EU energy consumption by 2020;
  • 20% improvement of the EU’s energy efficiency by 2020.

Theses 20-20-20 targets are made up by certain principles and tools as well as binding directives. The pioneering EU emissions trading system (EU ETS) – already launched in 2005 – is regarded as the key tool for reducing carbon dioxide emissions in Europe cost-effectively. It was therefore decided to strengthen the 3rd phase of the Emissions Trading Directive with effect from 2013. For sectors not included in the EU ETS divergent national emission targets for 2020 are determined by the ‘Effort Sharing Decision’ on the basis of member states’ relative wealth. Recent figures from the European Environment Agency (EEA) show the EU’s overall emissions have already met the 2020 goal to cut GHG emissions by 20% versus 1990.

In October 2014 the EU leaders agreed upon a revised and more ambitious GHG emission goal that is expected to become legal in 2015 and will follow the 20-20-20 goals. The 2030 climate and energy package plans to cut EU’s GHG emissions by at least 40% from 1990 levels by 2030 in order to meet the track towards the longer term reduction roadmap 2050 by at least 80%. The sectors that are covered by the EU ETS are called to reduce their emissions by 43% compared to 2005 on a more restrictive path by curtailing the number of allowances by ‑2.2% p.a. from 2021 onwards (vs. the rate of ‑1.74% up to 2020). Currently the EU ETS (3rd phase 2013-2020) covers barely half of total EU’s greenhouse gas emissions predominantly from power and heat production, energy-intensive industry sectors and commercial aviation.[2] Furthermore a market stability facility with the power to withhold or release allowances shall help to strengthen the efficiency of the EU ETS. Other sectors beyond the EU ETS are required to cut emissions by an EU-wide 30% but with national diverse targets according to their GDP.

Thus – like before – some regulations are set to be broken down to individually different national targets: Though the Commission targets a binding increase of the renewable energy share to 27% of the aggregate EU’s energy consumption by 2030, the target is in fact voluntary for individual member states and was pushed down by U.K. and Poland in the negotiation process from proposed 30%. Even though the climate package is labelled as the toughest climate change target of any region in the world, environmentalist groups are rather disappointed by the outcome since some state that some goals barely presents more than the business-as-usual track.

In 2000, Germany was one of the first countries setting up a Renewable Energy Act (EEG) to implement a feed-in tariff law to boost renewable energy expansion, thus becoming the worldwide prototype model thereafter. This ambitious energy industry restructuring program has intended to decarbonise the German energy system in the long-run (80%-share of renewables in electricity generation by 2050). Based on political decisions the load-bearing walls for Germany’s future energy architecture have been clearly set: much more renewables (due to strong subsidies), no more nuclear power stations (phasing out by 2022) and beyond that declining shares of lignite (brown coal) and hard coal power stations as well as oil (all environmentally unfavourable). The role of gas in power generation has been constantly left over as a kind of undefined joker role, rarely mentioned in political energy strategy, although due to its clear advantages gas-fired power stations are assigned to play a key role in Germany’s electricity generation transition to provide back up to intermittent solar and wind generation.

The EEG has hitherto undergone several major amendments with one of the most significant was coming into effect in 2014. According to the German Ministry of Economy (BMWI 2015) the EEG has been developed and amended as follows since coming into force on April 1, 2000:

  • The EEG 2000 itself was already built upon its predecessor regulations in the Electricity Feed-in Act (Stromeinspeisegesetz) from 1990 that was the first legal scheme in Germany intending to boost electricity production by renewables by the means of a feed-in tariff and a purchase obligation for the power utilities. The need for this new EEG law mainly resulted from the rising wind energy plants, obligations from the Kyoto Protocol to reduce GHG emissions, and steps necessary to adapt the remuneration for renewables arising from increasing electricity prices.
  • The first amendment EEG 2004 for the first time determined a concrete expansion target for renewable energies in Germany (up to 12.5% by 2010 and at least 20% by 2020).
  • The amendment of EEG 2009 was more fundamental and comprehensive with most important extensions according to the compensation rules for hardship in case of capacity constraints and in relation the direct marketing of electricity from renewable energy sources. However, due to the drastically reduced capital cost of photovoltaic (PV) systems there was a need of a reduction in rates for new PV system to avoid an over-funding, therefore the EEG 2009 was soon amended by the PV 2010 amendment.
  • With the EEG 2012 amendment the government proposed goals for the power sector were settled in legislation: the share of renewable energies should be at least 35% of electricity consumption by 2020, 50% by 2030, 65 % by 2040 and 80 % by 2050. Furthermore, more attention was attributed to optimisation of the overall system, i.e., the improvement of the interplay between renewable and conventional energy sources as well as storage and consumers. An optional market premium should give incentive to EEG plant operators to operate more market-oriented. Besides EEG, another PV amendment in 2012 aims to limit the increase of total feed-in-payments linked to PV facilities by setting an overall target of 52 GW of PV power reimbursed, a further decrease of tariffs, a modification of the degression scheme reducing tariffs by about 1% per month, and setting the maximum power of a single facility to 10 MW.
  • The EEG 2014 amendment particularly aims to stabilise the rising cost burden of the EEG surcharge by more controlled development paths of specific renewable energies.

In general, the latest amendment of the EEG is set to tackle some key problems that were arising in the course of the intended energy industry restructuring throughout the process while continue progress towards the specified renewable energy targets expansion targets, i.e.:

  • PV and (onshore) wind power costs were falling dramatically and are now more competitive. To curb the renewable expansion costs by focusing on the most cost-effective technologies onshore wind and solar photovoltaic; consequently decreasing the incentives for other energy types. E.g. extension of biogas plants will be restricted to 100 MW per year. The law introduces a so-called “flexible cap” to reach the specific quantitative target.
  • The market share of renewables is now substantial, thus renewables require better market integration according to wholesale market price signals;
  • The burden linked to the administered Feed-in Tariff has substantially risen due to drastic growth of solar especially, and has therefore evoked issues of cost and distribution of renewables among consumers. Currently the surcharge for some industrial consumers is kept low through exemptions, which drive costs up for mainly the household consumers. However, finally to ensure international competitiveness of German industries, no dramatic shift can be expected and private consumers will continue to bear the brunt.

In addition to the new EEG regulations the ministry of economy is considering to force energy companies to shut down eight more coal-fired power plants in order to reduce carbon emissions by at least 22 mt by 2020 to bring the development back on track according to Germany’s ambitious climate goals. The plan may prompt the main players like E.ON and RWE to mothball dirty coal power stations and to mitigate against the unintended outcome of flatlining GHG emissions of the German power sector in recent years. Even IEA (2014) expects that the “coal renaissance in Europe was only a dream”, since the temporary rise of coal use in Europe in recent years is more regarded as a temporary spike largely due to low coal and CO2 prices, high gas prices, and the ongoing shutdown of German nuclear plants.

The German energy restructuring towards a lower carbon footprint and national as well as international energy and climate legislation are interdependent, as the legislation determines the framework and incentives for the restructuring process, however, the outcome of the process (including wider issues as cost distribution etc, too) as well as market conditions influence the evolution of legal amendments. Therefore, it cannot be assumed that EEG 2014 has been the last reform of the Germany’s Renewable Energy Act. Indeed, the government has announced that in 2016, a new reform will be put forward to parliament that will trigger a more competitive auction process of tariff setting for renewables. Besides, the idea of setting up a capacity market for power generation back-up to overcome the mothballing of several gigawatts of unused gas-fired capacity is still ongoing, even if the German energy minister Sigmar Gabriel is (currently) opposed to it. However, it seems that capacity markets may provide a suitable solution and are making their way in Europe. In the upshot, the adaption of legislation will continue to make progress, depending on various factors, be it political (e.g. changing governments, outcomes of international agreements (EU, Kyoto and COPs)) or  triggered by changing market conditions (e.g. oil price slump, low coal and CO2 prices etc). The case of last-mentioned market distortions shows that even if politics might start with the right action to correct market-failure (like carbon pricing) or pursue other political aims (e.g. support green energy), the monitoring and possibly adaption over time is of utmost importance to avoid inefficiencies in the aftermath. These could arise within different political levels, be it on international, national or federal level and moreover if different markets/commodities are involved.

Part IIIa

The German Energiewende turns around Industry’s Business Models

Since 2000, Germany has triggered the Energiewende, an ambitious restructuring program of the German energy industry with the aim to decarbonise the energy system in the long-run. Additionally the German government has decided to phase out nuclear power plants finally by no later than 2022, as a consequence of Japan’s Fukushima Daiichi nuclear disaster in 2011. The Energiewende is widely regarded as an ongoing showcase project in experimental mode, worth of being narrowly observed around the globe.

The restructuring process is challenging numerous and diverse market players in the German energy industry that are continuously forced to react and adapt their business models to the ongoing change in the structural and economical market conditions in order to safeguard their investments and appreciate shareholder value. Both risks and opportunities matter: on the one hand the odds are long for the conventional players like the ‘big four’ ex‑incumbent electricity producers E.ON, RWE, EnBW and Vattenfall. On the other hand is the chance for several smaller players to enter into the evolving energy market with smart and innovative ideas in the course of shifting towards a more renewable based, decentralised and smarter as well as interconnected market structure.

