HVDC Vancouver Island

HVDC Vancouver Island is a high-voltage direct current interconnection between the Vancouver Island Terminal (VIT) in North Cowichan, British Columbia on Vancouver Island at and the Arnott Substation (ARN) in Delta, British Columbia at on the Canadian mainland. It went into operation in 1968 and was extended in 1977. HVDC Vancouver Island consists of three overhead line sections with a total length of 42 kilometres and two submarine cable sections with a length of 33 kilometres.
Route.
After its departure from Arnott Substation the overhead power line on the mainland splits at into two branches, one running to a terminal at and the other running to a terminal at , where the first submarine cable section begins.
At , the first submarine cable section ends and a short overhead line section running south-west across Galiano Island starts. The overhead line leaves Galiano Island south of Montague Harbour in an 880-metre-long span, which starts at and ends on Parker Island at .
A little to the west, on Parker Island at the overhead line ends and the second submarine cable section begins.
At the cable reaches Salt Spring Island and the third overhead line section starts. It crosses Salt Spring Island west-south-westerly. North of Maxwell Point at and Arbutus Point at the overhead line crosses Sansum Narrows, the strait between Salt Spring Island and Vancouver Island, by a 1900-metre-long span. After this span the overhead line runs westward to Vancouver Island Terminal near the town of Duncan.
History.
In 1968 the first pole of the HVDC Vancouver Island link went into service. Its static inverters use mercury vapour rectifiers. Each of these rectifiers is 3.35 metres (11 ft) long, 1.22 metres (4 ft) wide and 6.10 metres (20 ft) high and has a weight of 4.5 metric tons. The valves are situated in a hall 26.21 metres (86 ft) long, 11.89 metres (39 ft) wide and 11.28 metres (37 ft) high. The maximum transmission capacity of this pole is 312 megawatts and the transmission voltage is 260 kV. The stations Vancouver Island Terminal and Arnott Substation were designed and delivered by Swedish company ASEA (later ABB). The Swedish team of some 10 people were headed for the first phase by Ivan Hedlund and for the second phase by Gunnar Ahgren.
In 1977 the HVDC Vancouver Island link was supplemented by installing a second pole. This pole uses thyristor valves for its static inverters and operates at a voltage of 280 kV with a rating of 370 megawatts. A new 230 kV. submarine cable for three-phase alternating current has been constructed between the Canadian mainland and Vancouver Island. This parallels the existing two HVDC lines and replaces one of two earlier 138 kV lines. The HVDC systems are at the end of their service life and are not considered to be reliable. As a result of this, the first pole was shut down in 2016.
Electrodes and metallic return.
HVDC Vancouver Island uses metallic return, during monopolar operation, when current is lower than 600 A. Otherwise earth return is used. On Vancouver Island the line for metallic return is a monopolar line on wooden poles, which are used in some sections also by AC lines, running parallel to the main line of HVDC Vancouver Island.
On the mainland, it uses the poles of the electrode line until a point at . After this point it runs on wooden poles together with a single-circuit three-phase AC line until .
From there it runs as underground cable to Splasdown Park, where it transits at again into an overhead line, which ends at the terminal of the main line at .
The electrode on the Canadian Mainland is a land electrode situated at Boundary Bay at . It is connected with Arnott Substation by an overhead pole line with two conductors. The electrode on Vancouver Island is a shore electrode in a bay at Sansum Narrows at . It is connected with Vancouver Island Terminal by an overhead line with two conductors, which is installed on wooden poles. It runs between Vancouver Island Terminal and a point northwest of Maple Bay at parallel to other power lines.


