Public Utilities Commission of Sri Lanka

The Public Utilities Commission of Sri Lanka (abbreviated PUCSL) (Sinhala: ශ්‍රී ලංකා මහජන උපයෝගිතා කොමිෂන් සභාව "Śrī Laṃkā mahajana upayōgithā komishan sabhāwa"; Tamil: இலங்கைப் பொதுப் பயன்பாடுகள் ஆணைக்குழ) is the government entity responsible for policy formulation and regulation of the electric power distribution, water supply, petroleum resources, and other public utilities in Sri Lanka.
The PUCSL was established by the Public Utilities Commission of Sri Lanka Act, No. 35 of 2002, and has authority for the execution of its duties through this Act, as well as through those established for organizations, agencies and corporations involved in providing public utilities in the country. It has a broad mandate to act both as a consumer protection authority, as well as an advisory, inspection and policy formulation body; as such, it is also involved in issuing and enforcing licences that regulate utilities on the island, enforcing contracts between utilities providers and the State, regulating utilities tariffs, resolving disputes (both between utilities providers and the State, and between them and the public), and the establishment and enforcing safety and quality standards within the utilities sector (including standardization of the country's power plugs and sockets). The Commission seeks to promote competition and efficiency among utilities providers, and harmonise the country's utilities sector with international standards.
The Commission has recently been assigned the task of producing Sri Lanka's long-term power generation plan in the middle of power shortages and an impending energy crisis in the country- the Electricity Supply 2020 and Beyond report has been the subject of minor controversy, with unionized employees of the Ceylon Electricity Board in particular taking issue with it.
Organizational structure.
The Director General and Secretary to the Commission both report directly to the Commission, with the latter having oversight of the PUCSL's legal affairs department and internal auditor, while the director general has direct oversight of:
The main departments of the commission are controlled through the deputy director general -
Consumer Consultative Committee.
The Consumer Consultative Committee (CCC) was established under section 29 of the PUCSL Act, in order to act as a forum for the representation of the general public and small industry within the commission and the broader utilities sector, and thus prevent the government and larger industry from dominating policy and regulation. The CCC consists of 15 volunteer members:
The CCC is responsible for consulting the general public on proposed policy changes, current issues in the utilities sector and any other matters that would affect the public, as well as outreach and education of the public on changes to existing regulatory and procedural practices or policies enacted by the State. It is also acts as a distinct advisory body to the Commission by itself.


Roland Winston

Roland Winston is a leading figure in the field of nonimaging optics and its applications to solar energy, and is sometimes termed the "father of non-imaging optics". He is the inventor of the compound parabolic concentrator(CPC), a breakthrough technology in solar energy. He is also a former Guggenheim Fellow, past head of the University of Chicago Department of Physics, a member of the founding faculty of University of California Merced, and as of 2013, head of the California Advanced Solar Technologies Institute.
He holds more than 25 patents, chiefly related to solar energy, and has been figuratively said to have a "patent on the sun".
Early life and education.
Winston enrolled as an early entrant at Shimer College in 1950, transferring to the University of Chicago after two years. He received a BA from Shimer in 1953, in a graduating class of 11, including future cosmologist Jerome Kristian. Continuing with advanced undergraduate study at the University of Chicago, he received a BS in 1956.
Winston remained at University of Chicago for his graduate work in physics, completing his MS in 1957 and his Ph.D. in 1963. He studied under figures including Yoichiro Nambu and Subrahmanyan Chandrasekhar. Winston's doctoral dissertation was on "observable hyperfine effects in muon capture by complex nuclei."
Scientific career.
Winston initially developed the underlying concept of the CPC for use in the study of Cherenkov radiation while working at Argonne National Laboratory in 1966. He was prompted to invent the CPC several years later in 1974, when Argonne director Robert Sachs asked him if it would be possible to extend the parabolic approach to solar energy applications, and if so, whether it would be superior to the existing systems that used imaging optics. Only a year after the invention of the CPC, it was discovered that this design had been anticipated by hundreds of millions of years by the eyes of the horseshoe crab. The paper announcing this discovery was also coauthored by Winston.
A key advantage of the CPC over the earlier imaging collectors was that it could achieve very high efficiencies without needing to track the sun. Non-tracking collectors had previously been believed to be impossible to design. In addition, CPCs received considerable media attention for their ability to function even under heavily clouded and hazy skies.
Winston and Joseph O'Gallagher devised a more refined version of the CPC in 1982, which was smaller and eliminated the need for an extra layer of glass.
In 1988, using a new mirror-based technique, Winston and his team set a new record for concentration of solar energy, concentrating sunlight to more than 60,000 times its normal intensity. In 1989, Winston coauthored with W.T. Welford what became the defining text of the field, "High Collection Nonimaging Optics". Later revised under the name of "Nonimaging Optics", it remains a classic in the field.
From 1989 to 1995, he served as chair of the Department of Physics of the University of Chicago. In addition to his solar energy work, he has continued to work in his original field of high-energy physics, conducting experiments at Argonne and Fermilab.
In 2003, Winston left the University of Chicago, where he had been working and studying since 1952, to join the founding faculty of the University of California Merced. He has however remained connected the U of C and the city of Chicago, and has remained affiliated with the university's Enrico Fermi Institute. In 2004 he partnered with Chicago company Solargenix Energy to create roof-integrated solar cooling and heating systems.
Awards and recognition.
Winston has received numerous awards in the course of his career, including a Guggenheim Fellowship in 1977 and the Joseph Fraunhofer Award for "significant accomplishments in optical engineering" from the Optical Society of America in 2009. He was elected as a US delegate to the International Solar Energy Society in 1991.
Devices to which Winston's name has become attached include the CPC itself, which is sometimes known as a "Winston solar collector", and "Winston cones", the individual parabolic elements that make up a CPC.


HVDC Gotland

The HVDC Gotland, on the Swedish east coast, was the first fully commercial static plant for high-voltage direct current transmission (HVDC) in the world.
Gotland 1.
The first HVDC Gotland link (Gotland 1) went into service in 1954. It could transfer 20 megawatts over a 98-kilometer-long submarine cable between Västervik on the mainland and Ygne on the island of Gotland, with a voltage of 100 kV. As a static inverter, Mercury arc valves were used.
In 1970 the service was re-engineered to transmission capacity of 30 megawatts at a voltage of 150 kV by using the first thyristor module for HVDC applications.
Gotland 2.
However even this capacity was not high enough and in 1983 a new monopolar link, HVDC Gotland 2 with a transmission capacity of 130 MW and a transmission voltage of 150 kV was established. It consists of a 92.9 kilometers long cable with a single copper conductor of 800 mm2 cross section, from which 92 kilometres are submarine and 0.9 kilometres underground. Beside this, HVDC Gotland 2 has a 6.6 kilometres long overhead powerline section between Västervik static inverter plant and the Swedish Coast. It has 2 Aluminium conductors each with a cross section of 910 mm2, which are installed on wooden poles - perhaps the only HVDC powerline using such poles.
Gotland 3.
In 1987 HVDC Gotland 3, a further monopolar link, with a transmission capacity of 130 MW and transmission voltage of 150 kV was installed. It consists of a 98 kilometers long cable with a single copper conductor of 800 mm2 cross section. 92 kilometres of this cable are laid in the sea and 6 kilometres underground on land.
Structure.
The grounding electrode of the Västervik Inverter Station is situated at Almvik on Östra Eknö, that of Ygne Inverter Station at Gravfält. Both electrodes are used for Gotland 2 and Gotland 3 and are situated in sea-water filled basins close to the sea. At Almvik there are 2 such basins, while Gravfält uses only one. The basin design of the electrodes prevents fishes from getting too close to the electrodes, which may harm them.
The Almvik electrode is connected with Västervik Inverter Station by an 18.95 kilometres long line with 4 overhead line and 3 submarine cable sections for strait crossings. The overhead line sections, which have a total length of 17 kilometres are installed on wooden poles and consist of 2 Aluminium conductors each with 910 mm2 cross section. The total length of the cable sections amounts to 1.95 kilometres and consist of 2 cables each with 1000 mm2 cross section. The connection between Ygne Inverter Station and Gravfält Electrode has a length of 12.75 kilometres. It consists of a 12 kilometres long overhead line on wooden poles, which uses 2 Aluminium conductors each with 910 mm2 cross section and a 0.75 kilometres long underground cable consisting of 2 Aluminium conductors each with 1000 mm2 cross section.


Wind power in New Zealand

Wind power in New Zealand generates a small but growing proportion of the country's electricity. As of December 2017, wind power accounts for 690 MW of installed capacity and over 5 percent of electricity generated in the country.
New Zealand has abundant wind resources.
The country is in the path of the Roaring Forties, strong and constant westerly winds, and the funneling effect of Cook Strait and the Manawatu Gorge increase the resource's potential.
These effects make the Lower North Island the main region for wind generation.
About 70 percent of the nation's current installed capacity lies within this region, with some turbines have a capacity factor of over 50 percent in this area.
Generation capacity and expansion.
As of December 2017, New Zealand had an installed wind generation capacity of 690 MW. In the 2017 calendar year, wind power produced 2,120 GWh of electricity, 5 percent of the country's electricity generation that year.
A further 2,500 MW of wind farms have received resource consent.
The New Zealand Wind Energy Association predicts that wind could reach 20 percent of New Zealand's annual generation by 2035.
Wind resources.
New Zealand has outstanding wind resources, due to its position astride the Roaring Forties, resulting in nearly continuous strong westerly winds over many locations, unimpeded by other nearby landmasses at similar latitude. One study found that using 1% of total available land for wind farms would produce approximately 100,000 gigawatt hours (GWh) per year. This is roughly two times the annual electricity consumption of New Zealand. Nearly continuous, however, does not mean continuous: a high-pressure weather system, for instance, sometimes cover the entire country with the result of no significant winds anywhere, and dispatchable sources like hydro and gas must take over via transmission lines like the HVDC Inter-Island.
The strength and consistency of New Zealand winds means the nationwide capacity factor is high compared to other countries, averaging between 30 and 35 percent, with some individual turbines recording capacity factors above 50 percent.
Public opinion.
Wind farms and turbines generate a wide range of opinions from outright opposition to widespread acceptance. Opposition is due to noise, aesthetics and ecological factors.
Coping with intermittency.
Wind farms partner nicely with hydro plants on the same grid to create combined power plants, because hydro plants can be uprated with extra turbine units to provide highly dispatchable peak generating capacity above the average flows of their rivers, at lower cost than other peak power options. During periods of high wind and low electricity demand, a hydro plant can reduce its output to accumulate water in its reservoir, whilst wind power handles a higher share of the grid load. Then during periods of low wind, the hydro plant can raise its output temporarily, drawing down its reservoir a bit. Given New Zealand's large proportion of hydroelectric generating capacity, it is better-positioned than most nations to uprate its generating stations and grid to handle intermittent power sources such as wind and solar. The available virtual energy storage represented by hydro plants can be one of the main factors limiting the maximum amount of wind and solar power that a grid can accommodate. Further increases in intermittent power source development may require construction of pumped-storage hydroelectricity and implementation of energy demand management techniques.
List of operating wind farms.
Only wind turbines and farms over 5 MW generating capacity are listed.
Individual demonstration and prototype wind turbines have been installed at Southbridge in Canterbury, Gebbies Pass near Christchurch and at Brooklyn in Wellington.
Many small windmills serve as windpumps on New Zealand farms.
Meridian Energy also operates a 1 MW wind farm on Ross Island, Antarctica. It is not included in the above list as it doesn't contribute electricity to the New Zealand national electricity network.