The intended structural changes are particularly hammering the core business of the incumbent utilities: the double whammy of Energiewende regulations towards a higher share of renewables and lower lignite and hard coal power stations as well as the gradual phasing-out of nuclear power is going to little by little eliminate the business model that they hitherto used to run: For decades some large utilities have dominated the German electricity sector by legally established, regionally demarcated and vertically integrated monopolies. Some of these companies could successfully survive the consolidation process resulting from the ongoing liberalisation process of the German (and European) energy market that took off in the mid nineties and maintain its dominating positions regionally: e.g. RWE in the industrially important Rhine-Ruhr region, EnBW in Baden-Wurttemberg and Vattenfall in the eastern parts of Germany.

It is widely said that the German utilities have relied too long on an obsolete business model that was profoundly based on large scale and long term investments in centralised base-load power generation plants fired by fossil fuels (first and foremost lignite/coal) and nuclear. Having overinvested in gas- and coal-fired plants before the financial crisis, the two largest players E.ON and RWE were building up too much capacity in the subsequent downturn while the subsidy-incentivised new and “green” competitors were upsetting the market. On top of that the nuclear accident at the Fukushima Daiichi reactor in 2011 has triggered an unprecedented turnaround manoeuvre by the German government that decided – just few months after having granted some lifetime extensions – to downturn eight out of 17 nuclear power stations in short term and the complete decommission of nuclear power in Germany by 2022, bringing forward the enormous decommissioning costs to the operators. Wholesale power prices have been deteriorating due to the rapid expansion of heavily subsidised renewables with low running costs and have additionally worsened the financial conditions for the big four even more, since they largely blew their chance of entering into green energy markets.

The Economist (2013) has put the rigorous situation for European utilities already out 2013 by titling “How to lose half a trillion euros – Europe’s electricity providers face an existential threat”: At their peak in 2008 the top 20 European energy utilities were stated to be worth about 1 trillion Euro. Till late 2013 they were losing half of their value. As illustrated in Figure 1 the share price of the two German top dogs E.ON (red line) and RWE (blue line) tanked till 2014 and have not recovered one jot since then. The sheer magnitude of the massive value destruction at the capital market becomes very clear by paying attention to the widening gap between the utility’s market value and the German blue chip stock market index DAX that has almost doubled within the last three years (grey line).

Figure 1: Share Price of selected German Utilities vs. DAX 2006-2015 (Index May 2006 = 100%)

Source:, accessed March 13, 2015. Compiled by author     

Casting a glance on the generation mix of RWE in Germany already reveals a lot of the dire straits the large utilities are actually facing. Figure 2 illustrates that more than half of RWE’s German power generation in 2013 was from lignite with hard coal accounting for another 20%; thus more than two-thirds of RWE power generation in 2013 was coal fired (and 59% capacity, respectively). Even if generation from indigenous lignite was thriving again in recent years, this is widely deemed as a temporary phenomenon. Currently the political pressure on that vastly available and cheap but most carbon-intensive type of fossil fuel is definitely on the rise: Since the German government firmly seeks to realise its intended carbon reduction targets the economy ministry has drafted a legislation that might urge the utilities to cut emissions by at least an extra of 22 mt CO2 by 2020. Accordingly a kind of new climate levy of about 18‑20 EURO/t CO2 is supposed to tackle the oldest and most carbon-intensive power stations meaning that several coal-fired power stations may be closed down. These are bad news particularly for RWE that alone runs four of the biggest lignite power stations. Besides, nuclear power stations are accounting for more than one fifth odd in RWE’s generation mix, yet another end-of-range model.

On the other hand E.ON is not that much dependent on lignite, however, nuclear power make up almost one third of its overall generation capacity in Germany, even if already two reactors were forced to shut down in 2011, right after the Fukushima disaster. Another reactor in Grafenrheinfeld is planned for being decommissioned by May 2015. Vattenfall is profoundly involved in lignite mining and generation in the Eastern parts of Germany; the Swedish state company has recently announced to offload all its German lignite assets. More or less the same picture can be drawn for the fourth big player EnBW that has large stakes in nuclear as well as coal/lignite power generation.

What is more, even natural gas fired power stations that are much required for overall (technical) system stability needs have been widely mothballed in recent years due to losses resulting from longer lasting negative clean spark spreads. Therefore – as one aspect of the so-called ‘Energiewende-Paradox’ (higher CO2-emissions despite higher share of renewables) – natural gas power stations are continuously squeezed out of the market by cheaper coal-powered blocks. Quite recently E.ON has officially announced the closedown of its just two years old, most efficient state-of-the-art natural gas fired blocks 4 and 5 at the Irsching power plant in Bavaria with due effect on April 2016 because of its expected ongoing poor economics. Up to now these blocks were put under a so-called redispatch agreement for two years until March 2016 under that the plant operators are reimbursed from the grid operator TenneT (yet still the regulator can prohibit the closure for operational network security reasons).

Even the formerly most lucrative chunk of power generation in Germany has been thwarted by the rise of renewables since at peak hours in the middle of the day there’s no big profit to cash in anymore on sunny days, because massive solar power generation tends to significantly control the profitable price spread between peak-hour and base-load prices.

In a nutshell, the big four altogether suffer from the break-off of their core business, the centralized large-scale power generation. On the downside, the big four’s stakes in renewables is partly nominal as can drastically be seen in Figure 2 looking at the marginal share of renewables in RWE’s generation portfolio in Germany (that is only slightly higher on company-wide international scope). The data from RWE’s quite recently published annual report 2014 reveals that the group-wide power generation from renewables decreased by 27% year-on-year to a lousy 10 TWh in 2014 (due to closure of a biomass combustion plant in UK), that is less than 5% in RWE’s overall power generation mix. The share of RWE’s power generation from renewables in Germany itself is yet lower; it fell from 0.7% in 2013 to poor 0.5% in 2014. On a first glance E.ON seems to be better invested into renewables, however, far more than 90% of renewable generation and capacity can be attributed to hydro. E.ON’s renewable power generation fell in Germany from 2013 to 2014 by 22%; in 2014 renewables (i.e. hydro) made up about 7% in E.ON’s overall German power output.

Therefore, the big four have bet not only too long on discontinued fossil fuel and nuclear power stations on the one hand, they even seem to have missed the opportunity of investments into the booming sector of renewable energy. According to the Federal Network Agency’s (2014) recently published monitoring review the big four utilities’ aggregated market share of power generation capacity in Germany has collapsed another 11%-age points within only three years 2010-2013 down to 68%. Their combined share in overall power generation in Germany has fallen from 84% to 74%, respectively, primarily due to the generation attributed to E.ON, that went down by 38%. As a result, one can state that over the course of the Energiewende restructuring process the ownership profile of the power generation assets has been broken up from only a handful of former incumbents led by E.ON and RWE towards a wide variety of smaller and independent power producers like private citizens and farmers (together owning almost half of the renewable generation in Germany), followed up by project developers as well as industry and banks. And even the approx. 800 so-called Stadtwerke are yet playing vital role in the German energy companies landscape, gaining from their potential of local power production and particularly from options in co-generation plants. (The Stadtwerke currently stage a comeback with numerous municipal new establishments after a large wave of privatisation during the 1990s.) The corresponding power sale market shares for Germany (as shown in Figure 3) are highlighting the same deconcentrating trend, as the former incumbents’ stake in the sales market is plunging (to a combined share of 67% in 2013) as well, particularly E.ON but RWE, too.

The bottom line is that the big four are getting more and more into the red due to the insidious breakup of the utilities’ longstanding fossil fuel and nuclear driven business model. E.ON has recently announced a huge loss of more than 3 bn Euro (over 2 lakh crore rupees) for its business year 2014, the second one in the company history after 2011 (see Figure 4). RWE already faced a similar loss in 2013 due to strong depreciations. Besides the falling power prices and falling business volume, E.ON is troubled by other problems including its Russian subsidiary suffering from the weakness of the ruble as well as trade sanctions, its Brazilian power producer Eneva filed for bankruptcy protection at the end of 2014, mistaken asset investments in Spain that were again offloaded end of 2014 and last but not least the massive oil price drop. Not that long ago E.ON experienced some bonanza years with annual profits of 6-8 bn Euro.

Figure 4: Profits of selected German Utilities 2007-2014 (Earnings after tax in bn. Euro/a)

Source:, accessed March 25, 2015. Compiled by author

Looking at the steadiness of dividends (i.e. the returning value for shareholders) that serves as a performance benchmark for the attractiveness of long-term investments, one can as well observe a clear and steady downswing (Figure 5). For example, RWE cut its current dividend by half to 1 euro that is only a fraction of the 4.5 Euro they paid some years earlier. Starting in 2015, RWE will no longer calculate dividends on recurrent after-tax profit but will base the payments on operating cash flow, debt and earnings. However, reliable dividend payouts are particularly important for RWE since the biggest single shareholder is a group of highly indebted towns and cities in North-Rhine-Westphalia that seeks a stable income to settle their budgets.

Figure 5: Dividends of selected German Utilities 2003-2014 (in Euro/kWh)

Source:, accessed March 25, 2015. Compiled by author.