Tokyo Electric Power Company

, also known as or TEPCO, is a Japanese electric utility holding company servicing Japan's Kantō region, Yamanashi Prefecture, and the eastern portion of Shizuoka Prefecture. This area includes Tokyo. Its headquarters are located in Uchisaiwaicho, Chiyoda, Tokyo, and international branch offices exist in Washington, D.C., and London. It is a founding member of strategic consortiums related to energy innovation and research; such as JINED, INCJ and MAI.
In 2007, TEPCO was forced to shut the Kashiwazaki-Kariwa Nuclear Power Plant after the Niigata-Chuetsu-Oki earthquake. That year it posted its first loss in 28 years. Corporate losses continued until the plant reopened in 2009.
Following the 2011 Tōhoku earthquake and tsunami, one of its power plants was the site of one of the world's most serious ongoing nuclear disaster, the Fukushima Daiichi nuclear disaster.
TEPCO could face ¥ ($) in special losses in the current business year to March 2012, and the Japanese government plans to put TEPCO under effective state control to guarantee compensation payments to the people affected by the accident. The Fukushima disaster displaced 50,000 households in the evacuation zone because of leaks of radioactive materials into the air, soil and sea.
In July 2012, TEPCO received ¥1 trillion from the Japanese government in order to prevent collapse of the company to ensure electricity is still being supplied to Tokyo and its surrounding municipalities, and for the decommissioning of the Fukushima Daiichi Nuclear Power Plant.<ref name="Guardian 09/05/2012"></ref> TEPCO's management subsequently made a proposal to its shareholders for the company to be part-nationalized. The Nuclear Damage Compensation and Decommissioning Facilitation Corporation later became the majority stockholder to oversee damages and decommissioning of the power plant. The total cost of the disaster was estimated at $100bn in May 2012.
History.
Japan's electricity sector, nationalized in 1939 in preparation of total war (the Pacific War), were privatized in 1951 on behest of the U.S./Allied occupation forces, creating nine privately owned government-granted monopolies, one in a certain region; this included TEPCO. The business model are modeled after the United States electricity industry, which was mostly regulated and privately owned at the time.
In the 1950s, the company's primary goal was to facilitate a rapid recovery from the infrastructure devastation of World War II. After the recovery period, the company had to expand its supply capacity to catch up with the country's rapid economic growth by developing fossil fuel power plants and a more efficient transmission network.
In the 1960s and 1970s, the company faced the challenges of increased environmental pollution and oil shocks. TEPCO began addressing environmental concerns through expansion of its LNG fueled power plant network as well as greater reliance on nuclear power generation. The first nuclear unit at the Fukushima Dai-ichi (Fukushima I) nuclear power plant began operational generation on March 26, 1971.
During the 1980s and 1990s, the widespread use of air-conditioners and IT/OA appliances resulted a gap between day and night electricity demand. In order to reduce surplus generation capacity and increase capacity utilization, TEPCO developed pumped storage hydroelectric power plants and promoted thermal storage units.
Recently, TEPCO is expected to play a key role in achieving Japan's targets for reduced carbon dioxide emissions under the Kyoto Protocol. It also faces difficulties related to the trend towards deregulation in Japan's electric industry as well as low power demand growth. In light of these circumstances, TEPCO launched an extensive sales promotion campaign called 'Switch!', promoting all-electric housing in order to both achieve the more efficient use of its generation capacity as well as erode the market share of gas companies.
Major subsidiaries.
As Tokyo Electric Power Company Holdings, Inc. is a holding company, there are several major wholly owned subsidiaries.
Corporate overview.
Community compensation.
Tokyo Electric Power could face 2 trillion yen ($23.6 bln) in special losses in the current business year to March 2012 to compensate communities near its crippled Fukushima nuclear plant, according to JP Morgan.
Japan plans to put TEPCO under effective state control so it can meet its compensation payments to people affected by radiation from its Fukushima I plant. Tokyo will set aside several trillion yen in public funds that TEPCO can "dip into if it runs short for payouts to people affected".
Salary pay cuts.
The company workers agreed to a management proposal to cut their pay as a sense of responsibility for the world's worst nuclear disaster. Annual remuneration for board members will be reduced by 50 percent since April 2011, while payment for managers will be cut by 25 percent and workers by 20 percent both since July 2011 and bonuses since June 2011. The company expects to save about 54 billion yen ($659 million) a year from the pay cuts.
In July 2012 it was announced that annual salaries of managers will be reduced by at least 30%, with workers pay cut remaining at 20%. On average employees pay would be cut by 23.68%. In addition, the portion of the employee health insurance program that the company covers will be reduced from 60% to 50%, the standard in Japan.
Sale of hospital.
It was announced in July 2012 that the company would sell the hospital it owns in Shinjuku Ward in Tokyo. The hospital is used exclusively by current and former TEPCO employees and their families. Its market value is ¥8.6 billion.
Power stations and generation capacity.
Position in the industry.
TEPCO is the largest electric utility in Japan and the 4th largest electric utility in the world after German RWE, French Électricité de France and Germany's E.ON. As TEPCO stands in a leading position in this industry, they have relatively a strong effect for Japanese economics, environment, and energy industry.
Management and finance.
For the fiscal years ending in 2011, 2012 the company had a pretax loss, in 2013 the deficit was 377.6 billion yen. In the following year 2014 red figures were expected too.
Generation.
The company's power generation consists of two main networks. Fossil fuel power plants around Tokyo Bay are used for peak load supply and nuclear reactors in Fukushima and Niigata Prefecture provide base load supply. Additionally, hydroelectric plants in the mountainous areas outside the Kanto Plain, despite their relatively small capacity compared to fossil fuel and nuclear generation, remain important in providing peak load supply. The company also purchases electricity from other regional or wholesale electric power companies like Tohoku Electric Power, J-POWER, and Japan Atomic Power Company.
Transmission and distribution.
The company has built a radiated and circular grid between power plants and urban/industrial demand areas. Each transmission line is designed to transmit electricity at high-voltage (66-500kV) between power plants and substations. Normally transmission lines are strung between towers, but within the Tokyo metropolitan area high-voltage lines are located underground.
From substations, electricity is transmitted via the distribution grid at low-voltage (22-66kV). For high-voltage supply to large buildings and factories, distribution lines are directly connected to customers' electricity systems. In this case, customers must purchase and set up transformers and other equipment to run electric appliances. For low voltage supply to houses and small shops, distribution lines are first connected to the company's transformers (seen on utility poles and utility boxes), converted to 100/200V, and finally connected to end users.
Under normal conditions, TEPCO's transmission and distribution infrastructure is notable as one of the most reliable electricity networks in the world. Blackout frequency and average recovery time compares favorably with other electric companies in Japan as well as within other developed countries. The company instituted its first-ever rolling blackouts following the shutdown of the Fukushima I and II plants which were close to the epicenter of the March 2011 earthquake. For example, on the morning of Tuesday, March 15, 2011, 700,000 households had no power for three hours. The company had to deal with a 10 million kW gap between demand and production on March 14, 2011.
Corporate image.
Safety incidents.
On August 29, 2002, the government of Japan revealed that TEPCO was guilty of false reporting in routine governmental inspection of its nuclear plants and systematic concealment of plant safety incidents. All seventeen of its boiling-water reactors were shut down for inspection as a result. TEPCO's chairman Hiroshi Araki, President Nobuya Minami, Vice-President Toshiaki Enomoto, as well as the advisers Shō Nasu and Gaishi Hiraiwa stepped-down by September 30, 2002. The utility "eventually admitted to two hundred occasions over more than two decades between 1977 and 2002, involving the submission of false technical data to authorities". Upon taking over leadership responsibilities, TEPCO's new president issued a public commitment that the company would take all the countermeasures necessary to prevent fraud and restore the nation's confidence. By the end of 2005, generation at suspended plants had been restarted, with government approval.
In 2007, however, the company announced to the public that an internal investigation had revealed a large number of unreported incidents. These included an unexpected unit criticality in 1978 and additional systematic false reporting, which had not been uncovered during the 2002 inquiry. Along with scandals at other Japanese electric companies, this failure to ensure corporate compliance resulted in strong public criticism of Japan's electric power industry and the nation's nuclear energy policy. Again, the company made no effort to identify those responsible.
2008 shutdown.
In 2008, Tokyo Electric, forced to shut the Kashiwazaki-Kariwa Nuclear Power Plant after an earthquake, posted its first loss in 28 years as oil and gas costs soared.
Nuclear accidents.
On 11 March 2011 several nuclear reactors in Japan were badly damaged by the 2011 Tōhoku earthquake and tsunami.
The Tōkai Nuclear Power Plant lost external electric power, experienced the failure of one of its two cooling pumps, and two of its three emergency power generators. External electric power could only be restored two days after the earthquake.
The Japanese government declared an "atomic power emergency" and evacuated thousands of residents living close to TEPCO's Fukushima I plant. Reactors 4, 5 and 6 had been shut down prior to the earthquake for planned maintenance. The remaining reactors were shut down automatically after the earthquake, but the subsequent tsunami flooded the plant, knocking out emergency generators needed to run pumps which cool and control the reactors. The flooding and earthquake damage prevented assistance being brought from elsewhere. Over the following days there was evidence of partial nuclear meltdowns in reactors 1, 2 and 3; hydrogen explosions destroyed the upper cladding of the building housing reactors 1 and 3; an explosion damaged reactor 2's containment; and severe fires broke out at reactor 4.
The Fukushima nuclear disaster revealed the dangers of building multiple nuclear reactor units close to one another. This proximity triggered the parallel, chain-reaction accidents that led to hydrogen explosions blowing the roofs off reactor buildings and water draining from open-air spent fuel pools—a situation that was potentially more dangerous than the loss of reactor cooling itself. Because of the proximity of the reactors, Plant Director Masao Yoshida "was put in the position of trying to cope simultaneously with core meltdowns at three reactors and exposed fuel pools at three units".
The Japanese authorities rated the events at reactors 1, 2 and 3 as a level 5 (Accident With Wider Consequences) on the International Nuclear Event Scale, while the events at reactor 4 were placed at level 3 (Serious Incident). The situation as a whole was rated as level 7 (Major Accident). On 20 March, Japan's chief cabinet secretary Yukio Edano "confirmed for the first time that the nuclear complex — with heavy damage to reactors and buildings and with radioactive contamination throughout — would be closed once the crisis was over." At the same time, questions are being asked, looking back, about whether company management waited too long before pumping seawater into the plant, a measure that would ruin and has now ruined the reactors; and, looking forward, "whether time is working for or against the workers and soldiers struggling to re-establish cooling at the crippled plant." One report noted that defense minister, Toshimi Kitazawa, on 21 March had committed "military firefighters to spray water around the clock on an overheated storage pool at Reactor No. 3." The report concluded with "a senior nuclear executive who insisted on anonymity but has many contacts in Japan sa[ying that] ... caution ... [as] plant operators have been struggling to reduce workers’ risk ... had increased the risk of a serious accident. He suggested that Japan's military assume primary responsibility. 'It's the same trade-off you have to make in war, and that is the sacrifice of a few for the safety of many,' he said. 'But a corporation just cannot do that.'"
There has been considerable criticism to the way TEPCO handled the crisis. It was reported that seawater was used only after Prime Minister Naoto Kan ordered it following an explosion at one reactor the evening of 12 March, though executives had started considering it that morning. TEPCO didn't begin using seawater at other reactors until 13 March. Referring to that same early decision-making sequence, "Michael Friedlander, a former senior operator at a Pennsylvania power plant with General Electric reactors similar to the troubled ones in Japan, said the crucial question is whether Japanese officials followed G.E.’s emergency operating procedures." Kuni Yogo, a former atomic energy policy planner in Japan's Science and Technology Agency and Akira Omoto, a former TEPCO executive and a member of the Japanese Atomic Energy Commission both questioned TEPCO's management's decisions in the crisis. Kazuma Yokota, a safety inspector with Japan's Nuclear and Industrial Safety Agency, or NISA, was at Fukushima I at the time of the earthquake and tsunami and provided details of the early progression of the crisis.
The Fukushima disaster displaced 50,000 households in the evacuation zone because of radioactivity releases into the air, soil and sea. In 2012 it was reported that 8.5 tonnes of radioactive water had leaked from Fukushima Daiichi No.4.
In June 2012 TEPCO revealed, that in 2006 and 2008 TEPCO-employees made two studies in which the effect of tsunami-waves higher than the "official" expected height of 5.7 meters was studied on the performance of the reactors. This was done after the large Indian Ocean tsunami in 2004. The conclusion from the simulation in 2006 was, that a 13.5 meter wave would cause a complete loss of all power and would make it impossible to inject water into reactor No.5. The costs to protect the plant for such an event was estimated to be about 25 million dollars. In 2008 the effect of a 10 meter high tsunami was calculated. TEPCO failed in both cases to take advantage of this knowledge, and nothing was done to prevent such an event to happen, because the study sessions were conducted only as a training for junior employees, and the company did not really expect such large tsunamis.
TEPCO subsequently signed a partnership with French company Areva to treat the contaminated water.
In 2016 three former TEPCO executives, chairman Tsunehisa Katsumata and two vice presidents, were indicted for negligence resulting in death and injury. All were acquitted by the Tokyo District Court on Sept. 19, 2019.
Company future.
On 30 March 2011, the president of TEPCO, Masataka Shimizu, was hospitalized with symptoms of dizziness and high blood pressure in the wake of an increasingly serious outlook for the Fukushima plant and increasing levels of radiation from the stricken plant, as well as media reports of TEPCO's imminent nationalization or bankruptcy triggered by the situation at the Fukushima plant.
On July 31, 2012, TEPCO was substantially nationalized by receiving a capital injection of 1 trillion yen (US$12.5bn) from the Nuclear Damage Liability Facilitation Fund (currently Nuclear Damage Compensation and Decommissioning Facilitation Corporation), a government-backed support body. The Fund holds the majority (50.11%) of voting rights with an option to raise that figure to 88.69% by converting preferred stocks into common stocks. This Japan's biggest utility had received by the end of February 2016 at least 5.7609 trillion yen in state support since the tsunami. The total cost of the disaster was estimated at $100bn in May 2012. In April all Japanese nuclear reactors were closed.
Power plants.
Nuclear.
In March 2008, Tokyo Electric announced that the start of operation of four new nuclear power reactors would be postponed by one year due to the incorporation of new earthquake resistance assessments. Units 7 and 8 of the Fukushima Daiichi plant would now enter commercial operation in October 2014 and October 2015, respectively. However, following the nuclear crisis of 2011, these plans have been cancelled.
According to TEPCO's official regulatory paper, starting operation of Higashidori is expressed as 'Not yet determined'.
Hydro.
TEPCO has a total of 160 hydroelectric stations with a total capacity of 8,520 MW. The largest pumped-storage plants are:
Electric vehicle batteries and recharging.
Under the lead of an organization affiliated with the Ministry of Economy, Trade and Industry, the Tokyo Electric Power Company is working out next-gen car battery norms.
It has developed a specification for high-voltage DC automotive fast charging using a JARI Level 3 DC connector, and formed the CHΛdeMO (stands for Charge and Move) association with Japanese automakers Mitsubishi, Nissan and Subaru to promote it.
The city of Tokyo: second largest shareholder.
On 11 April 2012 TEPCO announced that Tokyo had temporarily become the largest shareholder of the firm with 9.37 percent voting rights, after former largest share holders Dai-ichi Life Nippon Life Insurance Co. and Nippon Life Insurance Co. had sold their 3.42 and 3.29 percent stakes in the company. The two life insurance companies had lost their interest in TEPCO after the shares had lost almost all their value at the stock market. At the next shareholders meeting of TEPCO in June 2012, Tokyo hoped to put a halt to TEPCO's plans raising the price of electricity. This position was changed by later ownership changes.
TEPCO to cancel nuclear promotion abroad.
Early June 2012 TEPCO announced that it would cancel all export of nuclear expertise abroad, because it needed to focus on the stabilisation of the damaged reactors in Fukushima. All participation in a program to supply and run two nuclear reactors at a plant in Vietnam would be cancelled. This project undertaken by International Nuclear Energy Development, a public company set up in 2010 by heavy machinery producers and power companies, including TEPCO, aims to promote Japanese nuclear expertise and exports. According to Naomi Hirose, director of TEPCO, "Our atomic power engineers still need to do a lot more to stabilise and decommission the reactors" at the crippled Fukushima Daiichi plant, and: "It is impossible" to abandon the domestic task and promote exports.