Saubhagya scheme

The Saubhagya Scheme or Pradhan Mantri Sahaj Bijli Har Ghar Yojana is an Indian government project to provide electricity to the households. The project was announced in September 2017 by Prime Minister Narendra Modi, who said that the aim was to complete the electrification process by December 2018. Certain households identified via the Socio-economic and Caste Census (SECC) of 2011 will be eligible for free electricity connections, while others will be charged Rs. 500. On 16 November, 2017, the government launched a website saubhagya.gov.in to disseminate information about the scheme. The total outlay of the project is Rs. 16, 320 crore while the Gross Budgetary Support (GBS) is Rs. 12,320 crore.
The beneficiary household will get One LED lights, one DC power plug. It also includes the Repair and Maintenance of Meter Only (R&M) for 5 years.
Responses.
91% of rural Indian households have received electricity access by june 2019. Commentators have noted that while the scheme would provide the capacity for electricity in poor and rural households, it did not solve the problem of power outages and made no provision for cases where households could not afford electricity bills. In October 2018, Bihar completed its target of 100 per cent electrification of willing households under Saubhagya scheme.


Genalta Power

Genalta Power is an independent power producer based in Calgary, Alberta. The company was founded in 2008 and specializes in distributed generation facilities ranging from 2–50 megawatts. The company builds, owns, operates and maintains power plants that utilize wasted or under utilized energy resources.
The company has undergone several rounds of financing with strategic financial partners to build over 66 MW of power producing assets and in October 2020 allied with Capstone Infrastructure to enable Genalta to continue to develop carbon-neutral distributed generation facilities throughout Alberta and Saskatchewan.
The company was the first company in Alberta to earn carbon credits by converting flare gas to electricity.


Aniwhenua Power Station

The Aniwhenua power station is a hydroelectric power facility in Bay of Plenty in New Zealand located on the Rangitaiki River upstream of the Matahina Power Station. Water is drawn from behind a dam above the Aniwhenua Falls and diverted through a canal and a headpond to the power station before being discharged back into the river. The power station is named after the falls which are adjacent to the power station.
History.
Development.
In the late 19th century and early 20th century, numerous small local power generation stations were built by both private and local authorities. From the 1920s onward as the state electricity system expanded and the national grid was developed, development of small local power stations declined as the centralisation of electricity supply under state control increased.
The 1973–74 oil shock, nation-wide electricity shortages during the winters of 1973 and 1974, a renewed policy emphasis on regional development by central government, and increased uncertainty as to future wholesale electricity price trends lead to the New Zealand government to re-evaluate its policy regarding local hydro development. As a result, in 1977 the government announced that they would subsidize local power station schemes of less than 50 MW by providing grants to cover the investigation and design work, cheap loans to finance construction as well as loans from the NZED to cover operating losses in the early years of approved schemes. The government established the Committee on Local Authority Hydro Development (CLAHD) to evaluate applications for grants or loans from supply authorities.
Taking up this opportunity the Bay of Plenty Electric Power Board which had begun operations in 1928 and engaged consultants to investigate a local hydro scheme in mid-1973. Preparation of a feasibility report was authorised in December 1973, with the report being completed in September 1974. The study determined that a power station on the Rangitaiki River at its confluence with the Pokairoa Stream, midway between Murupara and Whakatane. The scheme was technically feasible and financially viable. The main identified environmental impacts were significantly reduced flows over the Aniwhenua Falls, inundation of productive farm land and the displacement of one family, as well as the long term accumulation of sediment in the lake that the project would create. The issue of the reduced flow was managed by the imposing of a minimum residual flow over the falls.
The estimated cost was NZ$12.5 million.
Construction.
Following the obtaining of water rights, government consent and other necessary approval, construction and equipment supply contracts were let in the second half of 1977.
The civil works which commenced by the end of 1977 constructed by Downer and Company which involved the excavation of one million tons of material and the placing of 270,000 cubic metres of fill, 20,000 cubic metres of concrete and 884 tonnes of reinforcing steel.
Commissioning.
Aniwhenua began generating on 3 October 1980. The 1982 annual report for the board showed that the total cost of the station to 31 March 1982 was $27,767,203 of which $24,628,809 was financed by government loan. The book value of the scheme as at 31 March 1992 was $21,109,000. By the 1985/86 financial year, the scheme was breaking even financially and was able to trade its way into long-run profit without any write-offs of debt. Over the period from 1989 to 1992 as its trading activities were making a loss the profits from Aniwhenua kept the power board in the black.
Service.
The Energy Companies Act was enacted in 1992, and amended later that year. This act required the corporatisation of the electricity and gas undertakings of electric power boards and municipalities with the aim of ensuring a commercial and efficient approach to electricity distribution and supply.
As a result, the power board was forced in August 1994 to vest all of its assets including Aniwhenua and associated water rights to the Bay of Plenty Electricity Limited. Bay of Plenty Electricity subsequently became the first electricity company to be listed on the New Zealand stock exchange.
Purchase by Nova Energy.
In July 1998 the New Zealand Government passed the Electricity Industry Reform Act which was intended to change the structure of the electricity industry to encourage competition. This Act required the operational separation of distribution and generation business activities by 1 July 1999 and separation of the ownership by 1 January 2004.
As a result, in 1998 Bay of Plenty Electricity sold its retail and generation business, together with its name to Nova Energy, which was owned by the Todd Corporation. On 1 April 1999, the remaining distribution assets were transferred to a new company, Horizon Energy Distribution Limited (which operates these assets under the name of Horizon Networks).
Leak.
After a serious leak developed in the dam during Nova's ownership. Following investigations and development of a solution by consultants Tonkin + Taylor, the contracting firm of Waiotahi Contractors commenced in February 2006 the 58 day repair of the leak which took 58 day at a cost NZ$2.78 million.
Purchase by Southern Generation Partnership.
Looking to raise capital to invest in other energy projects in the North Island Nova agreed to sell Aniwhenua in November 2015 to Southern Generation Partnership (a partnership between Pioneer Generation Investments and Roaring Forties) for approximately NZ$100 million with ownership transferring in April 2016. The Roaring Forties is a partnership between The Power Company and Electricity Invercargill.
At the beginning of December 2018 Pioneer Energy took over the services agreement with the Southern Generation Partnership to operate and maintain the power station.
Design.
A 200-metre-long, 10-metre-high dam located upstream of the eight-metre-high Aniwhenua Falls impounds the Rangitaiki River and Pokairoa Stream at their confluence at Black Road, Galatea, approximately 65 km upstream from the river mouth to create Lake Aniwhenua. Smaller dams also divert water from the Pokairoa into Lake Aniwhenua. The lake is 4.5 km long by approximately 500 m wide and is 255 ha in area. The maximum depth of the lake is 10 metres at the dam but it is typically less than three metres deep in other locations. The dam contains two wheeled penstock intake closure gates, two radial spillway gates which can discharge 1,270 cumecs of water. As well there are three additional flap type flood gates designed to handle higher flood conditions.
From the dam a 2.2 km long concrete-lined canal conveys water to the Pahekeheke Headpond, which was created by damming the Pahekeheke Stream. From the headpond two penstocks transport the water down to a powerhouse containing two Escher Wyss vertical Francis turbines which are each directly coupled to an ASEA 11 kV 12.5 MW synchronous generator. The station produces on average 127 GWh per annum. The output from the generating units is discharged back to the river just below the falls. The generator size was based on the desire to meet the power board's load factor of 65%.
The power station has a head of 38 metres.
Compensation water of a 2.5 cumecs is also released from the dam to preserve the original river channel and maintain flow over the falls.
A small turbine coupled to a 100 kW generator is driven by the compensation flow and supplies power to the local distribution network via Horizon Energy's Galatea feeder.
Compensation water is also released from the headpond through a draw off pipe into the original course of the Pahekeheke Stream.
Via two 11/33 kV step-up transformers Aniwhenua is the primary supplier of electricity to Horizon Network's distribution network in the Galatea and Kaingaroa regions via a single 33 kV feeder that runs to Snake Hill and then splits into two feeders to supply Galatea with a further single feeder from Galatea to Kaingaroa. Any surplus above this local demand is exported via a 110 kV circuit to the Matahina Power Station where the two power stations combine to export electricity to the national grid via two 110 kV circuits to Transpower's Edgecumbe Substation.
Operation.
For transmission pricing purposes a Prudent Discount Agreement exists for Aniwhenua that makes it part of the Edgecumbe GXP. Aniwhenua is operated to maximise injection into the Horizon network. If there is any generation in excess of local load, this is exported to the national grid. As a result, the power station is effectively embedded.
Operation of the power station is covered by the requirements of five resource consents, with the principal consent expiring in September 2026. The lake level operates between a normal operating range of 146.1 to 146.8 metre RL (relative to the Moturiki datum) with the emergency spillway having a level of 148.6 metre RL. The power station operates as a run of river scheme as the lake is small in terms of river flow. Low overnight demand allows refilling of the lake and drawdown to provide increased generation over the daytime peaks. and
The power station typically generates at least 8 MW, as below this value it will be necessary to spill water which will impact on the river downstream.
There is an ongoing programme to transfer migrating elvers and eels both upstream and downstream from the lake, to maintain eel stocks.
Sedimentation.
The headwaters of the Rangitaki River collect lightweight pumice sands and partly greywacke gravels which are deposited in the lake. During its first 15 years of operation the lake accumulated approximately 1.5 million m3 of sediment. Loss of storage has been managed by constructing training banks to encourage the sediment to settle in the deeper areas of the lake as well as lowering of the lake and flushing during floods.
In addition, it has been necessary to undertake limited dredging operations to remove sedimentation with 30,000 m3 removed in 2002.