Those days of high profits and dividends are over, and probably never to return. Even worse, the utilities management is blamed for having failed to cope appropriately with the market challenges; a recently published study on behalf of Greenpeace (2015) ascribes severe strategic flaws, first of all, that reactions were not timely and decisive enough to change course:

  • The big four have banked too long on their high margins and profits from market power and didn’t realize the need to bring business in line with the successive market changes;
  • They have unilaterally focussed on lifetime extensions of their nuclear power stations, which turned out to be faulty after the phase-out decision in the wake of the Fukushima disaster;
  • They simply missed the investment options in the upcoming renewable energy sector.

About one year ago, when the CEO of RWE had to announce a historic loss, Spiegel-Online (2014) has headlined: ‘conceptless RWE CEO: lamenting as a strategy’. The critique was that the company’s strategy was built up too much on the hope that the government might take pity on them while ignoring entrepreneurial solutions. Hereof two big ideas surrounding state compensation and supply risks are repeatedly floated towards the policymakers:

  • The first strategy is to increase the pressure in relation with the decommissioning of the German nuclear energy sector. The big four have filed several lawsuits against the decision to terminate the lifetime extension and the immediate shutdown of eight nuclear power plants as well as against the nuclear fuel tax regime. According to Reuters (2014) E.ON is said to claim about 8 bn Euro, RWE more than 2 bn Euro and Vattenfall 4.7 bn Euro. Furthermore, the creation of a kind of “bad bank” to hive off the four nuclear operators’ provisions of about 36 bn Euro for plant decommissioning and disposal of nuclear waste is at issue.
  • Strong lobbying in order to achieve a market redesign in favour of the so-called “power capacity market” that shall help to uphold investment in power plants that provide back-up capacity, which otherwise might be mothballed due to negligible load and/or profit. So far the government is refusing to consider the creation of service payments like this, however, neighbouring markets like the UK have already acknowledged and implemented that concept by implementing capacity auctions.

Nonetheless, the utilities’ lobbyists in Berlin have forfeited their immense power of successfully influencing the policymakers in the recent years. Therefore large rationalisation programs have been rolled out, incorporating large scale reduction in employment, organisational streamlining, outsourcing of non-core assets business areas and closing of unprofitable power plants (the start of RWEs most recent profound cost-cutting programme “Lean Steering 2.0” was heralded only a couple of days ago at mid April). The tense debt situation is pressuring to sell off assets, as quite recently the oil/gas exploration and production unit RWE Dea. RWE, E.ON and EnBW are altogether singing renewable power expansion praises now and furthermore strengthen their investment in infrastructure and smart energy products and services. Their announced mission statement obviously still lives on the credit of the old conventional energy world (see as an example RWE’s mission statement in Figure 6).

Figure 6: RWE’s Mission Statement 2015

Source: RWE Annual-Report 2014.

While RWE seems to head on strategically by muddling through, the most comprehensive strategic approach is pursuit by E.ON and Vattenfall. On the one hand Vattenfall has started to prepare its market exit by announcing to sell its lignite generation plants and mines in eastern Germany. On the other hand E.ON desperately tries to change track and decided to perform its second comprehensive strategy swing within a couple of years after 2010 when the management has opted to enter new international markets like Brazil. However, the most radical strategic step was announced in Nov. 2014 as Germany’s largest utility surged forward to offload its complete fossil fuel and nuclear based power generation business as well as global trading unit and it’s upstream into the so-called “New Company” (Figure 7). The new company will generally incorporate E.ONs former core business including struggling Brazil and Russia operations. The divestiture would leave E.ON to focus on environmentally friendly renewable-energy sources and is intended to become an energy network and solutions provider; E.ON’s 31 bn Euro net debt will retain with this larger part of E.ON. E.ON has repeatedly reaffirmed that the spin-off company would have sufficient financial strength to cover the liabilities associated with the decommissioning of nuclear energy in Germany; the company’s accrued liabilities for the nuclear phase-out of currently about 14.5 bn will remain with the nukes in the new company. By all means, E.ON’s restructuring agenda has startled politicians because of fears coming up in public discussion that E.ON might be creating a ‘bad bank’ for its seven nuclear plants that will have to be bailed out by the German taxpayer as a leading member from the Green Party has put it bluntly. (Overall provisions of the big four are about 36 bn. Euro for plant decommissioning and disposal of nuclear waste; however, there is an ongoing debate whether there are sufficient funds).

Figure 7: Planned Spin-Off Company Structure of E.ON (incl. data from 2014)

Source: Der Spiegel (2014b). Compiled by author.

Part IIIb

The ongoing Energiewende in Germany (“energy turnaround”) requires considerable transformation of the utilities’ business models. The prevoius part (IIIa) has focussed on the ‘big four’ incumbents and how they meet the strategic challenges. This present second part (IIIb) will take a look at new business models that are concomitantly evolving with the industry’s restructuring. It concludes with a more global foresight relating to some ongoing tendencies that are expected to strengthen the green paradigm further on.

Beyond the bitter fate of the ‘big four’ even most of the thriving companies – like the prominent photovoltaic (PV) cell producers Solarworld, Q-Cells, Conergy or Solon – in the windfall of all the generous financial support associated with the Energiewende were getting into dire straits already soon after the initial boom. Primary reasons were at first the creation of excess capacity at the German solar market and then the influx of cheaper PV modules and cells from Chinese competitors entering the German market. Several German solar producers rushed into bankruptcy. Even the former showpiece company Solarworld could barely escape crash, and saved its neck so far only by acknowledging a harsh debt cut and by relinquishing autonomy in favour of its new major investor Qatar. Figure 8 illustrates the rollercoaster ride the Solarworld stocks have been on in recent years: from penny-stock level up to its all-time peak late 2007 and back down again. Recently it was blamed the second consecutive year for being the inglorious leader of ‘capital burning’ in Germany; its stock price was down 82% in 2014 alone, and moreover, since 2010 the price fell by 99.5%.

Even beyond the pioneers of the solar and wind boom it is expected that now the whole industry will adjust to the business opportunities arising from the decentralisation drive towards more data-based and interconnected smart grids solutions that will help to match growing intermittent supply and demand efficiently. Alongside the traditional providers of industrial solutions in the energy sector like U.S. General Electric (GE) or German Siemens new innovative player are entering the market: one outstanding example is Google’s $ 3.2 bn acquisition of Nest Labs in Jan. 2014 in order to be involved in the promising future business of smart-home technologies. Nest Labs manufactures a variety of smart home devices like thermostats, which learn a user’s habits over time and adjusts the room temperature accordingly. Nest Labs aims to establish itself as the operating platform for web-connected home devices: users will be able to communicate with appliances from Whirlpool, cars from Mercedes, remote controls from Logitech among others. Quite recently Nest has teamed up with solar power system manufacturer SolarCity to make savings easier for homeowners.

In Germany one signal example of how to carve out a fortune in the future energy industry is the so-called SchwarmEnergie-concept provided by one of the Germany’s largest green electricity and gas suppliers Lichtblick. SchwarmEnergie (“swarm energy”) intends to cope with the requirements of a fragmented and decentralised electricity market, in which more and more power is produced locally in a variety of small units (e.g. renewables like photovoltaic systems, (smallest) combined heat and power stations, heat pumps, solar batteries or the batteries of electric vehicles), and increasingly stored. Therefore the strict separation of consumers and producers is going to be superseded as we go along. The basic idea is to interconnect thousands upon thousands of involved small-scale market players (e.g. households) by means of appropriate smart control systems and an applicable software that could quickly rewire and provide a “virtual power plant” at an aggregate level (as illustrated in Figure 9). Given that, traditional back-ups for intermittent wind and solar power generation by large power plants (and mostly operated by large utilities) will become more and more redundant. The whole approach is based on Lichtblick’s IT platform SchwarmDirigent (“swarm conductor”) that aims to bundle the countless processes of an increasingly complex energy world. The pilot scheme was already successfully rolled out and provides an instructive foretaste of what is to come.

Figure 9: Synopsis of the SchwarmEnergie Concept (Lichtblick)

Source:, accessed April 16, 2015. Compiled by author.

In the upshot, energy markets must be understood to be in a constant state of flux due to diverse reasons that comprise altering resource availability, the ever-changing supply/demand (market) conditions but also (politically initiated) shifts in the institutional framework. Even if utilities have often operated under temporary exceptional permissions and/or government backed (or being a mere state company) it can be stated that there is no guarantee for a certain business model to survive. As we have seen, it is actually more important to address the changing conditions at the right time (i.e. early enough) with the right strategy (i.e. dare to advance), otherwise the risk of failure is rising enormously.

In the case of the Energiewende an institutional redeemer cannot be foreseen, politically there is currently no “too large to fail” or species protection for the ‘big four’. It seems to be more about being the last of their species as they are abandoned to their fate that results in a structural market adjustment at the end of the day: RWE might turn out to be a potential takeover target (if yet attractive enough for investors), Vattenfall seeks to get rid of its German business. Even the big four’s long established wheeling and dealing with the political circles in Berlin is evidently more and more for the birds and doesn’t provide a proper lifeline anymore.