Bajaj Electricals

Bajaj Electricals Ltd () is an Indian consumer electrical equipment manufacturing company based in Mumbai, Maharashtra. It is a part of the Bajaj Group. It has diversified with interests in lighting, luminaries, appliances, fans, LPG based Generators, engineering and projects.
Its main domains are lighting, consumer durable, engineering and projects. Lighting includes lamps, tubes and luminaire. Consumer durable include appliances and fans. Engineering and projects include transmission line towers, telecommunications towers, high-mast, poles and special projects, and others include die casting, wind energy & solar energy. Some notable project includes lighting works at the Commonwealth Games stadium and the Bandra Worli Sea Link
It has 19 branch offices spread in different parts of the country with a chain of about 1000 distributors, 4000 authorized dealers, over retail outlets and over 282 Customer Care centers.
History.
Bajaj Electricals was incorporated on 14 July 1938 as Radio Lamp Works Limited under the Indian Company Act, 1913 as a Public company limited. On 1 October 1960 it was renamed to Bajaj Electrical Limited.
In 1964, Matchwell Electricals (India) Limited, ("Matchwell"), a manufacturer of electric fans became a subsidiary of the Company and subsequently, with effect from 1 July 1984, the business and undertaking of Matchwell was amalgamated with the company.
In the financial year 1993–1994, Bajaj Electrical entered into a joint venture with Black & Decker Corporation, US, for the manufacture and marketing of power tools, household appliances, and related accessories, through a separate company named Black & Decker Bajaj Private Limited, ("Black & Decker Bajaj").
During the financial year 1999-2000 Black & Decker Bajaj became a 100% subsidiary of the Company upon the Company acquiring a further 50% of the shareholding thereof from Black & Decker Corporation, after which Black & Decker Bajaj was renamed as Bajaj Ventures Limited.
However, in the financial year 2002–2003, the Company divested 50% of its shareholding in Bajaj Ventures Limited and Bajaj Ventures Limited ceased to be a subsidiary of the company.
In January 1998, the company established a new manufacturing unit at Chakan near Pune and commenced operations of manufacturing of fans and die-cast components. The production of fans at the manufacturing activities of the Matchwell unit also was gradually shifted to the Chakan unit.
In September 1999, Bajaj established and commissioned a wind energy generation unit with an installed capacity of 2.8 mega watts in the village of Vankusawade in Satara, Maharashtra. The facility continues to run profitably till date.
In the year 2000-2001 the Company set-up manufacturing facilities including a fabrication unit and a galvanising plant at Ranjangaon, near Pune for the manufacture of high masts, lattice towers, and related products, and the said manufacturing facilities commenced commercial production with effect from 1 April 2001.
In November 2002, the Company entered into a technical collaboration and brand licensing agreement with Morphy Richards, United Kingdom, for the sales and marketing of electrical appliances under the brand name of "Morphy Richards" in India.
In the year 2005 the company entered into a Distribution agreement with Trilux Lenze of Germany for high end technical lighting.
In the year 2007, the company acquired 32% of the share capital of Starlite Lighting Limited, a company engaged in the manufacture of Compact Fluorescent Lamps ("CFLs").
In 2012–2013, they have completely divested the stake and association with Black & Decker Corporation, USA.
In 2015 Bajaj Electrical appointed On Ads Communications as their sole creative partner.