Valve hall

A valve hall is a building which contains the valves of the static inverters of a high-voltage direct current plant. The valves consist of thyristors, or at older plants, mercury arc rectifiers. Mercury arc rectifiers are usually supported by insulators mounted on the floor, while thyristor valves may be either supported by insulators or hung from the roof of the valve hall. The latter required a stronger ceiling structure, however the hall and the static inverter can better survive earthquakes compared to valve structures standing on the floor.
A valve hall is equipped with heating and cooling equipment to control the temperature of the mercury arc rectifiers (which operate best over a narrow temperature range) or thyristors. The valve hall also protects the valves from weather and dust. Several valve assemblies, connected in series for the required terminal voltage, may be installed in the valve hall building.
High voltage bushings are supported through the walls of the valve hall, to allow connections between the converter transformers on the one side and the DC switchyard on the other. Beside the valve hall there is often an additional building, in which are control electronics, equipment for valve cooling and valve monitoring, station service power distribution, and amenities for the plant workers.
Because very high voltages are present while the inverters are in operation, access to the valve halls is limited while the static inverter is running. The auxiliary control building may have windows to observe the valve hall, but usually the converter is remotely controlled. To protect communication systems from electromagnetic interference, valve hall buildings must have shielding installed to control emission of radio-frequency energy.
At some HVDC converters such as at Cabora-Bassa, outdoor valves are installed in oil-immersed containers. At such plants no valve halls or wall bushings are required.


Mount Salak

Mount Salak (, ) is an eroded volcano in West Java, Indonesia. It has several satellite cones on its southeast flank and the northern foot, along with two additional craters at the summit. Mount Salak has been evaluated for geothermal power development.
According to a popular belief, the name "Salak" derived from "salak", a tropical fruit with scaly skin; however, according to Sundanese tradition, the name was derived from the Sanskrit word "Salaka" which means "silver". Mount Salak can be translated to "Silver Mountain" or "Mount Silver".
Geology.
Mount Salak is an adesetic stratovolcano with its last recorded eruption in January 1938.
On October 10, 2018, there was a false alarm, as the VAAC in Darwin said that there was a sudden eruption and that an ash plume from the volcano had risen to 15 km, or 50,000 feet. After a period of no confirmation of whether an eruption took place or not, it was determined that an eruption had indeed not taken place and that the initial report that one took place was false.
Climbing routes.
Mount Salak offers several routes for climbing. The route most often climbed is Curug Nangka, in the northern part of the range. Peak I is visited via easier routes from the east, through Cimelati and Cicurug. Peak I also can be reached by more challenging routes, from Peak II via Sukamantri and Ciapus. An additional alternate route is "the back way" through Cidahu, Sukabumi, and Kawah Ratu near Bunder Mount.
Mount Salak is popular for many mountain climbing clubs, especially Route II, because of the difficulty involved in reaching the peak. Climbers bring water with them, especially through Post I at Kawah Ratu Route. A water source, supplied by rain, exists at an altitude of on this route.
Cimelati can be reached from Cibuntu Village. Water is scarce in parts of this region. An irrigation system ensures that water is plentiful until Post/Shelter III. Beyond this point, travelers must carry water. The route itself is scenic, with several waterfalls as well as a large villa appearing before reaching Post/Shelter I.
Animals.
Mount Salak is a habitat for a variety of animal species, including frogs, toads, reptiles, birds, and mammals. During research, D. M. Nasir (2003) from KSH forest faculty IPB found 11 frog and toad species in Lingkungan S (Environment S) at Ciapus Leutik, Desa Taman Sari, Bogor Residency. They are the "Asian giant toad", the "Asian common toad", the "Java spadefoot toad", the "Indian cricket frog", "Huia masonii", "Limnonectes kuhlii", "Limnonectes macrodon", "Limnonectes microdiscus", "Rana chalconota", "Rana erythraea", and "Rana hosii". The findings did not include tree toads and other mountain toads that might also be found there. At Cidahu, bangkong bertanduk ("Megophrys montana") and katak terbang ("Rhacophorus reinwardtii") were found.
Many reptiles, including lizards and snakes, live on Mount Salak. These include the chameleons "Bronchocela jubata", "Bronchocela cristatella", Kadal Kebun ("Mabuya multifasciata") and Biawak Sungai ("Varanus salvator"). Some snakes living in Mount Salak are Ular Tangkai ("Calamaria sp."), Ular Siput ("Pareas carinatus"), Ular Sanca Kembang ("Python reticulatus"), and many more. Mount Salak has become famous for its habitat for birds; there are at least 232 birds species in total. The most notable birds are Elang Jawa ("Spizaetus bartelsi"), Crested Serpent Eagle ("Spilornis cheela"), Ayam Hutan Merah ("Gallus gallus"), "Cuculus micropterus", "Phaenicophaeus javanicus", "Phaenicophaeus curvirostris", "Sasia abnormis", "Dicrurus remifer", "Cissa thalassina", "Crypsirina temia", Burung Kuda ("Garrulax rufifrons"), "Hypothymis azurea", "Aethopyga eximia", "Aethopyga mystacalis", and "Lophozosterops javanicus". The notes about mammals indicate that there are not many living on Mount Salak, aside from leopards, silvery gibbons, Javan surilis, and sunda pangolins.
Aircraft accidents.
In 2012, "The Jakarta Post" dubbed Mount Salak an "airplane graveyard". High turbulence and fast-changing weather conditions of the mountainous terrain are cited as contributing factors to multiple aviation crashes in the area. There were seven aviation crashes around Mount Salak between 2002 and 2012.
One person was killed in the crash of a small aircraft in October 2002, seven in October 2003, two in April 2004, and five in June 2004. Eighteen people were killed in a crash of an Indonesian Air Force military plane in 2008.
In 2012, three people were killed in a crash of a training aircraft not long before the SSJ-100 crash, which occurred on May 9, 2012: a Sukhoi Superjet 100 crashed into the mountain during a demonstration flight, killing all 45 people on board.


Blackhillock Substation

Blackhillock Substation is an electrical substation located in the north east of Scotland, near the town of Keith in Moray.
It is owned and operated by Scottish Southern Electricity Network (SSEN). Covering an area the size of 24 football pitches, it is as of January 2019, the UK's largest substation and Europe's second biggest.
Construction began in early 2015 to upgrade the existing substation so it could accommodate the new Caithness - Moray Link. The £1bn construction project had four main elements: 400kV and 132kV gas-insulated substations, one 275kV air-insulated substation, a High Voltage Direct Current (HVDC) converter for the Caithness - Moray subsea link and a HVDC underground cable from the substation to Portgordon. In January 2019 construction and commissioning were completed making it the UK's largest operating substation. It is seen as integral to the UK electricity grid as the north of Scotland generates much renewable energy via windfarms. The upgrade was primarily done to accommodate the Beatrice Windfarm.