The advantage in rapid transforming structures decidedly is with the small, flexible and innovative players. That’s a lesson we have actually also learnt from other energy markets, e.g. the US shale revolution that was actually not driven by the incumbent oil and gas majors but rather by smaller independents like Devon Energy, Chesapeake Energy or Continental Resources. Struggling to find new reserves and at times of rising uncertainty about the crude oil price, Exxon and other oil majors have now turned to gas as a proxy in fossil fuel market and consolidated the sector by several takeovers (with the last prominent merger seen just a couple of days ago when Shell announced to buy BG Group, a vital player in the global gas market).

And there is yet another story behind the ongoing adaptation of business models to spot that is very important for investors in long-lasting energy infrastructure assets to pay attention to: the trend to acknowledge the requirements of local pollution and global climate change. Beyond corporate green washing hypocrisy there are evermore concrete examples of large-scale and long-lasting energy industry’s restructuring really triggered by climate change considerations, like the shift away from lignite and brown coal in Germany, more and more investments of the oil super majors into lower carbon fossil fuel natural gas and/or renewables (or as BP’s new slogan puts it straight: “beyond petroleum”).

One could even be well-disposed to argue that the current restructurings are driven by the ‘unburnable carbon’ idea.[3] Even if there is still a lot of dispute about the genuine truth of this concept (which is likely to be verified only in the times to come), the times of being a myth are over and there is increasing evidence that the shadow of unburnable carbon becomes longer and starts to touch on a variety of crucial market players. One of the most recent paradigm is the disclosure of Norway’s Government Pension Fund Global (GPFG), actually the world’s richest sovereign wealth fund, to divest from 22 companies involved in coal mining, oil sands, cement production and coal-fired power production during 2014 on the basis of a broader assessment of companies’ business models and the sustainability of their operations over time. Moreover the GPFG has also divested from a further 27 companies, due partly to other environmental considerations.

A couple of days ago Bloomberg (2015) carried the headline “Fossil Fuels Just Lost the Race Against Renewables – This is the beginning of the end” and pointed out that now more capacity for renewable power will be added each year than coal, natural gas, and oil combined; and that the shift will continue to accelerate. The cost of wind and solar power continues to decrease and is now on par or cheaper than grid electricity in many areas of the world. Thus it’s only a matter of time that the world will see renewables cutting into the markets even without being backed by large subsidy systems, and it’s safe to assume that these will only be needed as stimulus if the institutional framework is set accordingly.

Against this backdrop the declaration of India’s largest power producer NTPC to more than double its current installed capacity to 90 GW in the next ten years might be put at risk, even if the power producer plans to include solar energy in its total installed capacity in the coming years. Given lifetimes of coal power stations of about half a decade or more the challenge to compete against cheaper renewables in times to come might be considered to turn out desperate. This is aggravated by the fact that state companies are known for their inefficiencies and stubborn market strategies. As has been shown the German ‘big four’ incumbents are struggling even in a slow evolving and foreseeable market environment due to strategic and management flaws. It is much to be hoped that players on the Indian energy market like NTPC will learn from the German experiment, envisaging the developments that are already looming ahead and shifting to more pioneering strategies – otherwise they might share the big four’s doom and face a rude awakening.


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[1] See Schuppe (2013) for more information according to the reasons behind this development.

[2] Participation in the EU ETS is mandatory for companies operating in these sectors, but in some sectors only plants above a certain size are included.

[3] The ‘unburnable carbon’ concept can be generally traced back to the Carbon Tracker Initiative, which is focussing on the fossil fuel reserves held by publically listed companies and the its market valuation in relation to potential systemic risks for institutional investors caused by the shift to a low-carbon economy (see for more information

Views are those of the author                    

Author can be contacted at

Courtesy: Energy News Monitor | Volume XI; Issue 26

Courtesy: Energy News Monitor | Volume XI; Issue 34

Courtesy: Energy News Monitor | Volume XI; Issue 44

Courtesy: Energy News Monitor | Volume XI; Issue 45

High Oil Price Risk Remains

Lydia Powell and Akhilesh Sati, Observer Research Foundation

Delivering a lecture on critical drivers of the global oil market in Washington in 2013 Dr Fereidun Fesharaki, well known analyst of world hydrocarbon markets observed that it was God, Saudi Arabia and market fundamentals (in that order) that decided global crude prices. The list of factors as well as the order in which Dr Fesharaki listed them may still be valid even if those uncomfortable with the idea of God having something to do with the oil market use factors such as geology, technology, policy, politics or institutions instead. Those who want to stick to the market as the underlying driver of oil price would take the cost of the marginal barrel of oil as the determinant of price. However the cost of producing the marginal barrel depends on where it is produced. ‘Where the marginal barrel is produced’ depends on factors including but not limited to the oil market. This is reflected in some of the recent reports on oil markets which suggest that they would probably replace Saudi Arabia with the United States in Dr Fesharaki’s list of factors driving the oil market (Chart 1).

Chart 1: Largest Oil Production Increases

Source: BP Energy Outlook 2035, February 2015

Chart 2 from the medium term oil market report of the International Energy Agency (IEA) released in February 2015 captures the emergence of the United States as the new swing producer who balances the market. In chart 2, a deficit supply situation in the oil market shifts into a surplus situation in the beginning of the second quarter of 2012 with a sustained surplus of over 1.5 million barrels per day (bpd) emerging by the first quarter of 2015. Much of this surplus is attributed to production of non-conventional oil from non-OPEC regions.  According to IEA’s World Energy Outlook 2014 (WEO 2014), non-OPEC production of unconventional oil mainly light tight oil (LTO) from the United States increased from 0.4 million bpd in 1990 to 5.4 million bpd which is more than a ten-fold increase in just over a decade (chart 3).

The medium term oil market report of the IEA concludes that ‘this time the oil market correction would be different’ because (1) the United States as the new swing producer is not Saudi Arabia (politically, institutionally and otherwise) and (2) that the production of LTO in the United States will respond very quickly to changes in supply and demand conditions unlike conventional crude oil. As IEA puts it, ‘LTO production in the United States has upended the traditional division of labour between OPEC and Non-OPEC countries and the resilience of LTO production will ensure that price corrections in the oil market will happen as fast as the price rallies’. OPEC’s pursuit of market share rather than price management is compared with a similar move in 1986 by most of the recent oil market reports but the IEA is optimistic that OPEC strategy is unlikely to drive out surplus production and that LTO production may actually come out stronger after the price correction.

Chart 2: Oil Demand-Supply Balance

Source: Medium Term Oil Market Report 2015, IEA

Others, such as analyst Arthur Berman are not so optimistic over the prospects for LTO production in the United States. In his recent blog post, he points out that in an environment of low interest rates, the desire for yields is leading investment banks to direct capital into US E & P companies to fund tight oil plays. He points out that the financial performance of many of the companies engaged in tight oil plays is characterised by falling cash flows and growing debt.  Based on data from Schlumberger he concludes that US Shale companies had to drill 100 times more wells than Saudi Arabia to reach the same daily production as that of Saudi Aramco. This relates to the point made earlier that who gets to produce the last barrel does not depend entirely on the oil market. We will have to wait probably until 2020 to find out who is more accurate.

Chart 3: Crude Oil Production and Liquids Supply by Source (Current Policies Scenario)

Source: World Energy Outlook 2015, IEA, NGL – Natural Gas Liquids

If we return to WEO 2014 projections for oil supply under a current policies scenario captured in Chart 3, it appears that the role of non-OPEC conventional and unconventional liquids production would remain significant until 2020 but after that it would once again be OPEC conventional oil production that would dominate. This means that after 2020 the market may look very much like what it did before the United States emerged as a swing producer.

How the oil markets evolve has significant implications for India. As per the WEO 2014, net growth in oil demand is expected to come almost entirely from non-OECD countries till 2040. Projections by WEO expect that for each barrel of oil eliminated from demand in OECD countries, two additional barrels of oil will be consumed in the developing world. WEO highlights India and Nigeria as countries with the highest rates of oil demand growth (3.5% until 2040) with oil demand in India projected to touch 9.2 million bpd (under new policies scenario, could be more under current policy scenario), 2.5 times that of today (3.7 million bpd in 2013) pushed mainly by 70% growth in demand from the transport sector.

As a country with one of the highest rates of growth in demand for oil, India must keep its eye on how the oil markets evolve. Hope of low oil prices on account of shrinking market for oil, carbon penalties, growing use of electric vehicles or unconventional oil production may be unfounded. The price of oil will be determined by the cost of the incremental barrel and this is unlikely to be affected by the presumed reduction in the size of the oil market.

Views are those of the authors                    

Authors can be contacted at,

Courtesy: Energy News Monitor | Volume XI; Issue 45


Monthly Non-Fossil Fuels News Commentary: May 2017


India’s solar energy generation capacity rose at a record pace of 81 percent last financial year. India’s total solar power capacity currently stands at 12,288 MW as against 6,762 MW at the end of March 2016. The MNRE in April announced that the country’s solar capacity expanded by a record 5,526 MW in 2016-2017. In comparison, India added 3,010 MW capacity in 2015-2016. With 8.8 GW of projected capacity addition (growth of 76 percent over 2016) in 2017, India is set to become the third largest solar photovoltaic market, overtaking Japan, according to a report by solar energy consulting firm Bridge to India. By the end of 2017, India’s solar power capacity is expected to touch 18.7 GW, which will be about five percent of global solar capacity, growing by 89 percent over last year. As of March 2017, India had installed 12.2 GW of utility scale solar capacity.