Electricity sector in Sri Lanka

The electricity sector in Sri Lanka has a national grid which is primarily powered by hydroelectric power and thermal power, with sources such as photovoltaics and wind power in early stages of deployment. Although potential sites are being identified, other power sources such as geothermal, nuclear, solar thermal and wave power are not used in the power generation process for the national grid.
The country is expected to achieve 100% electricity generation by renewable energy by 2025.
History.
Sri Lanka (then Ceylon) first witnessed electricity in 1882 when SS Helios docked in Colombo for a local electricity exhibition.
In 1890, using a diesel generator the first electric bulb in Ceylon was lit with electricity in the Billiard Room of Bristol Hotel in Colombo, before electric lights became an established commercial product.
In 1895, Messrs Boustead Bros established a small power station in Bristol Building, Fort. The power station was the first commercial power station in the country, serving a few mercantile offices, government buildings, and streets, in the Fort area. The company established "Electricity Ordinance No. 5", the first Act pertaining to the supply of electricity in the country.
Four years later in 1899, United Planters Company established the Colombo Electric Tramways, the first tram system in the country. In 1902, Colombo Electric Tramways and Lighting Co. Ltd. was formed, and the Pettah Power Station was established on Gas Works Street.
The Pettah Power Station served the tram network, and also served mostly mercantile offices, government buildings, and streets. Over the next three years, the electricity supply was extended to Galle Face and Kollupitiya, serving several houses.
In 1905, the Colombo Gas Company established a power station in Kandy, which was eventually taken over by the Kandy Municipal Council in 1922. In 1906, "Electricity Ordinance No. 36" was passed as an amendment to "Electricity Ordinance No. 5".
In 1912, the government commissioned a small hydroelectric power station at Black Pool, and inaugurated the Nuwara Eliya Electricity Scheme. In 1918, D. J. Wimalasurendra, submitted a report to the Engineering Association of Ceylon, outlining the economic viability of hydroelectricity in Ceylon.
From 1920, local authorities in at least Gampaha, Veyangoda, Ja-Ela, Peliyagoda, Kochchikade, Avissawella, and Minuwangoda started supplying electricity locally from diesel generators.
In 1927, the Department of Government Electrical Undertakings (DGEU) was established to take over and run the electricity supply business in Colombo, and extend the supply to other areas, and eventually the entire country. The three-megawatt Stanley Power Station - named after Herbert Stanley, was commissioned in 1929, supplying 16 towns by the end of the year.
In 1935, the State Council of Ceylon passed "Electricity Board Establishment Ordinance No. 38 of 1935", only to be dissolved again 1937 with the re-establishment of the DGEU.
Sri Lankan gained independence on 4 February 1948.
On 30 October 1950, the Old Laxapana Power Station was finally completed, after being under development since 1924. The same year, regional offices were opened in Norton Bridge, Nuwara Eliya, Diyathalawa, Panadura, Negombo, Avissawella, and Peradeniya, to decentralise the electricity works. The following year, electricity was purchased from the Kankesanthurai Cement Factory from distribution in Jaffna.
On 1 November 1969, the current Ceylon Electricity Board (CEB) was established under Parliament Act No. 17 of 1969. To this day, the CEB oversees the development and coordination of the generation, supply, and distribution of electricity in the country.
Power generation.
Electricity in Sri Lanka is generated using three primary sources — thermal power (which includes energy from biomass, coal, and fuel-oil), hydro power (including small hydro), and other non-conventional renewable energy sources (solar power and wind power):
Hydroelectricity.
Hydroelectricity is the oldest and historically the principal source of electricity generation in Sri Lanka, holding a share of 48% of the total available grid capacity in December 2013 and 58% of power generated in 2013. Hydroelectric power generation has been constantly under development since the introduction of the national grid itself, but its market share is declining because suitable new sites are scarce. Currently, ten large hydroelectric power stations are in operation, with the single largest hydroelectric source being the Victoria Dam. Although a large portion of the country's hydroelectric resource are tapped, the government continues to issue small hydro development permits to the private sector, for projects up to a total installed capacity of per project.
State-run hydroelectric developments are categorized into three main geographic sectors.
Thermal power.
Thermal power stations in Sri Lanka now roughly match the installed hydroelectric generation capacity, with a share of nearly 49% of the available capacity in December 2013 and 40% of power generated in 2013. Thermal power stations in Sri Lanka runs on diesel, other fuel oils, naptha or coal. The Norocholai Coal Power Station, the only coal-fired power station in the country, was commissioned in late 2011, adding a further of electrical capacity to the grid. It is currently planned to add an additional of capacity to Norocholai in the next half decade. The second and final coal power station, the Sampur Coal Power Station, is under consideration in Trincomalee and is expected to be in-service by the end of 2017. On 13 September 2016 the Attorney General's Department informed the Supreme Court that the Sampur Coal fired plant has been cancelled and will not be built.
Wind power.
The use of wind energy was seen in the country even before 500 BC. The ancient Sinhalese used the monsoon winds to power furnaces as early as 300 BC, making Sri Lanka one of the first countries in the world to use wind power. Evidence of this has been found in Anuradhapura and in other cities.
The development of modern wind farms was considered by local and international developers for many years. Such developments were largely hampered due to the many obstacles faced in such developments in economics and infrastructure. The first commercial grid-connected wind farm is the Hambantota Wind Farm, northwest of Hambantota.
Unlike other power sources, power developments from this source would face many challenges during its development timeline. Poor accessibility to potential sites is the first obstacle in the development of a wind farm. Most key transport routes around the country are too narrow or have turns too tight for transportation of turbines larger than . Constructing wind farms with turbines smaller than the current commercial-scale megawatt-class turbines would prove to be uneconomical due to the high cost incurred during development.
The country is also in a long battle against its poor power grid. The grid, apart from being unstable in most provinces, is only capable of handling a small increases in load, typically limited to a few megawatts. Provinces with poor grids, such as the power grids in the Northern, North Central and North Western provinces need complete upgrade to support further commercial-scale developments. This factor contributes to a large percentage in development costs for wind farms constructed at such locations. The government policy limit of per wind project also significantly decreases economies-of-scale, further straining such developments.
Current status.
Despite the many technical obstacles, a few developments totalling have been proposed till September 2009. In October 2009, cases were filed over political interference connected with the approving of wind projects, leading to a complete halt in the wind power industry in Sri Lanka. The Ministry made allegations of wrongdoing in allocating energy licences, including the structuring of the wind power tariff. There were also allegations that energy licenses are being sold, similar to how car licenses have been sold.
From December 2009 to March 2010, permits for another of projects were issued by the Sri Lanka Sustainable Energy Authority, before concerns relating to the issuing of permits were raised again, leading to another deadlock in the industry. As of June 2010, issuing of permits for the development of private wind farms were stopped.
In July 2010, engineers at the Ceylon Electricity Board raised further concerns regarding the approval of private wind projects with extra high tariffs, presumably some of the highest in the world. A review of the wind power tariff was expected to be carried out on 12 September 2010, after an agreed postponement.
Solar power.
As of 2017, Sri Lanka has more than 100 MW in installed capacity for solar power and intends to be able to generate 1 GW installed capacity by 2025.
Grid-connected solar power has only recently been introduced. The only operational commercial-scale solar-powered facility is the Buruthakanda Solar Park of , operated by the Sri Lanka Sustainable Energy Authority (SLSEA).
Through the Ministry of Power and Renewable Energy, Ceylon Electricity Board, and the SLSEA, the country is implementing an accelerated solar rooftop program called Soorya Bala Sangramaya (Battle for Solar Energy). The program was launched on 6 September 2016.
Geothermal power.
Geothermal power is under research, although no power stations of this type are operational.
Nuclear power.
The CEB has included a 600 MWe nuclear power plant as an option in its plans for 2031.
Power transmission.
Transmission network.
The Sri Lankan electric transmission network consists principally of 132 kV facilities, with a 220 kV backbone connecting major inland hydroelectric generation to the capital region.
India – Sri Lanka grid interconnection.
The proposed connection involves the linking of the national grids of India and Sri Lanka via Rameshwaram in south India and Talaimannar in north-west Sri Lanka. The project involves the construction of a HVDC connection between Madurai in southern India and Anuradhapura in central Sri Lanka, through the Palk Strait. The link would measure approximately in length, including of submarine cables, and would take more than three years to construct. It would be implemented by the Power Grid Corporation of India Limited and Ceylon Electricity Board.
Electricity use.
End-user power tariffs.
The monthly end-user electricity tariffs are:
Net metering.
In 2010, the Ministry of Power and Energy, with the Lanka Electricity Company and the Ceylon Electricity Board introduced net metering, where consumers could generate their own power from renewable sources and credit excess production back to the power utility. While the power utility will not pay back in monetary values irrespective of how much credit a household generates, it allows the transferring of this credit between households. The first solar power facility intended for net metering was commissioned in July 2010.
Entities exempted for electricity-usage charges.
Per Section 21-2 of the "Sri Lanka Electricity Act No. 20 of 2009", the has granted the following entities exemptions in electricity usage:


United Energy

United Energy is a Victorian energy network which distributes electricity across east and south-east Melbourne and the Mornington Peninsula to more than 640,000 customers, 90% of which are residential. Its network includes 209,000 poles and over 13,000 kilometres of wires. Electricity is received via 78 sub-transmission lines at 46 zone stations, where it is transformed from sub-transmission voltages to distribution voltages.
The company was owned by the DUET Group, which also owned Multinet Gas, which distributes gas in Melbourne's inner eastern suburbs to middle-eastern Victoria. DUET also owned the West Australian Dampier to Bunbury Natural Gas Pipeline, the sole gas conduit for Perth and coastal West Australia.
In April 2017, Hong Kong-based Cheung Kong Infrastructure (CKI) proposed to acquire the DUET Group for A$7.4 billion, which was approved by FIRB later that month. CKI also owns CitiPower in Melbourne, Powercor in western Melbourne and western Victoria, and Envestra, which distributes gas through much of Victoria, as well as Queensland and South Australia. After the acquisition, CKI owns three out of five electricity distributors and two out of three gas distributors in Victoria.