Geothermal power in Indonesia

Geothermal power in Indonesia is an increasingly significant source of renewable energy. As a result of its volcanic geology, it is often reported that Indonesia has 40% of the world's potential geothermal resources, estimated at 28,000 megawatts (MW).
With an achievement of 1,924.5 MW it put Indonesia in second place in the world after the United States in utilizing geothermal power, shifting second position previously occupied by the Philippines. In 2007, geothermal energy represented 1.9% of the country's total energy supply and 3.7% of its electric power.
At the 2010 World Geothermal Congress in Bali, President Susilo Bambang Yudhoyono announced a plan to build 44 new geothermal plants by 2014, more than tripling capacity to 4,000 MW. By 2025, Indonesia aims to produce more than 9,000 MW of geothermal power, becoming the world's leading geothermal energy producer. This would account for 5% of Indonesia's total energy needs.
A detailed report on the geothermal sector in Indonesia issued in 2015 by the Asian Development Bank and World Bank, "Unlocking Indonesia's Geothermal Potential", indicated that reforms in key areas of policy were likely to be needed to stimulate sustained expansion in the sector.
History.
The first proposal on energy from volcanoes came in 1918 during the Dutch colonial era. In 1926, five test borings were drilled in Java's Kawah Kamojang field, the third being the first that was successful. In the early 1980s, it was still discharging superheated steam from a depth of 66 metres at a temperature of 140 °C and a pressure of 3.5 to 4 bars. A prefeasibility study for electricity generation was initiated in 1972 by Geothermal Energy New Zealand. The first generator was inaugurated in 1983 by President Suharto and subsequently expanded in 1987. Current capacity is 140 MW.
Since the mid-1980s, Chevron, the world's largest geothermal power producer, has operated two geothermal fields in West Java at Salak and Darajat with a combined capacity of around 365 MW. Between 1989 and 1997 explorations were conducted at the Sibayak geothermal field in northern Sumatra, and subsequently a 12 MW plant has been placed in operation.
In 1991, the Indonesia Geothermal Association ("Asosiasi Panasbumi Indonesia" - API), a non-governmental organisation, was established to promote and advertise geothermal energy. It has approximately 500 members including geothermal experts, companies, and stakeholders. The Wayang Windu Geothermal Power Station in West Java, owned by British Star Energy, has been in operation since 2000. It currently comprises two units with a total capacity of 227 MW. There are plans for a third unit of 127 MW which is expected to be on-stream by mid-2013.
Exploration and development.
Exploration of the Bedugul Geothermal Field in Bali started in 1974 and though production capacity was estimated at 175 MW in 2008, the project is on hold after being opposed by local residents.
At the 2010 World Geothermal Congress in Bali, several companies were awarded the rights to develop geothermal fields and power plants: Golden Spike Indonesia won the tender to develop a power plant at Mount Ungaran in Central Java, Sokoria Geothermal Indonesia gained rights to develop a plant at Ende, on Flores island, while Supreme Energy was chosen to develop plants at Mount Rajabasa in Lampung and Solok in West Sumatra. These projects were estimated to require a total investment of US$1.68 billion.
As of 2010, a total of 265 potential sites for plants have been identified across the country. Development of the industry, however, involves a range of complex policy issues, some of which are proving to be a continuing source of controversy. In mid-2011, for example, the Indonesian Government issued an expected regulation providing certain guarantees for investors with the aim of encouraging increased investment in the geothermal sector. However, investor response was guarded, suggesting that key aspects had not been addressed in the regulation.
In late 2013, PT Pertamina Geothermal Energy (PGE) -- a geothermal business branch of state oil and gas company PT Pertamina—said that it planned to develop eight new geothermal plants with a total capacity of 655 MW (expected to require $2.0 bn of new investments). These included:
Of these, several were to be financed with loans from World Bank and Japan International Cooperation Agency.
In addition, work is starting on the Sarulla geothermal plant in North Sumatra with a total planned capacity of 320 MW. The plant has been on the books since the early 1990s but development was stalled over various issues. The plant, expected to cost around $1.65 billion, will be built with financial support from the Asian Development Bank along with the Japan Bank for International Cooperation and other lenders. The first 110 MW started in 2017.
Installed capacity.
According to the Renewable Energy Policy Network's "Renewables 2013 Global Status Report", Indonesia has the third largest installed generating capacity in the world in the geothermal sector. With 1.3 GW installed capacity, Indonesia trails only the United States (3.4 GW) and the Philippines (1.9 GW). However it leads Mexico (1.0 GW), Italy (0.9 GW), New Zealand (0.8 GW), Iceland (0.7 GW), and Japan (0.5 GW).
Recent developments.
In recent years, the Indonesian Government has announced plans for two 'fast-track' increases in the total capacity of Indonesia's electricity generation network of 10,000 MW each. Under the second 10,000 MW fast-track plan it was forecast that a relatively large share of 3,970 MW would be installed in geothermal plants. But under the first 10,000 MW fast-track plan, investment in the geothermal sector appears to be lagging.
Policy issues.
Expansion in the sector appears to be being held back by a range of factors including an uncertain regulatory environment (including, especially, uncertainty over land laws) and the perceived risks of development. The Indonesian Government's plans for development of the geothermal sector rely largely on private sector investment. But numerous reports indicate that private sector investors are concerned about a range of risks including technical (geological) risks, regulatory risks stemming from uncertain government policy, and financial risks arising from the pricing policies determined by the Indonesian Government. For example, coal has been indirectly subsidised through the Domestic Market Obligation policy, which requires coal companies to sell at a government-specified, subsidised rate to the national utility. By comparison, geothermal power has enjoyed relatively unfavourable tender processes and is sold at higher prices. This makes it difficult for geothermal plants to compete with conventional fuels.
There is disagreement within the Indonesian Government as to how to mitigate risks or, where that is not possible, who should bear these risks. Policy makers in the power sector, with an eye to meeting the government's official investment targets, are often inclined to the view that at least some of the risks should be borne by the Indonesian Government through the national budget managed by the Ministry of Finance. Official policy from the Ministry of Finance has traditionally been cautious, resisting the suggestion that unspecified risks should be borne by the Indonesian budget.
In response to reports about certain of the risks that private sector investors were concerned about, in mid-2011 the government issued a regulation intended to provide guarantees that the state electricity utility PLN would meet financial obligations to independent power producers (IPPs) who invested in the geothermal sector. But the regulation was quickly criticised by representatives of private investors as being too limited and for failing to clarify important concerns.
Pricing policy
Prices have been another important policy issue in the sector. In an effort to encourage private sector investment, the Indonesian government has been establishing a feed-in tariff scheme by instructing state electricity utility PLN to purchase power from geothermal projects at various rates ranging from around 6.5 US cents to over 12 US cents per kWh. The government is also preparing a regulation that is expected to specify the price that the PLN must purchase power from geothermal plans in the second 10,000 MW fast-track electricity sector program which the government has announced; this regulation is expected to be finalised by early 2012.
Environmental issues.
According to the Ministry of Forestry, around 80% of geothermal reserves are located in designated conserved forest areas. The 2009 mineral and coal mining law lists geothermal exploration as a mining activity so a presidential decree would be required to allow geothermal activities within conserved forest areas. According to the ministry, geothermal mining is unlikely to cause environmental harm. In May 2011 the Indonesian government imposed a two-year moratorium on logging. However this excepts the energy sector, including geothermal activities.


Central West Public Service Corporation

Central West Public Service Corporation was a Chicago, Illinois-based utility company that operated in Iowa, South Dakota, Texas, and Minnesota. It owned stock in other utilities that operated in Illinois, North Carolina, North Dakota, Nebraska, Virginia, and West Virginia.
Its failure in 1934 reflects the difficult economic climate of the Great Depression and the inability of large utilities, with significant market capitalizations, to remain solvent.
Insolvency.
The power corporation went into receivership in March 1934 after defaulting on interest payments on its first lien collateral gold bonds, its ten-year convertible 6% debentures, and its 7% gold notes. Three receivers for the firm were appointed, first in Wilmington, Delaware and Sioux City, Iowa, and later in Chicago. Central West Public Service Corporation reported an outstanding indebtedness of $12,800,000 at the time of its
failure.


HVDC BorWin2

HVDC BorWin2 is a high voltage direct current (HVDC) link built to transmit offshore wind power to the power grid of the German mainland. The project differs from most HVDC systems in that one of the two converter stations is built on a platform in the sea. Voltage-Sourced Converters are used and the total cable length is 200 km. The project was completed by the Siemens/ Prysmian consortium and handed over to its owner, TenneT, in January 2015, becoming the first such project to be completed (the earlier HVDC BorWin1 project, despite having completed construction in 2009, was still not fully in service by that date).
Context.
BorWin2 is part of an ambitious programme of providing grid connections to offshore wind parks off the coast of Germany, in the German Bight, as part of the German Energiewende (Energy Transition) programme. BorWin2 forms part of the "BorWin cluster", named after the German island of Borkum. BorWin2 has been built to transport power from the 400 MW Veja Mate (using 6 MW Siemens gearless turbines) and Global Tech 1 wind parks.
HVDC has been chosen for most of the grid connections because the relatively long distance involved – both from the wind park to shore and from the shore to the nearest suitable connection point to the onshore grid - makes conventional alternating current transmission uneconomic.
Technical aspects.
BorWin2 uses Voltage Sourced Converters (VSC) to convert from AC to DC and back again, using 4.5 kV IGBTs as the switching elements. One converter is provided at each end of the link with a DC voltage of ±300 kV and a transmission capacity of 800 MW. The converters, built by Siemens, use the Modular Multi-Level Converter technology, in the symmetrical monopole configuration. Each converter station is equipped with two, three-phase transformers, each rated at 590 MVA (offshore) and 585 MVA (onshore). Each converter valve is equipped with a dry-type valve reactor of 50 mH.
The offshore converter is located on the BorWin Beta platform, which was built by Nordic Yards in Warnemünde. The "topside" of the platform is of the "float-over" type which is designed to be floated out to the installation site and then jacked up onto the submerged supporting structure using the support legs that are integral to the structure. The topside has a total weight of 12000 tonnes and measures 72.5 m x 51 m x 25 m high.
Each of the two 300 kV cables linking BorWin Beta to the onshore substation has a total length of 200 km, of which 125 km is sea cable and 75 km is underground land cable. The cables cross the small island of Norderney and, having reached the mainland, continue, as land cables, to the onshore converter station at Diele. The cables were supplied by Prysmian and use extruded Cross-linked polyethylene insulation.
Construction schedule.
The BorWin2 project was ordered in 2010. The platform was installed in April 2014. Commissioning was completed in November 2014 and the project was handed over in January 2015.