Solar power tariffs in India have fallen to a new record low of ₹ 2.44/kWh unit in the bidding for Bhadla Phase-III Solar Park in Rajasthan. SECI is developing the 500 MW solar park at Bhadla with SauryaUrja Co. of Rajasthan Renewable Energy Corp Ltd. Renewable energy firm ACME has bagged 200 MW and SBG Cleantech has bagged the rest 300 MW at Bhadla phase-III. This comes within days of the 250 MW capacity of Bhadla phase IV solar park auction which had received the lowest ever bid till then at ₹ 2.62/kWh. Solar power tariffs have gone lower than coal-fuelled thermal power tariffs, the lowest for which stands at ₹ 3.20/kWh for NTPC Ltd. The previous low solar tariffs of ₹ 3.15/kWh had been witnessed for the Kadapa Solar Park in Andhra Pradesh for NTPC’s auction of 250 MW.

With solar rooftop power plant installations gaining momentum following financial assistance from Central and state governments, a growing number solar water heater makers are now venturing into the business of solar photovoltaic rooftop systems. Apart from growing emphasis on solar rooftop projects by the state and Union government, the stagnancy in the solar water heaters market is also driving these manufacturers to get into the solar rooftop systems business. The central government offers a subsidy of 30% in capital cost (which is ₹ 20,700/kW for solar rooftop projects, while the state offers additional assistance of ₹ 10,000/kW. The estimated cost of grid connected 1 kilowatt solar rooftop system is ₹ 69,000/kW. STFI feels solar water heaters lack encouragement from the government, which should come up with policies to provide level-playing to solar waters as well. Solar panel makers have been offered yet another sop in the context of GST.  Solar panel equipment will attract the lowest tax rate of 5 percent under the GST regime, as against the initially proposed 18 percent. Solar water heater and system, renewable energy devices and spare parts for their manufacture, bio-gas plant, solar power-based devices, solar power generating system and windmills and wind-operated electricity generator will attract a 5 percent tax rate.

West Bengal is going solar this time to run generators that will pump water to a reservoir uphill in Purulia’s Ayodhya Hills during off peak hours, 10 years after the successful installation of Purulia Pumped Storage Project. The state power department will set up a 1,000 MW solar-hydro power project when the existing project is a thermal-hydro mix. The proposal was cleared in the state cabinet meeting. The purpose of this multifunction power plant is to pave the way for energy generation without fossil carriers, a first of its kind in the country, when Bengal has a lopsided 96:4 thermal-hydro ratio in power generation. The objective is to use the afternoon sunlight to run turbines to lift stored water from a reservoir at a lower altitude in Ayodhya Hills to a reservoir on the upper side during off-peak hours that can help meeting the peak demand. Planned to be installed within 81 months, the second project is being funded by the JICA. The generated energy will be wheeled to the power grid to meet the peak demand.

Obscured somewhat by developments in the solar space, wind energy in India has experienced steady development in the last 7-8 years as the government plans a major ‘green corridor’ project to transport surplus renewable energy to deficient states. MNRE held a successful tender for 1 GW of wind power for inter-state sale last year.  Three main challenges in wind energy were forecasting, transmission and the competitive bidding framework for trade. A scheme for auction of wind power projects of 1,000 MW capacity that will kick off soon. The scheme is open for all obligated entities purchasing wind power for compliance of their non-solar RPO. SECI will sign Power Purchase Agreements with selected wind developers and back-to-back Power Sale Agreements with buying utilities. According to the memorandum of agreement, the distribution utilities of Uttar Pradesh will buy 449.9 MW electricity, Bihar 200 MW, Jharkhand 200 MW, Delhi 100 MW, Assam 50 MW and Odisha will buy 50 MW of wind power for meeting their non-solar RPO.

India has been placed in the second spot in the renewable energy country attractiveness index by EY. Over 10 GW of solar power was added between 2015 and 2017 and wind energy capacity grew to 5.4 GW in FY18.  EY said falling bids tracked lower technology costs and cheaper capital, allowing developers to maintain margins. But those margins were already squeezed by competition. In the medium term, as renewable energy penetration increases, the government will also have to ensure the grid can manage intermittent renewable energy. EY said the cost and availability of energy storage technology could dictate how close India would get to its renewables targets. The Centre’s proposed compensation mechanism for existing renewable energy projects will protect the cash flows to an extent from grid curtailments and will also ensure a favourable operational environment for renewables, Ind-Ra said. Historically, PPAs signed for renewable energy projects have failed to address the grid issues and lacked a mechanism to compensate for energy loss. According to Ind-Ra, the annual debt service coverage ratio slips by 0.12 times for 10 percent of energy curtailment and the 50 percent proposed compensation at PPA tariff will restrict the fall by half at 0.06 percent. The compensation will also incentivise grid operators and distribution utilities to reduce curtailments and benefit renewable energy developers in scheduling and forecasting and enable integration of increasing renewable energy capacity. In FY17, grid curtailment was prevalent for wind projects in Rajasthan (up to even 45 percent energy curtailed compared to 90 percent of plant load factor) and solar projects in Tamil Nadu.

India’s decision to cancel nearly 14 GW of coal-fired power stations coupled with a record low solar tariff are the strongest indications that the country’s energy transformation is gaining rapid momentum, the Cleveland-based IEEFA said. IEEFA said 13.7 GW of planned coal power projects in India have been cancelled. Experts said India’s rapid shift towards low-carbon economy is a step towards the 2015 Paris Climate Agreement that aims to cut greenhouse gases from burning fossil fuels. The government approved raising of ₹23.6 billion through bonds for renewable energy projects in the current fiscal. The bonds will be raised by the MNRE through IREDA during FY18.

The Bihar government has come up with a new renewable power policy for the state where it looks to set up over 3,400 MW projects based on non-fossil fuel-based resources in the next five years. The policy is likely to spur investments to the tune of 200 billion in energy projects, according to CEED, a non-profit organization. The state’s Cabinet cleared the policy called ‘Bihar Policy for Promotion of New and Renewable Sources, 2017′ and is likely to notify the same soon. Under the policy, the state government is mulling setting up 2,984 MW capacity based on solar energy, 282 MW on biogas and 200 MW small hydropower plants. Of the total solar capacity, the state plans to set up 1,000 MW rooftop solar projects and 1,00 MW as mini grid projects. Composed of solar modules, a battery bank, and an inverter, a mini-grid system can offer solar power as the primary power source and later switch to alternative power sources when solar power is insufficient for meeting demand. The renewable energy capacity addition of Bihar is in line with central government’s plan to have capacity of 175 GW built on alternative sources of energy by 2022. Of this 175 GW, the government plans to add 100 GW solar power capacity, 60 GW wind, 10 GW from biomass and 5 GW from small hydro projects. CEED said the provisions to de-risk private sector investment in mini-grid projects are also included in the policy given the fact that remote areas of Bihar possess huge potential for mini-grids and it is important to tap those potential with suitable investment climate. Held up for nearly a decade with several glitches, the ball has set rolling for the Parwan Dam project in Baran district. The dam once constructed is likely to benefit the people of Baran, Jhalawar and the entire Kota division with drinking water for over 820 villages and irrigation water for over a 100,000 ha agricultural land. The project was embroiled in several controversies regarding displacement of tribals, the forests land getting submerged and most important the project being brought in only to benefit two thermal power projects. Work on a mega drinking and irrigation project, held up for a decade for want of integration of various design and contractual obligations, is likely to be completed in 48 months, the company said. The dam to be built 120 km from Kota town in Akawad village of Jhalawar district was likely to submerge 10,000 ha including more than 1,600 ha of forestland. The MOEF&CC granted environmental clearance to the project in November, 2011. The clearance letter states the dam will completely submerge 17 villages and partially inundate 30 villages, affecting over 3,000 families including 461 tribal families. The 100 MW Sainj Hydroelectric Project being constructed by HPPCL in Kullu district would be commissioned partially this month. The ₹ 8 billion hydro project, funded by the Asian Development Bank, will generate 322 million units per annum. The state is expected to earn revenue of ₹ one billion by selling electricity from it, HPPCL said. The first unit of the project will start generation by May 20 and the second unit by next month, HPPCL said. The mechanical spinning of the first unit of the project was done on April 25, HPPCL said. It has installed capacity of 100 MW with two generating units of 50 MW each. The run-of-the-river project is located on the Sainjriver, a tributary of the Beas. The project comprises a diversion barrage on the river near Niharni village, and an underground powerhouse on the right bank of the river near Suind village. The project has a 6.36-km-long headrace tunnel of 3.85-metre diameter with two Pelton turbines coupled with generating units of 50 MW each. After commissioning the project, the HPPCL said, each family affected by the project will be provided 100 units of electricity per month for a period of 10 years. State’s hydroelectricity generation potential is 27,436 MW, about 25 percent of India’s total potential in the sector. However, only 10,351 MW has been harnessed till December 2016, which is 37.73 percent of the total potential, the state’s Economic Survey 2016-17 said. The second unit of the KNPP was reconnected to the southern power grid. The unit was shut down due to water and steam leakage. KNPP said that the second unit was reconnected to the grid and touched a level of 500 MW during the course of the day. India’s atomic power plant operator, the NPCIL has two 1,000 MW nuclear power plants at KNPP built with Russian equipment. The first unit was shut down on April 13, for annual maintenance and refuelling, a process that would take around two months. Every year, one third of the reactor’s 163 fuel assemblies, or 54 assemblies, will be replaced. In a major decision to fast-track India’s domestic nuclear power programme, the union cabinet approved construction of 10 units of indigenous PHWRs. India’s installed nuclear power capacity is 6,780 MW from 22 operational plants, and another 6,700 MW is expected to be generated by FY22 through projects under construction. The government had in July 2014 set a target of taking nuclear power capacity to over 14,000 MW by 2024. The move will give manufacturing orders to domestic industry to the tune of nearly ₹ 700 billion and is expected to generate more than 33,400 jobs in direct and indirect employment. It would be one of the flagship “Make in India” projects in the nuclear power sector. It is also linked the government’s clean energy goals and low-carbon growth strategy.