Energy Regulatory Office

The Energy Regulatory Office (ERO) is an independent regulatory agency which sets the regulatory framework founded on the principles of free trade in Kosovo.
Functions.
The energy price is determined by different factors: operative cost, maintenance cost, import and other factors. The decrease of commercial and technical losses would affect positively in the tariffs of energy in Kosovo. Factors that have kept the low prizes until now are: foreign investments as grants, government subsidies, the lack of investments for environment protection and inexpensive labor force. Kosovo Energy Corporation (KEK) generating about 97% of the energy has the monopoly of market. ERO has the jurisdiction of setting tariffs for energy services.


Snowy Hydro

Snowy Hydro Limited is an electricity generation and retailing company in Australia that owns, manages, and maintains the Snowy Mountains Hydro-electric Scheme which consists of nine hydro-electric power stations and sixteen large dams connected by 145 kilometres (90 mi) of tunnels and 80 kilometres (50 mi) of aqueducts located mainly in the Kosciuszko National Park. Snowy Hydro also owns and operates two gas-fired power stations in Victoria and one in New South Wales, three diesel power stations in South Australia, and owns two electricity retailing businesses (Red Energy and Lumo Energy).
The company is owned by the Australian Federal government and whilst not a statutory corporation, is established by the "Snowy Mountains Hydro-electric Power Act 1949 (Cth)". Prior to its incorporation under the "Corporations Act 2001 (Cth)", the company was previously known as Snowy Mountains Hydro-electric Authority.
Generating assets.
The company manages the Snowy Mountains Scheme which generates on average around 4,500 gigawatt hours of clean, renewable energy each year, which is around 37% of all renewable energy in the mainland National Electricity Market in 2010.
The company also owns a 300 MW gas-fired peaking power station in Victoria's Latrobe Valley, a 320 MW gas-fired peaking power station at Laverton North near Melbourne, and a 667 MW gas-fired peaking power station at Colongra on the Central Coast of New South Wales. It also owns three diesel-powered peaking power stations in South Australia providing 136 MW between them. The company's production assets are summarised in the table below. These assets are used to generate electricity for sale under contract to the National Electricity Market.
Water storage and diversion.
As part of the company's responsibilities for managing the Snowy Mountain Scheme, Snowy Hydro Limited also collects, stores, and diverts water for irrigation from the Snowy Mountains catchment west to the Murray and Murrumbidgee River systems under what is called the "Snowy Water Licence". Granted as part of the for fixed five-year terms, this licence prescribes the rights and obligations on the company with respect to the collection, diversion, storage, use, and release of water within the Snowy area. The Snowy Water Licence also imposes some obligations on the company in terms of releasing environmental flows east into the Snowy River and other rivers in the Snowy Mountains region.
Proposed public divestment.
In December 2005, the NSW Government announced it would sell its 58% share in Snowy Hydro, expecting to yield A$1 billion. The Federal and Victorian governments had followed suit, announcing by mid-February 2006 the intent to sell their 13% and 29% respectively, with A$1.7 billion (ranging up to A$3 billion) expectations through a public float. Pre-registration for shares in Snowy Hydro opened in mid May and it was expected that the float would take place some time in July. Over 200,000 people pre-registered to purchase shares in the company over two weeks.
On 2 June 2006, the Federal Government announced that it would no longer sell its 13% stake in the project, effectively forcing the hands of the New South Wales and Victorian governments to follow suit. The aborted sale followed strong opposition from the public, including government MPs and prominent Australians.
In February 2014 the National Commission of Audit recommended in its Phase One Report that the Commonwealth sell its interest in Snowy Hydro.
Current market position.
Since privatisation was cancelled in 2006, the company has continued to grow with investment into Snowy Scheme modernisation projects, cloud seeding, development of mini hydro opportunities such as the 14 MW Jounama mini-hydro (commissioned in 2010) and growth of its retailing business, Red Energy. In September 2014 Snowy Hydro purchased gas and electricity retailer Lumo Energy for $600 million. Red Energy currently has 1.6 million electricity and gas customers and is a sponsor of the Newcastle Knights and Breast Cancer Australia, and a partner of Qantas Frequent Flyers.
In addition Snowy Hydro has developed its gas-fired power station portfolio to reduce risks to the business due to its reliance on water as an energy source, and the potential impact of transmission constraints on the ability of the remote Snowy Mountains hydro generation assets to access the electricity grid. In January 2015 Snowy Hydro acquired the gas-fired Colongra power station in New South Wales.


U.S. Gas and Electric

Founded in 2002, U.S. Gas & Electric, Inc., its subsidiaries and family of companies ("USG&E") is a provider of energy supply to commercial and residential customers. Recognized by Inc. magazine as one of the Fastest-Growing Private Companies in America within the energy industry, USG&E services customers in Connecticut, District of Columbia, Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio and Pennsylvania with plans for further expansion.
Founded in 2002 by Douglas Marcille and associates, and establishing CEO Don E. Secunda, Esq., the company is based in White Plains, New York, with its principal offices in Miramar, Florida. In 2013, Doug Marcille was named as the Florida State Business Ambassador by Florida Governor Rick Scott


Tuirial Hydro Electric Project

Tuirial Hydro Electric Project is NTPC NEEPCO owned project situated on Tuirial river system and is located in the Aizawl district of Mizoram adjoining Cachar district of Assam. Total installed capacity of project is 60(2 x 30) MW.


Cross Sound Cable

The Cross-Sound Cable is a long bipolar high-voltage direct current (HVDC) submarine power cable between New Haven, Connecticut, USA and Shoreham, Long Island New York, USA. The Cross-Sound Cable can transmit a maximum power of 330 MW at a voltage of +/- 150 kV DC. The maximum current for Cross-Sound Cable is 1175 amperes. The Cross-Sound Cable is not simply a pair of underwater HVDC cables; rather it is a bundle of cables that includes the HVDC transmission lines and fiber-optic cables for phone and Internet data transfer.
Construction of the Cross-Sound Cable was started in 2002 from the former site of the Shoreham Nuclear Power Plant. The cable was first laid on the floor of Long Island Sound; then a machine known as a jet plow tool used high-pressure water to fluidize the sea bed directly under the cable. The cable then fell into the liquidized trench.
Concern over possible environmental impact of the buried underwater cables caused significant delay in operation. Commercial operation of the cable was delayed until after the August 14, 2003 blackout of much of the eastern North American power system. Immediately after the blackout, emergency permission was secured to operate the cable. The cable has since been operating and, generally, sells electricity from the New England power grid to the New York power grid.
The builders and first operators of the project, TransÉnergie HQ, a subsidiary of Hydro-Québec, and the United Illuminating Company, sold their interests in the cable to Babcock & Brown for approximately US $213 million in February 2006.
The converters of Cross-Sound Cable are examples of HVDC light technology. Power can flow in either direction between New Haven and Shoreham terminals.