Electricity sector in the Dominican Republic

The power sector in the Dominican Republic has traditionally been, and still is, a bottleneck to the country's economic growth. A prolonged electricity crisis and ineffective remedial measures have led to a vicious cycle of regular blackouts, high operating costs of the distribution companies, large losses including electricity theft through illegal connections, high retail tariffs to cover these inefficiencies, low bill collection rates, a significant fiscal burden for the government through direct and indirect subsidies, and very high costs for consumers as many of them have to rely on expensive alternative self-generated electricity. According to the World Bank, the revitalization of the Dominican economy depends greatly on a sound reform of the sector.
Electricity supply and demand.
Installed capacity.
Electricity generation in the Dominican Republic is dominated by thermal units fired mostly by imported oil or gas (or liquefied natural gas). At the end of 2006, total installed capacity of public utilities was 3,394 MW, of which 86% was fossil fuels and 14% was hydroelectric. The detailed share for the different sources is as follows:
"Source": Electricity Superintendence Statistics, 2006
Total electricity generated in 2006 was 10.7 TWh. Generation experienced a 7.7% annual increase between 1996 and 2005. However, between 2004 and 2006, there has been an average annual decrease of about 10% in total electricity generated.,
Planned expansion.
Currently, there are plans for the construction of two 600MW coal-fired plants, Montecristi and Azúa, by the private sector. It is also expected that, by 2012, an additional 762MW of hydroelectric capacity will have been added to the generation system. The first three hydropower plants with a combined capacity of 240MW are:
The two first plants are already under construction.
Alternative sources for self-generation.
As a response to the electricity supply crisis (see The crisis below)., many consumers turned to alternative self-generation units such as small diesel generators, inverters, kerosene lamps or large power generators (for large industrial consumers). It is estimated that total installed capacity in 2006 was 5,518MW, which means that self-generation accounted for about 2,214MW, equivalent to 63% of the 3,394MW total capacity of public utilities and 38% of total installed capacity. The costs associated with this self-generation capacity are very high as they include equipment purchase, maintenance and fuel supply. This affects the residential, commercial and industrial sectors. For the latter, about 60% of its electricity consumption is self-generated.
Demand.
Electricity demand in the Dominican Republic has grown considerably since the early 1990s, at a yearly average of 10% between 1992 and 2003. Consumption is very close to the regional average, with annual per capita consumption of 1,349 kWh in 2003. Total electricity sold in 2005 was 3.72 TWh. Demand has constrained supply (see The crisis below), which in turn is limited by subsidies (see subsidies below)
In 2001, the share of each sector in the electricity sold by the three distribution companies (EdeNorte, EdeSur and EdeEste) was as follows:
Demand projections.
Annual demand increase has been estimated at about 6% for the upcoming years.
Access to electricity.
Distribution networks cover 88% of the population, with about 8% of the connections thought to be illegal. Government plans aim to reach 95% total coverage by 2015.
Service Quality.
Service quality in the Dominican Republic has suffered a steady deterioration since the 1980s. Frequent and prolonged blackouts result mainly from financial causes (i.e. high system losses and low bill collection) that are further aggravated by technical factors (i.e. unadequate investments in transmission and distribution). Poor service quality is also characterized by large voltage and frequency fluctuations.
Interruption frequency and duration.
The transmission system in the Dominican Republic is weak and overloaded, failing to provide reliable power and causing system-wide blackouts. East-west and north-south transmission lines need to be reinforced in order to deliver electricity to the capital and northern regions and to transmit power from the new power plants in the eastern region.
Distribution losses.
Distribution is the most dysfunctional element of the country's power system. Distribution losses in the Dominican Republic have historically been high and have increased even further in recent years. In 2005, the percentage of losses was 42.5%, up from 28.5% in 2002. This is far above the 13.5% average for LAC. Sustained poor service quality and relatively high prices have induced theft through illegal connections and non-payment of electricity bills. Recent data for 2007 show that only about 59% of power purchased by the distribution companies is eventually paid for by consumers (88% would be the target percentage for a well-managed distribution company ). Although still very low, this percentage has shown an improvement up from about 52% in 2005.
Responsibilities in the electricity sector.
Policy and regulation.
The National Energy Commission ("Comisión Nacional de la Energía", CNE) is the policy agency, one of its main responsibilities being the elaboration of the National Energy Plan. The CNE presented in 2004 the National Energy Plan for the period 2004-2015 as well as the Indicative Plan of Electricity Generation (PIEGE) for the period 2006-2020.
The Electricity Superintendence ("Superintendencia de Electricidad", SIE) is the regulatory agency, while the Coordination Agency ("Organismo Coordinador", OC) was created to coordinate dispatch of electricity.
The Dominican Corporation of State Electricity Companies ("Corporación Dominicana de Empresas Eléctricas Estatales" - CDEEE) is a holding company that brings together all government-owned generation, transmission and distribution companies and associated government programs in the country. It consists of:
EdeNorte and EdeSur are entirely government-owned, the remaining 50% shares being held by the government's Enterprise Trust Fund, Fondo Patrimonial de las Empresas (FONPER). EdeEste is a mixed private-public company.
Generation.
86% of generation capacity is privately owned (excluding self-generation), and 14% is publicly owned. Generation capacity is shared among the different companies as follows:
"Source": Electricity Superintendence Statistics
Transmission.
The transmission system, which is under the full responsibility of the state-owned company ETED (Electricity Transmission Company), consists of 940 km of 138kV single-line circuit lines that radiate from Santo Domingo to the north, east, and west.
Distribution.
In the Dominican Republic, there are three distribution companies. The government owns two of them, EdeNorte and EdeSur, through the CDEEE (50%) and the "Fondo Patrimonial de las Empresas" (FONPER). It also maintains a 50% ownership of the third one, EdeEste, (the additional 50% is owned by the Trust Company of the West (TCW) which is operated by AES Corporation, its original buyer. The three companies serve a similar share of the market.
Renewable energy resources.
As it has been described, most electricity generation in the Dominican Republic comes from thermal sources. Only 14% of the installed capacity is hydroelectric, with this percentage falling to below 9% when all the thermal self-generation is accounted for. The exploitation of other renewable resources (i.e. solar, wind) is very limited. However, this situation is expected to change following the enactment of in May 2007 of the Law of Incentives to Renewable Energy and Special Regimes (Law No. 57-07). Among other incentives, this law establishes financing at favorable interest rates for 75% of the cost
of equipment for households that install renewable technologies for self-generation and for communities that develop small-scale projects (below 500 kW).
Hydroelectricity.
As it has been mentioned, Egehid's expansion plan contemplates the addition of 762MW of hydroelectricity capacity in the period 2006-2012. According to CDEEE, the first of the new series of dams and hydropower plants - Pinalito - is a "model of environmental management", with only 12 families resettled and extensive reforestation.
Wind.
A 2001 study estimated that the Dominican Republic had a wind generation potential of 68,300GWh per year, equivalent to more than six times its current power production.
Solar.
In March 2016, the 33.4 MW Monte Plata solar plant came online. The farm consists of 132,000 photovoltaic panels. It was built by Soventix Caribbean (www.soventix.energy), and there will be a proposed second phase consisting of 270,000 photovoltaic panels that would double the size of the plant to 69 MW.
In August 2018, the 57.98 MW solar park Montecristi Solar started its energy injection to the grid, and became the largest solar farm in the Caribbean with 214,000 photovoltaic panels. A second phase is planned to double the capacity to 116 MW and becoming the largest photovoltaic power plant in the Caribbean and Central America.
History of the electricity sector.
The situation prior to the reforms.
Prior to the 1990s reform, the Dominican power sector was in the hands of the state-owned, vertically-integrated "Corporación Dominicana de Electricidad" (CDE). The operation of the company was characterized by large energy losses, poor bill collection and deficient operation and maintenance. During the 1990s, the rapid growth in the power sector mirrored the high economic growth experienced by the country. Total electricity demand increased at an annual rate of 7.5% in the years 1992-2001, while annual GDP growth was 5.9%. Generation capacity was not enough to meet peak demand, which translated into continuous supply constrains and widespread blackouts lasting up to 20 hours. In the mid-1990s, in order to address generation capacity shortages, several Independent Power Producers (IPPs) where encouraged by the government to sign Power Purchase Agreements (PPAs) with the CDE. The result of these deals, often nontransparent and negotiated, was high electricity prices.
Sector reforms: 1997-2002.
Sector unbundling and privatization.
The government, aiming to solve the enduring problems of the lack of available installed capacity and constant blackouts, enacted the Public Sector Enterprises Reform Law, which provided the framework for the privatization and restructuring of the power sector. In 1998-1999, under the first government of Leonel Fernández, the sector was unbundled and the vertically state-owned monopoly, "Corporación Dominicana de Electricidad" (CDE), was broken into a number of generation companies. EGE (Empresa Generadora de Electricidad) Haina and EGE Itabo, which ran the thermal plants, were privatized, and three distribution companies - EdeNorte (Empresa Distribudora de Electricidad), EdeSur and EdeEste - were created and also privatized.
An attempt had been made in 1997 to improve the functioning of the sector by strengthening sector regulation with the appointment of a new regulator, which was part of the Ministry of Commerce and Industry and thus had only limited autonomy.
Electricity Law of 2001.
A comprehensive regulatory framework was not enacted until July 2001, with the Electricity Law (Law 125-01)passed under the government of Hipólito Mejía. Under this law, the government's operational presence in the sector was to be through three entities:
A new holding company, "Corporación Dominicana de Empresas Eléctricas" (CDEE) was established to own ETED and EGEHID and to eventually substitute the CDE. Initially the government had intended to transfer its assets to manage the companies as an investment under a Trust Fund separate from the entities governing the sector, rather than using its ownership as a potential instrument for sector policy. However, this change was not implemented.
The 2001 Law and its supporting regulations from 2002 included the creation of an autonomous regulatory agency, the Electricity Superintendence (SIE). It also created the National Energy Commission (CNE) and a wholesale market under responsibility of a Coordinating Agency.
2000s developments.
The crisis and renationalization of distribution companies.
The reform resulted in new generation facilities, which were built and financed by the private sector, and investment in distribution by the privatized companies. Thanks to the new investments, between the end of 2000 and mid-2003, effective capacity experienced a 43% increase, with the distribution network also showing improvement. This led to temporary reduction in blackouts and distribution losses and increasing operating efficiency, the combination of which translated in improvements in the quality of service. Unserved energy decreased to 11% of the potential demand in 2002, down from 40% in 1991. In the same period, capacity deficits to meet unsuppressed demand were estimated to have fallen from 30% to 16%. However, rising oil prices, the introduction of generalized subsidies and political interference negatively affected the sector's financial health. In 2003, these unfavorable conditions and strong political pressure led the government to repurchase Union Fenosa's shares in the privatized distribution companies EdeNorte and EdeSur. These companies have experienced a deteriorating operating efficiency since their renationalization.,
The electricity sector has been in a sustained crisis since 2002, characterized by very high losses (both technical and commercial) and frequent blackouts of long duration. This situation has led to very high economic and social costs: high fiscal costs to the government; high production costs and uncertainty to industrial consumers as a result of service interruptions; high costs to industrial and residential consumers for public and private power generation, and increased social instability, including rising crime rates, caused by frequent blackouts and disruption in basic public services (e.g. hospitals, clinics and schools). In addition, domestic and international investment has been deterred, especially in sectors that depend on a reliable power supply for their activities, although many facilities (such as tourist resorts) have their own sources of power supply.
Blackout Reduction Program.
The Blackout Reduction Program (PRA) was established by the government in 2001. Initially designed to last two years, it has been subsequently extended in the absence of an alternative way to deal with the issues it addresses. This program has the objective of targeting subsidies to the poor on a geographical basis and implementing rolling blackouts in a more organized fashion. The poorest neighborhoods in the cities were to have a provision of about 20 hours of electricity per day at a price highly subsidized by the government and the utility. The PRA was initially considered a success. However, the country's macroeconomic crisis, the perverse incentives built into the PRA, and the deficiently targeted subsidy scheme have jeopardized the medium-term sustainability of the program. The absence of demand management, the lack of metering systems, sustained losses, a culture of non-payment and the absence of incentives for the distribution companies to fix the technical problems make it urgent to design a new subsidy and rationing system that is part of a more comprehensive approach to solve the problems of the power sector.
The program was closed in 2010.
Measures against fraud: modification of the Electricity Law.
In 2002, the government created the National Program to Support the Eradication of Electricity Fraud (PAEF) (Decree No. 748-02), whose main objective is to support the distribution companies in their efforts to eliminate fraud. However, results of the PAEF to date have been modest. The most serious step to combat fraud was taken in 2007 with the modification of the Electricity Law. Law 186-07, which modifies Law 125-01, criminalizes electricity fraud (e.g.illegal connections, non-payment, etc.), prescribing fines and/or jail sentences to those who breach its mandate.
Comprehensive Plan for the Electricity Sector.
In 2006, by request of President Leonel Fernández, the CDEEE, the CNE and the SIE designed a Comprehensive Plan for the Electricity Sector for the period 2006-2012. This Plan aims at achieving self-sustainability of the Electricity Sector in the Dominican Republic. The main objectives of the plan are: achieve financial sustainability of the sector, reduce electricity prices for final consumers and promote an efficient use of energy. For the medium term, it recommends the renegotiation of contracts with generators, the construction of coal plants, the development of transmission plans, the addition of new hydroelectric capacity, the promotion of renewable energy sources, a review of cross-subsidies and the strengthening of the Electricity Superintendence (SIE).
Tariffs and subsidies.
Tariffs.
Electricity tariffs in the Dominican Republic are among the highest in the Latin American and Caribbean region. This is due to several factors: reliance on imported oil, weak institutional environment, difficulties to pursue large non-payers, high prices originally negotiated in power purchase agreements with the generators, high commercial risks faced by generators such as non-payment or delayed payment by the distribution companies and/or the government, low cash recovery index (CRI), and high operating costs in the distribution companies.
The country's policy of cross-subsidizing residential tariffs by disproportionate increases in commercial and industrial tariffs translates into higher rates for industrial and commercial consumers compared to residential consumers. In 2007, the average residential tariff was US$0.160 per kWh (LAC weighted average was US$0.115 in 2005), while the average industrial tariff was 0.230 (LAC weighted average was US$0.107 per kWh in 2005) and the average commercial tariff was as high as US$0.290 per kWh.
Subsidies.
Electricity subsidies are estimated to exceed US$ 1 billion in 2008, corresponding to a stunning 3% of GDP. The need for subsidies has increased due to higher oil prices while electricity tariffs have been kept constant. Subsidies are channeled through two major mechanisms: The Blackout Reduction Program and the Tariff Stabilization Fund.
The Blackout Reduction Program (PRA) is targeted to poor areas. Due to low collections rates, these consumers have been receiving virtually free electricity since the program's inception.
Residential consumers outside the PRA areas and thus likely not to be among the poorest, are charged below-cost electricity prices for consumption below 700 kWh/month, a very high threshold by international standards. About 80% of residential users outside the PRA areas fall into this category. This subsidy is drawn from the Tariff Stabilization Fund (FET), which was designed to reduce the impact of high oil prices. The financial burden in this case is transferred to the distribution companies, which have found themselves unable to cover their costs in a scenario of rising oil prices, low efficiency and a limited customer base that could be charged to finance the cross-subsidy. This situation has forced the government to provide much higher than expected subsidies to the sector, which in turn translates into reduced ability to finance investments in other key sectors such as health and education. The government has started to reduce cross-subsidies gradually, with the final objective of limiting them to households with monthly consumption below 200 kWh, which is closer to thresholds for subsidized residential electricity encountered in other countries.
Investment and financing.
The power sector attracted an important amount of foreign direct investment (FDI) following the privatization of the main generation facilities and the distribution companies in 1999 and the subsequent expansion in generation capacity. In the period 1996-2000, the sector accounted for over 28% of FDI, reaching 37% in 2001.
Generation.
As previously described, the precarious situation of the electricity sector in the Dominican Republic is not caused primarily by limited generation capacity. Although a reduction of losses may provide a more economic way of resolving the crisis, there are plans for significant new investments in new generation capacity, especially in hydropower.
The private generation companies raise capital in the market. For example, in April 2007 EGE Haina raised US$ 175m in capital through 10-year bonds that were more than 10 times oversubscribed.
As for hydropower, Egehid's has identified in its 2006-2012 expansion plan new projects for an estimated value of US$1,442 million. The construction of first three dams (Pinalito, Palomino and Las Placetas) and associated hydropower plants will be partially financed through tied export financing from the Brazilian Development Bank BNDES approved in November 2006. The loans for the Palomino and Las Placetas projects total US$ 152.5 million, while the total costs of the facilities is estimated at US$ 512.5 million. A loan for the Pinalito project had already been approved earlier. Additional financing is provided by commercial Banks such as ABN and BNP Paribas.
Transmission.
There are bottlenecks in the transmission system that need to be addressed. The owner of the system, the CDE, lacks financial resources to improve the grid and the existing legislation has not allowed other mechanisms to mobilize private sector resources for transmission.
The Electricity Transmission Company (ETED) has produced an expansion plan for the transmission network to be executed in the period 2006-2012. Financing of US$284 million has been secured for the 2006-2008 period, with an additional US$80.75 million in process. Furthermore, US$222.5 million will be needed to finance the projects contemplated in the expansion plan for the period 2008-2012.
Rural electrification.
The Dominican Government claims to have plans to invest, through the Rural and Suburban Electrification Unit (UERS), about RD$1,500 million (US$890 million) in large number of scattered projects.
Summary of private participation in the electricity sector.
In 1998–1999, the Public Sector Enterprises Reform Law provided the framework for the privatization and restructuring of the power sector, previously controlled by the vertically state-owned monopoly, Corporación Dominicana de Electricidad (CDE). A comprehensive regulatory framework was enacted in 2001, which determined the government's operational presence in the sector through three entities: CDE(generation), EGEHID (hydroelectric generation), and ETED (transmission). As for distribution, two of the three existing companies, EdeNorte and EdeSur, are owned by the government, who also holds 50% ownership of the third one, EdeEste.
Electricity and the environment.
Responsibility for the environment.
The "Secretaría de Estado de Medio Ambiente y Recursos Naturales" is the institution in charge of the conservation, protection and regulation of the sustainable use of the natural resources and the environment in the Dominican Republic.
Greenhouse gas emissions.
OLADE (Latin American Energy Organization) estimated that CO2 emissions from electricity production in 2003 were 7.63 million tons of CO2, which corresponds to 46% of total emissions from the energy sector. This high contribution to emissions from electricity production in comparison with other countries in the region is due to the high share of thermal generation.
CDM projects in electricity.
Currently (December 2007), there is just one registered CDM project in the electricity sector in the Dominican Republic, the El Guanillo wind farm, with estimated emission reductions of 123,916 tCO2e per year.
External assistance.
World Bank.
The World Bank is currently financing a Power Sector Technical Assistance Project. The US$10 million project will receive US$7.3 million funding from the Bank in the period 2004-2009. This project aims to: (i) strengthen the Government's regulatory and consumer protection performance, (ii) improve policy formulation and implementation, (iii) design the transmission grid and the wholesale power market, (iv) increase the quantity and quality of electricity for the poor, and (v) protect the environment.
The World Bank is also financing the Second Generation Power Sector Reforms of the Dominican Republic Power Sector Program through US$150 million of financing in the period 2005-2008. The power sector program, which consists of two policy-based loans and an investment loan for transmission and service expansion, seeks to support the Government's strategy for the recovery of the power sector, and in particular to: improve the quality of service, especially by reducing the widespread blackouts of recent years; establish conditions that would permit the financial sustainability of all efficiently-operated companies in the sector; and, increase the percentage of the population with access to electricity.
Inter-American Development Bank.
The Inter-American Development Bank (IDB) supported the electricity sector reforms of the late 1990s, the creation of a National Energy Council and demand-side management to reduce electricity consumption through various technical assistance projects approved between 1996 and 2001. The IDB's private-sector arm also provided loans to the private electricity distribution companies Ede Sur and Ede Norte in 1999.