In a bid to make India ‘economically independent’, the home-grown FMCG company, Patanjali Ayuveda, is working on a unique renewable source of energy — Bull Power. Detailed research, conducted over a period of one and a half years, on the idea of generating electricity utilising a bull’s pulling power has yielded initial success. The aim is to prevent the animals from being sent to slaughter. Till now, the design, which involves a turbine, has managed to yield nearly 2.5 kilowatts of power, the report said. Ongoing research at Haridwar, is aimed at finding out how many watts of power could be produced in order to light a household by a farmer. A bullock’s strength goes unutilised after about 90 days’ work in the fields, which can be used to generate power. The energy thus generated can also be easily stored. A detailed cost-benefit analysis will be required to ensure that cost of fodder required by the bull is less than the cost of electricity produced.

Rest of the World

New global solar capacity will continue to grow this year, after lower costs drove it to record levels in 2016, and could surpass 80 GW, Europe’s solar industry forecast. Solar photovoltaic module prices have fallen 80 percent since 2009 as capacity has risen and technologies improved. A record 76.6 GW of new solar capacity was installed and connected to the grid last year, 50 percent up on 2015, solar power association Solar Power Europe said in a report. China connected 34.5 GW of solar to the grid last year, representing nearly half of the world’s new capacity and 128 percent more than in 2015. Although many experts say Chinese solar installations could slow this year, China has already commissioned 7.2 GW in the first quarter, slightly higher than what was installed in the first quarter of last year, the report said. Installed solar photovoltaic capacity increased by a third to 306.5 GW by the end of last year, up from 229.9 GW in 2015. That could increase to 400 GW in 2018, 500 GW in 2019, 600 GW in 2020 and 700 GW in 2021, the report said. The US has launched an investigation into imports of photovoltaic or solar cells, to determine if they pose a threat to American industry, the WTO said. This decision followed a request by Suniva, an American manufacturer of solar cells, the US said in a document sent to the WTO. Photovoltaic cells are used to convert sunlight into electricity, for example in solar panels. If that is found to be the case then a WTO member may restrict imports of a product “temporarily,” the trade body said in its statement.

Three fossil fuel industry groups dropped their attempt to intervene in a court case over climate change this week after failing to reach an agreement on a unified legal position on climate science, court filings show. The API and the NAM, prominent trade groups in the oil and gas industry, along with the AFPM, intervened in a federal case in which a group of teenagers sued the US government for violating their constitutional rights by causing climate change. A lawyer representing the three groups said in a court hearing that they were unable to agree on the causes and effects of human activity and greenhouse gas emissions on the climate, transcripts of the proceedings show. One issue for the industry groups is that laying out in court the scientific findings they accept on climate change could bind them to specific positions in other legal proceedings. Exxon Mobil, for instance, a member of both API and NAM, is battling with attorneys general in Massachusetts and New York who are investigating the company for fraud based on apparent discrepancies between its public stance on global warming and internal documents on climate science. According to the RET 2016 Administrative Report released by the Clean Energy Regulator, Australia is on track to meet its 2020 renewable generation target. The report highlights progress toward the RET, which requires Australia to generate 33 TWh of new renewable generation capacity by 2020, resulting in covering more than 23% of power generation with renewables by 2020.In 2016, renewable power plants generated 18.3 TWh. One-third of the new build required to meet the target of 33 TWh was either fully financed or supported by a power purchase agreement in 2016. Once built, this will increase large-scale generation to more than 23 TWh in 2018. During the year, 98 large-scale renewable power plants were accredited, corresponding to a total capacity of 494 MW. The total capacity of committed projects in 2016 reached 1.35 GW, which should generate more than 3.9 TWh per year.

Thousands of Syrian refugees will be able to light their homes, charge their phones and chill their food by solar power as Jordan’s Azraq camp became the world’s first refugee camp to be powered by renewable energy, the UN refugee agency said. Each family in almost 5,000 shelters in the desert camp will be able to use electricity generated by a solar plant. The Azraq camp, in northern Jordan, is home to 36,000 Syrians refugees who will all be able to rely on solar power by 2018, UNHCR said. The switch to solar power will save the agency $1.5 million per year and function even if funding dries out, UNHCR said. The solar plant – which cost almost €9 million ($10 million) – was funded by the IKEA Foundation, which donated €1 to UNHCR for each lightbulb sold in the furniture chain’s stores. The plant will be connected to the national grid and any surplus electricity generated will be sent back for free.

Iowa’s Republican senator raised concerns that United States Energy Secretary Rick Perry has commissioned a “hastily developed” study of the reliability of the electric grid that appears “geared to undermine” the wind energy industry. In a letter sent to Perry, Senator Chuck Grassley asked a series of questions about the 60-day study he commissioned. Grassley said the results were pre-determined and would show that intermittent energy sources like wind make the grid unstable. Perry ordered the grid study and said Obama-era policies offering incentives for the deployment of renewable energy had come at the expense of energy sources like coal and nuclear. Grassley said Iowa gets 36 percent of its electricity from wind and that its largest utility, MidAmerican Energy Co, is on track to generate 90 percent of its electricity from wind in a few years. Grassley said MidAmerican has the ninth lowest electricity rates in the country. Grassley has been a leading proponent in Congress for the continuation of a wind energy production tax credit. The current credit is due to phase out over the next few years before ending in 2020.

Swiss voters will determine the fate of a law proposing billions of dollars in subsidies for renewable energy, a ban on new nuclear plants and a partial utilities bailout. Polling so far suggests the law will be approved in the binding referendum, but support has slipped. A survey this month by research institute gfs.bern for state broadcaster SRG showed 56 percent of voters backed the law, down from 61 percent. The Swiss initiative mirrors efforts elsewhere in Europe to reduce dependence on nuclear power, partly sparked by Japan’s Fukushima disaster in 2011. Neighbouring Germany aims to phase out nuclear power by 2022. Nearby Austria banned it decades ago. Debate on Switzerland’s “Energy Strategy 2050” has focused on what customers and taxpayers will pay for the measures and whether a four-fold rise in solar and wind power by 2035, as envisaged in the law, can deliver reliable supplies. Energy Minister Doris Leuthard, whose government proposed the law, dismisses opposition estimates as highly inflated. She said the package would cost the average family 40 francs more a year, based on a higher grid surcharge to fund renewable subsidies. The law will ban building new nuclear plants. Switzerland has five plants, with the first slated to close in 2019. Voters have not set a firm deadline for the rest, allowing them run as long as they meet safety standards.

According to the EIA, the nuclear power capacity in the US could decrease by more than 20 GW between 2018 and 2050, as 9.1 GW of new capacities are expected over this period, while the retirements of 29.9 GW of nuclear capacity are scheduled over the period. Nearly all operational nuclear plants started operation between 1970 and 1990 and would then require a subsequent license renewal before 2050 to operate beyond the 60-year period covered by their original 40-year operating license and the 20-year license extension that nearly 90% of plants currently operating have either already received or have applied for. According to the EIA’s 2017 Annual Energy Outlook, only four reactors currently under construction and some uprates at existing plants are projected to come online by 2050.

Kazakhstan, the world’s biggest uranium producer, will start producing nuclear fuel for Chinese power plants in 2019 through a JV set up by the two countries, the Ulba Metallurgical Plant said. The JV, Ulba-FA, is now building on land at the Ulba plant, Kazakhstan’s main uranium processing factory. By contrast, the JV between Kazakh state nuclear company Kazatomprom and China’s CGNPC aims to produce ready-to-use fuel assemblies. It will procure enriched uranium either in China or in Russia. The first stage of the JV will produce about 200 tonnes of nuclear fuel a year using technologies and equipment supplied by France’s Areva. Kazakhstan, a former Soviet republic that borders China, has no nuclear power plants of its own.