Geothermal power in Australia

Geothermal power in Australia is little used but growing. There are known and potential locations near the centre of the country that have been shown to contain hot granites at depth which hold good potential for development of geothermal energy. Exploratory geothermal wells have been drilled to test for the presence of high temperature geothermal reservoir rocks and such hot granites were detected. As a result, projects will eventuate in the coming years and more exploration is expected to find new locations.
Exploration.
There is exploration being conducted in all states and the Northern Territory but there is no commercial production of geothermal energy in Australia. Exploration involves finding vast blocks of "hot rocks" with fracture systems that could generate electricity through water being injected, circulated through the fractures, and being returned to surface as steam which could then be used to rotate steam turbines.
There are vast deep-seated granite systems in Central Australia that have high temperatures at depth and these are being drilled by companies such as Panax Geothermal, Geodynamics Ltd, Petratherm, Green Rock Energy and Pacific Hydro to depths of more than four kilometres.
South Australia has been described as "Australia's hot rock haven" and this renewable energy form could provide an estimated 6.8% of Australia's base load power needs by 2030. According to a conservative estimate by the Centre for International Economics, Australia has enough geothermal energy to contribute electricity for 450 years.
Parts of central Tasmania have been identified by KUTh Energy as having the potential to generate up to 280MW of power. Such a resource would be able to supply 25% of Tasmania's electricity needs.
Projects.
Paralana.
The 30 MW Paralana project is located adjacent to the Beverley Uranium Mine. It is an enhanced geothermal system (EGS) project, based on Petratherm’s "heat exchanger within insulator" model.
Cooper Basin.
A 25 MW Cooper Basin demonstration project to assess the potential of hot-rock geothermal energy for zero-emission, base-load power was commenced by Geodynamics. However, the project was abandoned after being assessed as uneconomic due to a combination of the cost of commercialising generation and the remoteness of the site.
"The technology worked but unfortunately the cost of implementing the technology and also the cost of delivering the electricity that was produced to a market was just greater than the revenue stream that we could create," Geodynamics chief executive Chris Murray said.
Geodynamics is no longer exploring geothermal power and is instead looking at other green energy initiatives. It has therefore changed its name to ReNu Energy and changed its ASX code to RNE.
Jurien-Woodada.
The Jurien-Woodada project, owned by New World Energy Limited, is the most advanced geothermal play in Western Australia for electricity production. The project is adjacent to transmission infrastructure and large resource-driven energy markets in the mid-west region. The project area has the potential to contain both hot sedimentary aquifer and EGS styles and is being assessed for delivery of electricity into Western Australia's South West Interconnected System.
Otway Basin.
The Penola Project is part of Panax’s Limestone Coast Project and is the largest of only four known Measured Geothermal Resources in Australia. An independent assessment has estimated the geothermal resource potential at 11,000 petajoules.
The Penola Project has an extensive database with 28 petroleum wells. The deepest petroleum exploration well is approximately 4,000 metres and intersects more than 1,000 metres of the target reservoir, the Pretty Hill Sandstone.
Panax’s Salamander-1 well, drilled in 2010 is the first deep geothermal well drilled in the Otway Basin. It was completed in record time and is the first to demonstrate conventional geothermal technology in Australia. First steam was produced and the well-testing programme was also completed on the project in 2010.
The Salamander-1 well met its primary objectives. At 4,000 metres projected geothermal temperatures were exceeded by more than 10°C and target reservoir rocks met the requirements for the development of a geothermal demonstration plant. An in-house pre-feasibility study found the project has the potential to generate power at $83 per megawatt hour, which is cheaper than wind power. Complications with the well were found during well-testing. Reservoir engineers have been engaged to examine the well and carry out remediation works.
Panax a conventional geothermal technology in Australia with its Salamander-1 well and is securing funding from the Australian Federal Government to progress the Penola Project.


Associated Gas and Electric


CU (power line)

CU is the designation of a line for high-voltage direct current (HVDC) transmission between the Coal Creek Station power plant south of Underwood, North Dakota at and the Dickinson converter station near Buffalo, Minnesota at .
The designation most likely refers to two Minnesota-based power generation/transmission cooperatives that originally partnered to build the Coal Creek plant and associated line - Cooperative Power Association and United Power Association, which later merged to become Great River Energy. Great River Energy recently announced that the mine-mouth plant that supplies this line, Coal Creek Station, will be decommissioned in 2022, unless another entity steps up to acquire (and continue operating) the plant, leaving the future of this line in doubt.
The CU project controversy in 1978 and 1979 was a result of protests by farm landowners in the path of the CU line right of way.
The CU line, which went in service in 1978, can transfer an electrical power of 1,000 megawatts at a symmetrical transmission voltage of 400 kV. An overhead line connection 436 miles (710 kilometers) long is used, with two conductors per pole. Thyristor static inverters are used.
Crossing of HVDC powerlines.
Southeast of Wing, North Dakota, at CU crosses Square Butte, another HVDC powerline. This is the only crossing point of two HVDC overhead powerlines in the Western hemisphere.
Electrodes.
The ground return electrode line at Coal Creek Station uses the towers of the AC line between and as support before it ends at .
The electrode line at Dickinson converter plant runs on the towers of the main line until a tower at . From this tower it runs on a line on 4 poles until its endpoint situated at .


ActewAGL

ActewAGL is an Australian multi-utility joint venture company that provides utility services in the Australian Capital Territory (ACT) and south-east New South Wales. The company was formed in October 2000 between the Australian Gas Light Company (now AGL Energy) and ACTEW Corporation (now Icon Water), an ACT Government-owned corporation.
As of October 2017, ActewAGL is made up of two partnerships:
History.
ActewAGL and their predecessors have been supplying energy and essential services to the Canberra region for over 100 years.
ActewAGL was formed in October 2000 as a joint venture between the Australian Gas Light Company (AGL) and ACTEW Corporation, a government-owned enterprise of the ACT Government.
In 2000, ActewAGL entered into a contract with ACTEW Corporation for the management and operation of the water and sewerage network of the ACT and surrounding area. In February 2004, ActewAGL entered into a management agreement with TransACT Capital Communications Pty Ltd.
In October 2006 ActewAGL's business was reorganised, creating separate retail and distribution entities. AGL and ACTEW Corporation continued as the partners for the retail business and Alinta and ACTEW Corporation became partners of the distribution business. Alinta changed its name in August 2008 to Jemena.
In June 2012, ACTEW Corporation did not renew ActewAGL's water and sewerage management contract.
Innovation.
Since its beginning, ActewAGL has continued to undertake several innovative programs to help the environment. They include the following.
Evoenergy.
Evoenergy is the name used by the electricity poles and wires, and gas pipes business and is part of the ActewAGL Distribution partnership. Evoenergy owns and operates over 2,000 km of electricity network and over 4,500 km of gas mains.
In 2018, Evoenergy partnered with the Canberra Institute of Technology (CIT) to build a first-of-its-kind hydrogen test facility to test how hydrogen interacts with network materials, work practices and equipment. The study so far has verified that the underground 200kPa plastic network is compatible with 100 percent hydrogen.
In March 2020, Evoenergy was awarded $2.05 million in funding from the Australian Renewable Energy Agency (ARENA) to research and test the impact of distributed energy resources on Canberra's energy market. The project will involve working in close collaboration with Schneider Electric, GreenSync, and Withywindle, and will explore the effect that distributed energy resources such as solar photovoltaics (PV), battery installations and electric vehicles have on the electricity network, and how these resources can be used by customers to their full potential.
In September 2020, Evoenergy received a $250,000 grant from the ACT Government to provide home batteries for 75 homes as part of the Ginninderry Residential Battery Trial. Ginninderry Estate is one of Canberra's first all-electric suburbs and the project will provide Evoenergy with the opportunity to analyse solar and battery usage patterns.