Sonnedix

Sonnedix is a multi-national solar power producer with more than 300 solar power plants/farms across 8 countries. Sonnedix develops, builds, owns and operates solar power plants for the long term. Sonnedix is majority owned by institutional investors advised by J P Morgan Asset Management.
Areas of Operation.
Other than the Netherlands and United States, all other countries are locations of Sonnedix's solar PV plants and offices.


Wright-Hennepin Cooperative Electric Association

Wright-Hennepin Cooperative Electric Association (WH) is a non-profit, member-owned energy and service cooperative located in Rockford, Minnesota. The company serves more than 45,000 electric accounts in western Hennepin County, Minnesota and most of Wright County, Minnesota.
History and background.
In 1937 farmers in rural Wright and western-Hennepin counties tried to get electricity to their homes. The investor-owned utilities would not work with them because they couldn’t profitably serve the rural area, where homes and businesses were further apart and more equipment investments would need to be made.
After that rejection, the farmers joined together and created an electric cooperative. Each person who joined WH became a "member" and took one share of ownership of the cooperative. Nine members are elected to serve on the Board of Directors. They determine the cooperative's strategic direction, provide financial oversight, set electric rates, and provide other governance for the cooperative.


Davao Light and Power Company

Davao Light and Power Company, Inc. is a Davao-based Filipino electricity company and the third largest privately owned electric utility in the Philippines and is owned by Aboitiz Power Corporation (AboitizPower). In 2007, the company had 247,341 customers and 290,000 customers in 2012.
The company was originally owned by P. H. Frank but was sold to Jon Ramon Aboitiz in 1941.