E.ON has partnered with Google to bring the US search giant’s Sunroof tool to Germany. Around seven million buildings are covered by the website, including those in major urban areas like Munich, Berlin, Rhine-Main and the Ruhr. Using this technology, homeowners can easily and precisely determine their home’s potential solar capacity and generate plans for installing a solar system. All they need to do is enter their address online. E.ON, Google and software producer Tetraeder are joining forces to promote the expansion of solar energy in Germany. The Sunroof website brings together technologies like Google Earth & Maps, 3D models, and machine learning in order to answer inquiries as precisely as possible. Sunroof calculates how much sunlight falls on a roof during the course of a year. It takes into account weather data, the position of the sun in different seasons, the area and slope of the roof as well as shadows from surrounding buildings or trees. Then Sunroof “converts” the data on sunlight into energy and calculates the potential cost savings. During the platform’s launch in Germany, “Sunroof” will be available exclusively at Interested homeowners not only can determine their solar potential, they can also assemble a suitable all-in-one package consisting of a photovoltaic module, an Aura battery storage unit and E.ON Solar Cloud. Moreover, with its “Sunshine Guarantee,” E.ON promises that a solar power system will actually produce the returns calculated – and the company provides financial compensation for any shortfall.

Carl Icahn’s big bet on falling prices for biofuels credits generated a rare profit in that area last quarter for the billionaire investor’s refining company CVR Energy. CVR Energy’s refining unit posted a net gain of $6.4 million associated with the credits, a $50 million turnaround from the year-ago period when CVR shelled out $43.1 million, the company said. Such a gain is extremely rare. Normally, independent refiners spend tens of millions of dollars on biofuels credits. But CVR, majority owned by Icahn, delayed the purchase of about $186 million in credits into 2017 and instead sold millions of them. This occurred as the U.S. government weighed an overhaul of its renewable fuels policy. In February, Icahn, an informal advisor to President Donald Trump, delivered a proposal to revamp the program to the White House. Under the RFS program, the government awards credits to firms that blend biofuels like ethanol in their fuel pool and requires firms that don’t, such as CVR, to buy credits from competitors. Icahn has been among the biggest national critics of the program, arguing it puts merchant refiners at the mercy of speculators operating in an opaque market.

MW: Megawatt, GW: Gigawatt, kWh: kilowatt hour, TWh: terawatt hour GST: Goods and Services Tax, MNRE: Ministry of New and Renewable Energy, RPO: Renewable Purchase Obligations, STFI: Solar Thermal Federation of India, SECI: Solar Energy Corp of India,  EY: Ernst & Young, Ind-Ra: India Ratings and Research, PPAs: Power Purchase Agreements, FY: Financial Year, IEEFA: Institute for Energy Economics and Financial Analysis, IREDA: Indian Renewable Energy Development Agency, CEED: Centre for Environment and Energy Development, MoEF&CC: Ministry of Environment, Forests and Climate Change, HPPCL: Himachal Pradesh Power Corp Ltd, KNPP: Kudankulam Nuclear Power Project, NPCIL: Nuclear Power Corp of India Ltd, US: United States, JICA: Japan Bank of International Cooperation, WTO: World Trade Organisation, API: American Petroleum Institute, PHWRs: Pressurized Heavy Water Reactors, NAM: National Association of Manufacturers, JV: Joint Venture, AFPM: American Fuel & Petrochemical Manufacturers, RET: Renewable Energy Target, UN: United Nations, UNHCR: United Nations High Commissioner for Refugees, EIA: Energy Information Administration, CGNPC: China General Nuclear Power Corp, RFS: Renewable Fuel Standard

Courtesy: Energy News Monitor | Volume XIII; Issue 52


Monthly Power News Commentary: May 2017


According to the power ministry, discoms in BJP-ruled states like Rajasthan and UP are likely to become profitable by next year. In Rajasthan losses of ₹ 150 billion have been reduced to half and by next year the discom would be in profit. In Haryana, one discom is already in profit and another would be in profit next year. In Tamil Nadu where discom had losses of around ₹ 130 billion that has been reduced to ₹ 30-40 billion last year and this year it may break even. Two interesting observations may be made here. The first is that the power ministry has inadvertently admitted that Tamil Nadu is a BJP run state.  Surprisingly none of the mainstream media seemed to have noticed this.  The second is that ‘profitability’ of the discoms of the BJP run states needs to be qualified. Under the UDAY scheme promoted by the central government, discom liabilities are transferred to the state government budget.  Effectively what this means is that if an unemployed son transfers his huge student loan to his father, he can declare himself to have become profitable. This is illustrated clearly in the next news item on the report on UDAY by the RBI. Finances of several Indian states are worsening after they took over the debt of their electricity distributors under the central government’s UDAY initiative, the RBI study said. Additional provisions states may have to make for UDAY, increased calls for farm loan waivers and potential pay hikes for state government employees are other pressure points on state finances, the report said. In this context, implementation of the GST is crucial, given that the centre will compensate states for any loss of revenue in the initial five years after the switch-over to the new tax regime, it said. For FY17, the revised figures for 25 states show that the consolidated fiscal deficit to gross state domestic product ratio (CFD-GSDP) is 3.4%, compared to the budgeted 3%. An increase in capital outlay and loans to power projects under UDAY worsened fiscal indicators. Excluding UDAY, the CFD of these states would have been 2.7% of GSDP, the report said. For FY18, the central bank expects an improvement in the consolidated GFD-GSDP ratio to 2.6% compared to the centre’s budgeted 3.2%. It, however, cautioned that state liabilities may increase going ahead. Apart from UDAY liabilities on their books and farm loan waivers, the RBI study said additional provisions under UDAY to provide working capital for electricity distributors, and state government guarantees towards public sector enterprises, could increase states’ debt.

As UPERC contemplates reducing tariff for industrial units consuming power above a set limit, the industrial sector may be at an advantage. Presently, the commission adopts a ‘telescopic’ tariff structure wherein more power consumption invites higher charges. As in the case of all consumers, electricity tariff for industries too increases from ₹ 7/kWh to ₹ 7.60/kWh when usage increases. Under the proposed changes in the tariff structure, expected to be introduced in the next couple of months, a unit consuming power more than a certain quantum would see tariff rates coming down. UPERC said the move would not only stop industries from moving out of the state but also help attract higher investment and encourage operating units to go in for expansion. UPERC plans to provide 20% rebate on tariff to industrial units which operate between 10 pm and 6 am. So far, the provision was applicable only to steel industries. The electricity regulatory also plans to waive off the system loading charges levied on industries. Power tariff for industries in UP is among the highest. In comparison, industrial power tariff in Gujarat and Maharashtra ranges from ₹ 4.5/kWh to ₹ 6/kWh. UPERC records also show industries account for 22.02% of the total consumption in UP. In comparison, industries in Gujarat consume 51.95% of the total electricity supplied in the state grid. UPERC said less consumption by industries creates imbalance in the over usage pattern. While this is a logical move, it is not clear how many industries will rush into UP on the basis of power tariff alone. Perhaps industries that offer to shelter to aging cows in air-conditioned sheds may find it an attractive option. The UP government has cancelled the long-term PPAs for 3,800 MW as the cost of power under these pacts was higher than the spot market prices. The previous government signed the 15-year contracts with Jindal Power, JP-Nigeri, Lanco, Adani Power, GMR and JSW. Against the 3,800 MW demand, the SP government had received bids for 6,652 MW in the price range of ₹ 3.9-5.5/kWh. The state was currently procuring 3,882 Mw at ₹ 4.06/kWh. Of its total power drawn of 9281 MW, UP sources 4,225 MW from inter-state generating stations, 228 MW from long-term agreement, 364 MW from medium-term agreement, 150 MW through bilateral trade, 26 MW as shared agreement.

India conducted the ground-breaking ceremony for its first green energy corridor project with an UHVDC link over 1,800 km with the aim to bring power to 80 million people. The project by PGCIL is being executed by ABB Group in partnership with BHEL. The mega project is worth over ₹ 43.5 billion. The Raigarh-Pugalur 800 kV UHVDC system aims to connect Raigarh in Central India to Pugalur in the southern state of Tamil Nadu.

It was reported that India has climbed up to 26th position in World Bank’s electricity accessibility ranking in the current year from 99th spot in 2014. By 2019, the government is likely to declare that India is fully electrified in time for the next elections. The government’s rural electrification programme is said to be proceeding swiftly, with over 13,000 villages electrified out of a total of 18,452 and is on track for completion within the targeted 1,000 days. Over 2.2 million rural BPL households were electrified in FY17, and over 40 crore LED bulbs were distributed in the same period. The total inter-regional transmission capacity has been significantly enhanced with 41 GW transmission capacity being added from May 2014 to April 2017. Manipur said all un-electrified villages in Manipur would be electrified by December 2018. Out of a total 4,141 un-electrified villages in the country, Manipur has 85. Not to be left behind, Bihar said every household of the State would have power connection by 2018 end. The government of Bihar has shifted its focus to provide quality power supply and that 633 un-electrified villages would be electrified by December 2017.  Even if the electrification is driven by electoral motives one cannot complain about the poor rural households getting power.  The tragedy is that when the motive is short term electoral gain, the ownership and maintenance of poles and power lines is not established as it is carried out for the centrally sponsored rural electrification scheme.  In addition such schemes do not assign responsibility for continues supply of power.