Washington Metropolitan Area Transit Commission

The Washington Metropolitan Area Transit Commission or WMATC is a regulatory agency established by the Washington Metropolitan Area Regulation Compact, an interstate compact established between the Commonwealth of Virginia, the District of Columbia and the State of Maryland, and consented to by Congress under Public Law 86-794 in 1960 to regulate passenger common carriers operating within the District of Columbia, and the suburbs in Maryland and Virginia.
Registration.
A common carrier desiring to offer passenger transportation for hire within the "Metropolitan District" must register with the commission and obtain a WMATC number. This includes public bus systems owned by cities and counties within the region if managed and operated by a private company. Carriers directly operated by a state, or a municipality within the region are exempt from registration. Carriers operating exclusively within Virginia are exempt from registration with WMATC as they would register with the Virginia State Corporation Commission.
Taxicab companies that operate vehicles carrying 9 or fewer passengers (including the driver) are also exempt from registration with WMATC.
Being authorized by the commission and issued a WMATC number to operate vehicles(s) means the organization does not have to register as a common carrier with the U.S. Department of Transportation if they operate exclusively within the Metropolitan District. Depending on the type of service, it may or may not have to also register with the District of Columbia Department of For-Hire Vehicles, the Virginia State Corporation Commission, and/or the Maryland Public Service Commission. WMATC serves as a single registration point for passenger common carriers operating within the "Metropolitan District," consisting of the District of Columbia; the cities of Alexandria and Falls Church, Arlington County and Fairfax County and the political subdivisions located within those counties, and that portion of Loudoun County occupied by Dulles International Airport; and Montgomery and Prince Georges Counties in Maryland and political subdivisions located within those counties.
Requirements.
The general requirement to obtain a WMATC number is similar to the U.S. Department of Transportation's requirement to obtain a DOT number, or most state Public Utilities Commissions to obtain a state registration number: submit a set of tariffs stating prices for services, pay a fee of about $500, and provide evidence of either a minimum of $1.5 million in insurance for carriers operating vehicles having 15 passengers or less (including the driver), or at least $5 million in insurance for carriers operating vehicles which can carry more than 15 persons.
As with any other registration system, the carrier posts their number on the outside of their vehicles in the form "WMATC 126".
WMATC should not be confused with the Washington Metropolitan Area Transit Authority (WMATA) which is the bus and train operator for the City of Washington and suburbs. WMATA is also exempt from regulation by WMATC.


The Electricity Act, 2003

The Electricity Act, 2003 is an Act of the Parliament of India enacted to transform the power sector in India.
The act covers major issues involving generation, distribution, transmission and trading in power. While some of the sections have already been enacted and are yielding benefits, there are a few other sections that are yet to be fully enforced till date.
Background.
Before Electricity Act, 2003, the Indian Electricity sector was guided by The Indian Electricity Act, 1910 and The Electricity (Supply) Act, 1948 and the Electricity Regulatory Commission Act, 1998. The generation, distribution and transmission were carried out mainly by the State Electricity Boards in various States. Due to politico-economic situation, the cross-subsidies reached at an unsustainable level. For the purpose of distancing state governments from tariff determination, The Electricity Regulatory Commissions Act was enacted in 1998. So as to reform electricity sector further by participation of private sector and to bring in competition, Electricity Act was enacted in 2003.
With effect from 2 June 2003 India has adopted a new legislation called the Electricity Act 2003, to replace some age-old existing legislation operating in the country. The new act consolidates the position for existing laws and aims to provide for measures conducive to the development of electricity industry in the country. The act has attempted to address certain issues that have slowed reform in the country and consequently has generated new hopes for the electricity industry. This paper reviews the Electricity Act 2003, to highlight how the new features are different from the existing legal provisions and whether these measures have economic rationale.
An act to consolidate the laws relating to generation, transmission, distribution, trading and use of electricity for taking measures conducive to development of electricity industry, promoting competition therein, protecting interest of consumers and supply of electricity to all areas, rationalisation of electricity tariff, ensuring transparent policies regarding subsidies, promotion of efficient and environmentally benign policies, constitution of Central Electricity Authority Regulatory Commissions and establients of Appellate Tribunal for matters therewith or incident thereto.
Generation.
The Act delicenses power generation completely (except for all nuclear and hydro-power projects over a certain size).
As per the Act, 10 per cent of the power supplied by suppliers and distributors to the consumers has to be generated using renewable and non-conventional sources of energy so that the energy is reliable.
Electricity generation has been made a non-licensed activity and the techno-economic clearance from the Central Electricity Authority (CEA) has been done away with for any power plant, except for hydro-electric power stations above a certain amount of capital investment. This has been provided in section 7 and 8 of the Electricity Act 2003. The generators can sell electricity to any licensees or where allowed by the state regulatory commissions, to consumers directly. The provision of direct sale of electricity by the generators, when and where allowed, would promote more IPP participation in the power generation, as these consumers are more creditworthy and bankable compared to many SEB’s. However the act provides for imposition of a surcharge by the regulatory body to compensate for some loss in cross-subsidy revenue to the SEB’s due to this direct sale of electricity by generators to the consumers.
Distribution.
The Act licenses distribution in rural areas and brings in a licensing regime for distribution in urban areas.
However, as per the Act, only 16 states in India have notified what constitutes as rural areas and therefore the rural distribution is yet to be freed up in nearly one third of the country.
Key features.
The main features of the act are as follows:
Role of CEA.
The role of CEA is limited to policy recommendations, monitoring electricity sector performance, advising the Ministry of power on technical issues, data management/dissemination of the power sector, etc.
Preparation of technical standards for construction of electrical plants, electric lines and connectivity to the grid is the responsibility of CEA as per section 73 (b) of the Electricity Act, 2003. However, as per section 7 of this Act, a generating company may establish, operate and maintain a generating station if it complies with the technical standards only relating to connectivity to the grid as given in clause (b) of section 73. This implies that generating stations need not follow compulsory the CEA technical standards specified for construction of electrical plants and electric lines. Similarly, transmission / distribution licensees need not implement compulsory the standards for construction of electric lines except the Grid Code/ Grid Standards for the operation and maintenance of transmission lines specified by CEA under clause 73 (d) of this Act. Many times, these CEA standards are conservative compromising optimum design features /cost/ utility and also do not give full clarity in selection of the system / sub system capabilities of electrical plants and electric line.
Left parties opposition.
Left parties opposed the clauses related to competition in electricity market such as unbundling of Electricity Boards and open access and also had strong objection regarding elimination of cross subsidies. UPA government, in its first tenure agreed for some of the amendments and according clause regarding cross subsidies are amended. In its second tenure, UPA government published a draft amendment of The Electricity Act 2003 with the main intention of separation of retail sale of electricity from distribution business.
Amendments.
Several amendments were made after 2003 in the Act. The amendments proposed during 2015 is to make major changes. The important provision is to introduce electricity supply companies who will not own electric lines. The Government says it would attract competition and therefore will cause reduction in price. But those oppose these amendments say that in Indian situation competition can not bring down the cost. Some electricity finance experts are of the opinion that it will weaken the public sector discoms and can damage power sector industry in the country.
Section 25 of the electricity act, 2003 authorises the central government to demarcate the country into regions necessary for the efficient, economical and integrated transmission and supply of electricity, and in particular to facilitate voluntary interconnections and co-ordination of facilities for the inter-State, regional and interregional generation and transmission of electricity. Electricity is listed in the concurrent list (entry 38 of list III). The traditional and unscientific demarcation of the country into five regions (north, south, east, west and north east regions) without giving any valid justification and applying one set of rules for intra region and different set of rules for inter regions in sharing electricity transmission system and transmission losses, etc. is considered discriminating one state from another state. Without the public interest, Constitution does not recognise different set of rules applicable for a group of states except ratified by each of the concerned state under of the constitution.
The concept of dividing the country in to regions by clubbing few states, emerged in seventies to envisage pit head super thermal power stations nearer to coal mines and to supply the generated power to far flung areas by high voltage transmission lines. In last forty years, electricity sector in India has grown many folds and the present power consumption in many big states has exceeded the regional level power consumption at that time. Moreover, the electricity generation from other sources such as natural gas, hydro, nuclear, wind, solar, imported coal, etc. has increased substantially and country has achieved decentralisation and diversification with respect to electricity generation and its consumption. The concept of regions is no more useful by treating the states in a region at par and outside the region differently. Many states forming boundary of a region are unable to draw/export cheaper power from adjoining regions/states due to regional bias / differentiation. Also, the electricity grid has transformed into one national grid and the emergence of single grid operation has made practically regional grids obsolete. Each state should be considered as one administrative entity/region/area for power transmission and its losses accounting and its commercial settlement as a part of national grid. Section 25 (provision to create regions) and other related sections of the Electricity Act 2003 & proposed Electricity Bill 2014 are unconstitutional in the absence of its ratification by each state.
Electricity is also being transmitted in circuitous path (ex: north-eastern region exports power to eastern region, eastern region exports power to northern and western regions, western region exports power to northern region and power from northern region is exported back to north-eastern region. Similarly eastern region exports power to western region and western region exports to southern region instead of eastern region directly export all the net power needed by the southern, northern and north-eastern regions.) on daily basis without any economic sense by the central transmission company. Thus regional concept for power generation and transmission has become counter productive.
Exceptions.
The Act extends to the whole of India except the state of Jammu and Kashmir. However, Jammu and Kashmir is part of the northern region for sharing the transmission network and the electricity generated from the central power generating stations located in the Northern region. As of now above rule may not be applicable as article 370, a special status for Jammu and Kashmir had been ruled out.