Intermountain Power Plant

Intermountain Power Plant is a large coal-fired power plant at Delta, Utah, USA. It has an installed capacity of 1,900 MW, is owned by the Intermountain Power Agency, and is operated by the Los Angeles Department of Water and Power.
It is scheduled in 2025 for replacement with an 840 MW natural gas plant, designed to also burn "green hydrogen."
The plant includes a HVDC converter.
Description.
The power plant consists of two units each with a generation capacity of 950 MW. Generating units are equipped with
General Electric tandem compound steam turbines and Babcock & Wilcox subcritical boilers.
The boiler houses of Intermountain Power Plant are and the flue gas stack is tall. The HVDC Intermountain transmission line runs between Intermountain Power Plant and Adelanto Converter Station in Adelanto, California.
History.
Construction on the plant began in September 1981. Commercial operation of unit 1 started in June 1986, and unit 2 in May 1987. The project cost US$4.5 billion. The plant was originally designed for four units; however, only two units were built. In 2004, units 1 and 2 were uprated. These works were conducted by GE and Alstom. The Intermountain Power Agency planned to build the third unit of 900 MW capacity. This unit was expected to go online in 2012; however, the project was cancelled after its major purchaser, the city of Los Angeles, decided to become coal-free by 2020.
On December 28, 2011, one of the generators failed causing the shut-down of one unit for several months.
Replacement with natural gas and green hydrogen plant.
By 2025 the plant is scheduled to be replaced with an 840 MW natural gas plant, at a cost of $865 million, which utility managers state is necessary both to avoid blackouts which could result from the non-dispatchable nature of solar and wind generation, and to ensure operation of the Path 27 HVDC transmission line which brings solar and wind power from Utah to Los Angeles.
The new natural gas fired turbines would be the first of their kind capable of burning a mix of 70% natural gas and 30% "green" hydrogen (hydrogen released by the electrolysis of water, using renewably generated electricity) when the plant opens in 2025. The plan is to steadily increase the hydrogen percentage to 100% by 2045, which will require upgrading or replacement of the turbines to be able to handle greater percentages of hydrogen.
One expert noted that using hydrogen to replace natural gas in power-plant turbines is currently theoretical and has never been done in practice, and a LADWP IPP official stated that the "economics remain to be seen" and "could be quite expensive."


China Power International Development

China Power International Development Limited (CPID), also known as just China Power, is a Chinese electric power company incorporated in Hong Kong in 2004. The former ultimate parent company China Power Investment Corporation (CPI Group), a Chinese state-owned enterprise also has the initials "CPI" but in the case of the parent company the "I" stands for "Investment" () not "International" (). State Power Investment Corporation (SPIC) became the new parent company of CPID after CPI Group was merged with another state-owned enterprise.
CPID is one of several Hong Kong listed subsidiaries of five national power generating groups in the Mainland China. Huadian Group, Huaneng Group, and Datang Group also have Hong Kong listed subsidiaries, in each case with the word "International" added to the title. CPID also a red chip company, a term for foreign incorporated listed company with Chinese government background in the Stock Exchange of Hong Kong (as Hong Kong had a separate jurisdiction from the Mainland). The fifth of the Big Five China power groups, Guodian Group has a listed subsidiary in Shanghai.
, the market capitalization of China Power International Development was HK$21.379 billion.
History.
China Power International Development Limited was incorporated in Hong Kong in 2004. Its predecessor and direct parent company, another Hong Kong incorporated company, China Power International Holding Limited (), was founded in 1994. It is ultimately controlled by the State Power Investment Corporation (previously China Power Investment Corporation), one of the five large national power generating groups that were administered by the State-owned Assets Supervision and Administration Commission of the State Council. CPID is engaged in developing, constructing, owning, managing and operating large power plants in China.
CPID was listed in the Stock Exchange of Hong Kong on 15 October 2004. It was the only red chip company among the big 5 electric power generation companies of the Mainland China, the other three were H shares companies as well as dual listed in the Mainland China. The last listed subsidiary, was listed only in the Mainland China stock exchange.
In 2009 CPID acquired 63% equity interests in Wu Ling Power making hydroelectric power 18.73% of its total installed capacity, the highest of any of the Chinese IPPs. This protects the company from the costs of coal power in China, and makes its overall profile cleaner.


Wilcox P. Overbeck

Wilcox Pratt Overbeck (1912–1980) was an electrical and nuclear engineer who built instrumentation for the first nuclear reactor, the Chicago Pile-1, and went on to work at other United States Department of Energy national laboratories. He previously worked with Vannevar Bush at MIT on the Rapid Arithmetic Machine.
A one-hot ring counter is sometimes referred to as an "Overbeck ring"; he patented such a device made with a multi-anode vacuum tube in 1943. At the Met Lab in Chicago, he used such counters to scale the rate of detected ionization events, to estimate the rate of the nuclear reaction in the Chicago Pile-1, Enrico Fermi's famous first critical nuclear reactor.


Terranora interconnector

Directlink (Terranora) Interconnector is a buried 59 kilometre (37 mi) High Voltage Direct Current (HVDC) electricity transmission cable route from near Lavertys Gap (), Southwest of Mullumbimby, New South Wales and Bungalora () & connected via a 3.5km (2.2mi) AC Overhead Transmission Line to the NorthEast to the Terranora Electrical Substation () @ Terranora, New South Wales New South Wales in Eastern Australia. <br>
It is one of the two interconnections used to trade electricity between New South Wales and Queensland (the other is the 330KV Dual Circuit Queensland – New South Wales Interconnector (QNI)).
History.
The interconnector was developed by a joint venture of NorthPower (later Country Energy), TransÉnergie–a subsidiary of Hydro-Québec, and "Fonds de solidarité FTQ". The motivation to build the interconnector was the power shortage in Southern Queensland and surplus capacities in New South Wales. It was developed as an Independent Transmission Project. It was commissioned in December 1999 and it started operations in April 2000. It was the first time that transmission systems of New South Wales and Queensland were linked. The construction cost US$70 million.
In December 2006, it was announced that Directlink would be purchased by Australian Pipeline Trust (APT, a part of APA Group) for US$133 million. The transaction was completed in February 2007.
Originally, the interconnector operated as a non-regulated market network service. However, on 6 May 2004 an application to convert it to a regulated network service was submitted. The application was approved by the Australian Energy Regulator on 10 March 2006.
In December 2008, ownership of Directlink (as well as Murraylink) was transferred to the Energy Infrastructure Investments Group, while the APA Group continued as the operator. The ownership of EII is allocated as APA with 19.9%, Japan-based Marubeni Corporation with 49.9%, and Osaka Gas with 30.2%.
Technical description.
Directlink (Terranora) interconnector is a HVDC land cable route. The system has three 65MVA Voltage Source Converters at each station connected by three pairs of transmission cables. Each pair of cables operates at +/-80 kV and transmits 60 MW. In New South Wales it is connected to a 132 kV alternating current transmission grid and in Queensland to 110 kV alternating current transmission grid.
The total rating of the interconnector is 180 MW. The maximum net transfer minus losses is around 170 MW. If one pair of cables malfunctions, the available capacity is around 115 MW. If two pairs of cables are out of service, the capacity is around 57 MW. However, in some cases for a limited time period the interconnector has operated in an overloading mode for up to 250 MW. The limiting factor for flow in the New South Wales direction is the thermal ratings of the Terranora–Mudgeeraba 110 kV lines and Mullumbimby–Dunoon 132 kV lines, and for flow in the Queensland direction is the thermal ratings of the Lismore–Dunoon 132 kV lines.
HVDC VSC was chosen for this project for reasons of low environmental impact of the transmission route and the ability of the IGBT converter stations at each end to accurately control both real and reactive power. Individual water-cooled IGBT modules are rated at 2.5 kV and 500 A, with multiple units connected in series to achieve the required voltage rating.


David A. Schlissel

David A. Schlissel has been a Senior Consultant with Synapse Energy Economics since 2000. For 30 years he has worked on complex engineering and economic issues mainly in the field of energy management. This work has ranged from conducting technical investigations, through to presenting expert testimony. Schlissel has undergraduate and advanced engineering degrees from the Massachusetts Institute of Technology and Stanford University, and a law degree from Stanford Law School.


Spark Infrastructure

Spark Infrastructure Group is an Australian investment fund which owns and manages a portfolio of electricity infrastructure assets. The company debuted on the Australian Securities Exchange on 16 December 2005 with the stock symbol SKICA representing an instalment receipt of with a final instalment of due in March 2007 when the instalment receipts were transferred for SKI shares.
Spark's principal investments are 49% stakes in both SA Power Networks and Victoria Power Networks; as well as a 15% stake in the NSW Power Networks consortium given the concession for TransGrid, the high-voltage transmission system for New South Wales.


Hartsville Nuclear Plant

The Hartsville Nuclear Plant is a canceled nuclear power plant project located near Hartsville, Tennessee. To be built and operated by the Tennessee Valley Authority, it was to have four General Electric boiling water reactors.
Land along the Cumberland River was acquired by TVA in the late 1960s for construction of the plant which was to accommodate the electricity demand for the 1980s. Construction began in 1975. The Plant B reactors were canceled on March 22, 1983 and the Plant A reactors were canceled on August 29, 1984.
There are currently plans to turn of the property into an industrial park similar to what became of the Satsop Nuclear Plant in Washington. The Trousdale Turner Correctional Center, a private prison operated by CoreCivic, began operations on the site in 2016.