After Gujarat and Andhra Pradesh, Kerala is readying to enter the select club of fully electrified states. Each and every household in Kerala will have electricity by the end of May. As much as ₹ 7 billion has been pumped in for the electrification drive. a special facility has been created under the umbrella of the KSEB, for the promotion and popularisation of solar energy. Till now, out of the 29 states, only two — Gujarat and Andhra Pradesh — enjoy the status of fully-electrified states in India. The feat required the electrification of around 2.5 lakh households that were yet to have a power connection. Andhra Pradesh, which claims to have attained self-sufficiency in power sector is now gearing up to provide 24×7 three phase power supply to all industrial feeders even in rural areas. The state is contemplating to take up this huge task by segregating agriculture feeders at an approximate cost of ₹ 40 billion sought the support of the union government, to help in promotion of micro & cottage industries and huge employment generation in the mandal headquarters, major gram panchayats and villages. Utilities are said to be fully geared up to meet any hike in power demand. Andhra Pradesh Capital Region Development Authority informed that the utilities are fully geared up to meet any hike in power demand.

State Ministers will consider the possibility of sharply reducing the number of power tariff slabs to make them uniform across the country and examine ways of re-engineering of power plants to use domestic coal in place of imported fuel at a meeting. explore ways of enforcing clean energy purchase obligations of power distribution companies and review challenges in achieving 100% rural electrification in difficult terrain and in left wing extremism affected areas. a rationalization of power tariff slabs across the country will improve transparency and may enhance energy consumption as well as bill collection efficiency. The idea is to have about 15 uniform slabs across the country in place of the highly complex system prevalent in states, where slabs vary significantly. In Tamil Nadu, for example, there are 36 slabs, while Andhra Pradesh has 93. The proposed 15 slabs will have five major classes of consumers-domestic, commercial, agricultural, industrial and institutional—and subclasses based on voltage and consumption. This system will enable providing benefits for “low/efficient consumption and discourage high/wasteful consumption” besides protecting the interests of certain consumers having low paying capacity, said the agenda.

MSEDCL has reduced the duration of power supply to farmers at night. Earlier, the discom used to provide 8 hours three-phase supply during the day and 10 hours during the night on rotation basis. Now, it is providing 8 hours during day as well as night. The company said that the hours of supply would be increased as soon as the power situation normalizes. However, consumer activists have alleged that the power cuts in the state off late were completely unwarranted and illegal. According to them, the discom’s current availability was 33,500 MW and that a tariff order issued in November 2016, determined the excess availability to be in the range of 6,000 MW to 6,500 MW. Agricultural consumers complain of major load shedding hampering the power needs of residential, commercial and agricultural consumers in the district. Lack of maintenance of power generation turbines is the major cause of the power deficit. In order to balance the power supply across the district, MSEDCL has started two hours load shedding of agricultural consumers. The Kolhapur zone of MSEDCL comprises of Kolhapur and Sangli district. The sugarcane farmers there require continuous power to irrigate cane. These farmers will now have to face load shedding of two hours during the night time starting from May 5.

The Supreme Court ruling setting aside a decision of the Central Appellate Tribunal for Electricity, effectively denying ‘compensatory tariff’ to Tata Power and Adani Power, has driven the producers to cut back power supply to Gujarat, citing financial unviability. The two companies have suspended electricity supplies to GUVNL, the parent of discoms in Gujarat, saying higher imported fuel costs had skewed their financial viability. The companies have begun the phased lowering of supply at the peak of summer. Adani Power and Tata Power had discontinued 1250 MW and about 500 MW supply, respectively. EPGL, too, has suspended supply owing to higher international coal prices following changes in Indonesian regulations. Essar Power, too, has filed a tariff review petition with GUVNL. If an order similar to the Supreme Court ruling on Tata Power and Adani Power is passed on the EPGL petition, the company may face cash-flow issues, which will impair its ability to service its loans. The demand for compensatory tariff arose after a change of law by the Singapore government, which escalated the cost of coal imported by Adani Power and Tata Power. The Supreme Court said the change of law was not a valid reason to hike power tariffs. The producers’ hopes now hinge on a favourable ruling by the CERC which was directed by the apex court to examine their demands for compensatory tariff.

India is set to see a countrywide cyber security audit of its power distribution and generation system to prevent hacking as state grids and plants increasingly become smarter with large-scale deployment of digital technology. participants agreed to get their power system — down to the plant level — regularly audited by agencies accredited by the CERT-In of the department of information technology. The states agreed to conduct mock drills simulating disasters and hackings to test preparedness for reviving downed systems. The vulnerability of India’s transmission network to hacking in an ‘intelligent’ environment in which machines ‘talk’ to each other on a common platform. Indian power equipment manufacturers have repeatedly been raising alarm over the issue as city grids are being smartened up with SCADA systems.

Endorsing the linking of the Aadhaar card with payment of electricity bills, was an initiative to help people said the government.  What the government has overlooked is the fact that those who rent houses pay bills that are issued to the owner of the house. Aadhaar linking will complicate things for those who live in rented houses. The government has also asked states to stop accepting electricity bill payments in cash and move to digital mode, a move that can be a giant leap towards a cashless economy as power worth lakhs of crore is consumed every year. The Union power ministry has told state distribution companies to introduce and strengthen online and digital payment mechanism, to begin with in urban areas and gradually to all electricity consumers. Data available with the CEA showed that over 1 trillion units of electricity was supplied across states during April 2016 and March this year. Shifting to an efficient digital payment mechanism could generate over ₹ 3 trillion going by a conservative estimate of ₹ 3/kWh tariff. The power ministry’s Urja portal showed that in urban areas mapped by the 12.4 percent of electricity consumers made digital payments for electricity bills. This was a quantum jump from 8.6 percent digital payments made in October 2016.

Rest of the World

Poland’s biggest power producer PGE has agreed to buy French group EDF’s local power and heating plants for 4. $1.2 billion including debt, in a move to increase market share and give the state more control over the country’s energy assets. The deal to buy EDF’s plants, which include eight combined heat and power plants and a 1.8 GW coal-fired power plant at Rybnik, in the south of the country, is expected to be concluded by January 2, 2018, PGE said. as a result of the acquisition PGE’s share of the country’s power generation capacity would increase to 45 percent from 36 percent, while PGE said the acquisition of the cogeneration plants would increase its district heating interests by 177 percent.

South Africa’s power utility Eskom could cut supplies to neighbouring Zimbabwe by the end of this month if Harare fails to clear arrears. Such a move could trigger widespread power cuts in an economy already battling with a liquidity crunch but which hopes for faster growth this year after rains boosted crop production. Zimbabwe imports 300 MW/day from Eskom, but owes the utility $44.5 million. Acute shortages of foreign currency have seen the southern African nation struggle to pay for imports. Zimbabwe was producing 1,051 MW of power, with another 350 MW coming from imports, against demand of 1,500 MW.

The government of Japan announced to provide a concessional loan of $24 million to the government of Pakistan for Islamabad and Burhan Transmission Line Reinforcement project. The transmission line stabilisation project would be completed in the capital territory by 2020. The financing of the project is Japanese ODA loan, which is long-term low interest rate loan advanced to the developing countries and have the liability of being paid back. So far, the government of Japan has been providing assistance to Pakistan in the power sector through the Energy Sector Reform programme and the National Transmission Lines and Grid Stations Strengthening project. The objective of this loan is to reinforce existing 220 kV transmission lines between Tarbela hydropower plant and the Burhan substation, which will enable it to supply over three times more electricity as compared to its existing capacity. The ODA loan project would not only help stabilise the power supply to the capital territory and surrounding areas, but would also help decrease the transmission losses through introduction of low loss conductor for the first time in Pakistan.

The electricity sales by the ten regional power utilities in Japan contracted by 1.7% in the April 2016 – March 2017 year, posting a new decline for the sixth year in a row. The electricity consumption in Japan has been hit by supply restrictions since the 2011 Fukushima disaster and contracted by 4% between 2011 and 2015. In April 2016, the electricity market was opened up, removing regional barriers and cross-ownership barriers and allowing new suppliers to enter the retail market. Consequently, the ten former regional monopolies lost more than 3.4 million customers, that switched to other suppliers.

UDAY: Ujwal Discom Assurance Yojana, discoms: distribution companies, BJP: Bharatiya Janata Party,  RBI: Reserve Bank of India,  GST: Goods and Services Tax, FY: Financial Year, UPERC: Uttar Pradesh Electricity Regulatory Commission,  km: kilometre, kV: kilovolt, UHVDC: ultra-high voltage direct current, MW: Megawatt, GW: Gigawatt, kWh: kilowatt hour, LED: light emitting diode, PGCIL: Power Grid Corp of India Ltd, PPAs: power purchase agreements, BHEL: Bharat Heavy Electricals Ltd, KSEB: Kerala State Electricity Board,  MSEDCL: Maharashtra State Electricity Distribution Company Ltd,  GUVNL: Gujarat Urja Vikas Nigam Ltd , EPGL: Essar Power Gujarat Ltd, CERC: Central Electricity Regulatory Authority,  CERT-In: Computer Emergency Response Team of India, SCADA: supervisory control and data acquisition, CEA: Central Electricity Authority, ODA: Official Development Assistance

Courtesy: Energy News Monitor | Volume XIII; Issue 51