Lanka Electricity Company

The Lanka Electricity Company (Private) Limited (Sinhala: ලංකා විදුලි (පුද්ගලික) සමාගම "Lanka vidulu pudgalika samagama") (also abbreviated as LECO), is the largest Electricity distribution company in Sri Lanka. With a market share of nearly (Confirmation Pending ), it controls all major functions of distribution and Energy Smart Meter manufacturing in Sri Lanka. It is one of the only two on-grid electricity companies in the country; the other being Ceylon Electricity Board (CEB). The company earned approximately LKR (Confirmation Pending)billion in 2018, with a total of nearly 521,982 consumer accounts.
It is a government owned and controlled utility of Sri Lanka that takes care of the general energy facilities of the island. The Ministry of Power, Energy & Business Development is the responsible ministry above the LECO. Lanka Electricity Company (Private) Limited (LECO), established by an Companies Act No.17 of 1982 and the Companies Act No.7 of 2007, is under legal obligation to develop and maintain an efficient, coordinated and economical system of Electricity supply in accordance with any Licenses issue


Qulliq Energy

Qulliq Energy Corporation (QEC; ; Inuinnaqtun: "Qulliq Alruyaktuqtunik Ikumadjutiit"; ) is a Canadian territorial corporation which is the sole electricity utility and distributor in Nunavut. It is wholly owned by the Government of Nunavut. Its name is derived from the qulliq (or kudlik), a traditional oil lamp used by Inuit and other Arctic indigenous peoples. The company uses Nunavut Power as its trading name for power generation. It is headquartered in Baker Lake, Nunavut.
History.
Qulliq Energy was established by the Nunavut Power Utilities Act (now the Qulliq Energy Corporation Act) in 2001, two years after the 1999 creation of Canada's Nunavut Territory, to take over the assets within Nunavut of the Northwest Territories Power Corporation (which was itself a successor to the Northern Canada Power Commission). Its original name was Nunavut Power Corporation and it was renamed Qulliq Energy Corporation in 2002 and the mandate of the corporation expanded to include energy conservation and alternative generation development. The power generation trading name Nunavut Power was adopted in 2003.
Qulliq Energy established Nunavut Energy Centre in 2006 as a division focusing on energy conservation through public outreach. The centre was closed down on March 31, 2009, and its functions were transferred to the territorial government departments.
Operations.
Low population, severe weather and remoteness of transportation and construction technology make long distance high voltage grids unviable. Every community in Nunavut relies on independent diesel generators, fueled by the annual sealift re-supply during the summer shipping season. This dependence on diesel presents its own set of environmental and economic impacts, leaving the territory vulnerable to world energy price fluctuations. The first new power generation facility since establishment of the company will be expansion of the Iqaluit power plant.
The geography of Nunavut presents unique challenges to hydro-electric facilities, but the company is actively engaged in site reviews for hydro-electric developments in the 12-20 MW range around Iqaluit, the territorial capital. The hydro-electric plants are planned in Jaynes Inlet and Armshow South on the south shore of Frobisher Bay.
During the 1970s, there had been suggestions of NCPC employing "slowpoke" nuclear generators to produce power in the many isolated communities.
Since the establishment, periodic discussions continue regarding the possibility of combining Nunavut's fuel delivery functions under Qulliq Energy.
Iqaluit Hydroelectric Project.
In 2005, Quilliq Energy initiated a study of potential sites near Iqaluit for the development of a hydroelectric power station. Two sites, Jaynes Inlet and Armshow South, were selected as the most cost effective and viable solutions after comprehensive research. The Jaynes Inlet site () would be the site of a 12.5 MW hydroelectric dam that is expected to meet Iqaluit's current energy demand. The Armshow South site () would be the site of a 7.3 MW hydroelectric dam that would be developed when additional capacity is needed.
However, Quilliq Energy does not have an adequate revenue surplus or borrowing ability in order to fund the project on its own, especially as 13 of the 25 diesel-fired power stations across the territory are in need of replacement. As a result, the hydroelectric project was shelved in 2014.
Controversies.
In 2010 and 2011, five lawsuits were filed against Qulliq Energy by former employees for wrongful/constructive dismissal, while some other former workers accused the company for the violation of Inuit rights in the workplace.


Korea Electric Power Corporation

Korea Electric Power Corporation (, ), better known as KEPCO (Hangul: 켑코) or Hanjeon (Hangul: 한전), is the largest electric utility in South Korea,
responsible for the generation, transmission and distribution of electricity and the development of electric power projects including those in nuclear power, wind power and coal. KEPCO, through its subsidiaries, is responsible for 93% of Korea's electricity generation as of 2011. The South Korean government (directly and indirectly) owns a 51.11% share of KEPCO. Together with its affiliates and subsidiaries, KEPCO has an installed capacity of 65,383 MW. On the 2011 Fortune Global 500 ranking of the world's largest companies, KEPCO was ranked 271. KEPCO is a member of the World Energy Council, the World Nuclear Association and the World Association of Nuclear Operators. As of August 2011, KEPCO possesses an A+ credit rating with Fitch Ratings, while Moody's has assigned KEPCO an A1 stable rating.
Originally located in Samseong-dong, Seoul, KEPCO headquarters was relocated to the city of Naju in South Jeolla Province in August 2014 as part of a government decentralization program. The move, which has been in the works for years has been controversial. Jong-Kap Kim is the president and CEO of KEPCO.
History.
KEPCO traces its origins to "Hanseong Jeongi Hoesa" (Seoul Electric Company), founded in 1898 during the Joseon Dynasty. The announcement of the Chōsen Electricity Control Decree by the Colonial Korean government in March 1943 saw the integration of several electric companies into the Korea Electric Power Company. The Korea Electric Company (KECO), established through the integration of the Korea Electric Power Company and two distribution companies, Gyeongsung Electric Company and South Korea Electric Company, opened on 1 July 1961. In 1982, KECO became a wholly government owned entity and was renamed the Korea Electric Power Corporation (KEPCO).
KEPCO was listed on the Korea Composite Stock Price Index (KOSPI) on 10 August 1989 and later in 1994 on the New York Stock Exchange. In 1996, KEPCO was named the prime contractor for the multinational Korean Peninsula Energy Development Organization (KEDO) project to construct a light water reactor nuclear power plant in North Korea, a project which was eventually abandoned in 2006. Following a push by the Korean government to restructure Korea's power industry which began in the mid-1990s, the "Act on the Promotion of Restructuring the Electric Power Industry" was proclaimed on 23 December 2000, after which the electricity generation business was split up into Korea Hydro & Nuclear Power, a subsidiary responsible for nuclear & hydro power generation, and five thermal power generation companies: Korea South-East Power, Korea Midland Power, Korea Western Power, Korea Southern Power, and Korea East-West Power.
In October 2012, Korea Deposit Insurance Corporation sold its 3.6% of its stake in KEPCO for a fee of around $550 million.
Subsidiaries.
KEPCO comprises six power generation companies and four subsidiaries in related business areas. It also owns a stake in four affiliated companies.
Operations.
Domestic activities.
In Korea, KEPCO primarily provides electricity to include industrial, commercial, residential, educational and agricultural customers. As of December 31, 2011, KEPCO had a total installed generating capacity of 67,001MW produced by 503 generation units including nuclear, oil, coal, liquified natural gas, hydro, wind and solar sources. The length of KEPCO's transmission lines stood at 31,249 circuit kilometers as of end-2011.
Nuclear business.
KEPCO's involvement in the nuclear energy sector ranges from design and engineering of the nuclear power plant to nuclear fuel, commissioning and operation, maintenance and decommissioning. Construction of KEPCO nuclear power plants is undertaken by major Korean construction companies, while the manufacture of key elements of a nuclear power plant is done by companies including Doosan Heavy Industries & Construction and Westinghouse Electric Company. In 2009, KEPCO won a bid to construct four units of the APR-1400 reactor in the United Arab Emirates at Barakah.
In October 2013 a vice-president of KEPCO, amongst about 100 people, was indicted for falsifying safety documents.
In 2017 KEPCO showed interest in taking a stake in the Moorside Nuclear Power Station in the UK, though did not proceed with the project.
In October 2020 KEPCO signed a memorandum of understanding with Daewoo Shipbuilding & Marine Engineering to develop a floating nuclear power plant based on the BANDI-60 60 MWe small modular reactor, which has been under development since 2016.
Overseas activities.
KEPCO's overseas forays started in 1993 when the company was awarded a technical consulting contract for maintenance on the Guangdong nuclear power plant in China. At present, KEPCO is involved in projects in 13 countries around the world. In 1996, KEPCO entered the Philippines power market when it was awarded the contract for the refurbishment and operation of the Malaya thermal power plant. In 1996, KEPCO won the bid to construct the Ilijan gas-fired combined cycle power plant, a 1,200MW build-operate-transfer project. Today, KEPCO operates four power plants in the Philippines, including the Naga Power Plant Complex and the Cebu Circulating Fluidized Bed Combustion Power Plant, while the company's operations account for 12% of the country's installed generation capacity. In April 2012 KEPCO contracted ICPO to raise $400m to buy into Boutique Coal in Australia to benefit from cheap coal briquettes which improved burn efficiency by up to 30% reduced and by >80% and reduced . KEPCO scientists tried to get IP details and reverse engineer the product for their own use. Boutique Coal cancelled all association with KEPCO due to an attempt to circumvent and declared KEPCO less than reputable.
In the area of transmission and distribution consultation, KEPCO has undertaken projects in Myanmar, Cambodia, Vietnam, Indonesia, Libya, Ukraine, Paraguay and Egypt. KEPCO entered the wind power industry in China with its involvement in the Gansu wind project, on which the first stage of construction began in 2007. KEPCO also holds an equity share in wind projects in Inner Mongolia and Riaoning, as well as in China's Shanxi Province. In 2010, a KEPCO-led consortium including Samsung C&T and Korean firm Techint was awarded a contract to build and operate the Norte II combined cycle gas power plant in the Mexican state of Chihuahua. In 2005, KEPCO began supplying electricity to the Kaesong Industrial Region in North Korea.
Resources development.
In order to raise its fuel self-sufficiency rate to 60% by 2020, in 2010, KEPCO acquired the Bylong Coal Mine in Australia from Anglo American PLC. Also in 2010, KEPCO bought a 20% stake in Bayan Resources in Indonesia, thus allowing the company to raise its coal self-sufficiency rate by 7 million tons annually from 2015. In 2009, KEPCO bought a 1.5% stake in Indonesia's Adaro Energy, thus securing 3 million tons of coal annually. Regarding uranium procurement, in 2009, KEPCO acquired a 17% share of Denison Mines Corp. in Canada, as well as a 10% stake in Areva SA's Imouraren uranium mine in Niger. In 2010, KEPCO signed an agreement with Areva to jointly develop uranium mines.
Smart grid.
In early 2010, KEPCO announced it would invest over US$7 billion in its smart grid business by 2030 to make electricity distribution more efficient and decrease Korea's greenhouse gas emissions. KEPCO is one of the 168 Korean and foreign companies taking part in the Jeju Smart Grid Demonstration Project, begun following the announcement of Korea's National Smart Grid Roadmap in 2009. In June 2011, it was announced that KEPCO would collaborate with IBM to build a Total Operations Center at the Jeju Smart Grid Test-Bed Demonstration Complex.