Kuratau Power Station

The Kuratau power station is a hydroelectric power facility in Kuratau on the western side of Lake Taupo
in New Zealand which makes use of water from the Kuratau River. The river is impounded behind a dam to form Lake Kuratau before discharging through the power station back into the river. The scheme is operated by Trustpower on behalf of its owner King Country Energy.
History.
Development.
In 1952 Lloyd Mandeno who was the consulting engineer to the King Country Electric Power Board suggested to the board that they consider building a power station. With demand and its revenues increasing (it increased by 1375% between 1948 and 1958), having its own generation would reduce the amount of power the board would have to purchase from the State Hydro-Electric Department (SHD), while also boosting industrial development in the board's area. The SHD was in 1958 renamed the New Zealand Electricity Department (NZED). Mandeno identified that Kakahi on the Whakapapa River would be a suitable location. However the SHD turned down the board's application for a licence to build a power station as they also intended to utilize the river to generate electricity in what later became the Tongariro Power Scheme.
Continuing his investigations Mandeno identified what he thought was another suitable site in a narrow gorge that could utilize the Kuratau River. The board authorized him to spend up to £400 on further investigations. Satisfied with Mandeno's conclusions, the board in August 1953 decided to apply for a generation licence and commenced discussions with the SHD to determine if they had any objections and with the Local Government Authorities Loan Board. The Loan Board was prepared to offer a 40-year loan, while the SHD indicated that it was prepared to buy any surplus power produced by the station.
Detailed design of the power station was then undertaken by consulting engineers Mandeno, Lee & Brown (of which Lloyd Mandeno was a principal).
Delays then occurred as it took time for the board to secure access to the proposed site to undertake detailed investigations as the land was part of a Maori development block that was jointly owned by several Maori families. Both them and the Department of Maori Affairs who were responsible for administering the block were concerned over how much valuable farming land was going to be lost and what compensation would be offered. Eventually, the amount of the compensation that board had to pay to the land owners had to be settled in court. As a result, it took until 1955 before the board was granted a licence to generate electricity at Kuratau.
Further delays then occurred with obtaining the generation equipment, which had to be imported. The station's output was to be distributed over 33 kV transmission lines which had to be built. While it was not the first such line in the board's area it was the first that they contracted out for construction and as such delays were incurred in obtaining some of the equipment that required.
After its construction loan was secured in 1959 tenders were issued for construction and supply of equipment. Fletchers Construction won the contract to undertake the civil works with a price of £295,000. English firm Boving & Co won the contract to supply the turbines and other hydraulic machinery, Swedish firm ASEA won the contract supply the generators, while local company Turnbull & Jones were awarded the contract to supply the control panels and install the electrical equipment. Fletcher Steel & Engineering won the contract to supply the steel for the penstocks, intake trash racks, control gates and the powerhouse structure.
An 8-km-long access road was created to a construction camp where several workshops, temporary accommodation, and three permanent staff houses were established on a bluff above where the power house was to be built. The nearest pub was however 26 km away which created issues for those in the workforce wanting to have a drink after work as this was during the days of the Six o'clock swill which meant the pub closed at 6 pm.
Construction.
Construction began in 1959 under the management of Tony Campbell of Fletchers what was intended to be a concrete arch dam which would convey the water via a short tunnel and canal to penstocks and hence down to the power house.
However, as excavation began it was found that sides of the narrow gorge in which the dam was being built were unstable, with a large amount of sand being encountered. This was a common issue on the volcanic soils of the central North Island and had been encountered on some of the power stations that had been built on the Waikato River. Digging continued, but it soon became obvious that it would be impossible to find any sound rock into which to anchor the abutments of the dam.
Mandeno, Lee & Brown quickly redesigned the power station to make use of another site 400 metres further upstream for which they designed a low rock-fill dam from which an open canal, penstocks and a surge chamber could convey the water to the powerhouse.
Once the dam was completed, the lake took one week to fill.
Commissioning.
By early 1962 one penstock had been installed which allowed its associated generator to be commissioned and then commence commercial operation at midnight on 16 April 1962 and immediately began bringing in a potential revenue of £150 to 200 per day.
A large crowd celebrated the official opening of the station on 25 May 1962.
The second generator entered service on 21 June 1962.
Following the completion of the work, the construction site was cleared during the middle of 1962, with all temporary construction buildings removed, after which the site was landscaped with 8,450 trees and 12 acres of new grass.
The construction of the power station cost £500,000.
Refurbishment and strengthening.
In the 1980s the station was shut down while repairs and improvements were made. The canal was earthquake strengthened, fitted a with drainage system under the lining and relined with concrete and shotcrete to solve excessive leakage. At the same time erosion below the spillway was repaired with shotcrete, the fastening of the powerhouse's cladding was improved and the penstock supports were strengthened. Diversion banks were also added to control flooding in the event of the bursting of a penstock or the canal and the closing of the canal's intake gate during an earthquake was improved.
Design.
A 36-metre-tall by 118-metre-wide by 70-metre-long rock-fill dam impounds the Kuratau River to create Lake Kuratau, which covers approximately 100 hectares and gives a head of 64 metres. The dam is fitted with a spillway on its western side that can pass up to 110 cumecs down the empty bed of the river.
From the south eastern end of the lake a 495-metre-long canal which terminates in a forebay directs the water into two steel penstocks which lead to a surge chamber from which a further two steel penstocks, each 296 metres long convey the water down to a powerhouse located on Kuratau Hydro Rd, Omori. Inside the powerhouse are two 4,000 hp horizontal Boving & Co turbines. Each turbine is directly coupled to a 3 MW, 3 MVA horizontal ASEA three-phase generator.
The power station is embedded behind Transpower's Ongarue Substation, but can also be switched within The Lines Company network to either Transpower's National Park or Tokaanu substations.
Operation.
Operation of the power station is covered by the requirements of five resource consents which expire in December 2026.
As the power station is located in an area covered in pumice, the intake to the power station requires regular maintenance to remove the pumice which has become dislodged and then floats down the river to build up behind the dam.
Lake Kuratau is popular with a range of recreational users, including duck shooters and fly fishermen. The New Zealand Fly Fishing Association frequently uses the lake in its national competitions. In 2009 the lake was used for the Oceania Fly Fishing Championships.
Despite covering 100 hectare the lake which created in what is basically a long narrow flooded river valley has a relatively small volume. This means that for example at an inflow of about four cumecs the lake will be drained in between 36 and 48 hours if the station was operated at its full output.
The lake has a consented operating range of 2.61m which is typically not fully utilised during the station's day-to-day operation.


E-CL

E-CL is a Chilean utility company based in Santiago and formerly known as Empresa Electrica Del Norte Grande or Edelnor. The company, which changed its name in 2010, was founded in 1981 with contributions from the Empresa Nacional de Electricidad SA (Endesa) and the Corporacion de Fomento de la Produccion (CORFO).
The Company's activities comprise the production, transportation and distribution of electric energy and natural gas; the purchase, sale and transportation of liquid, solid and gaseous fuels; as well as the provision of engineering consulting services. The Company's products and services are principally oriented towards the mining companies and other industries operating in the north of Chile.
The company is a subsidiary of French company GDF Suez and its main competitors are Colbún, AES Gener and Chilectra.


Solar power in Africa

Africa is often considered and referred as the "Sun continent" or the continent where the Sun's influence is the greatest.
According to the "World Sunshine Map", Africa receives many more hours of bright sunshine during the course of the year than any other continent of the Earth: many of the sunniest places on the planet lie there.
Despite the large solar potential, penetration of solar power in Africa's energy sector is still very low.
Solar potential.
The whole continent has a long duration of sunshine, and excluding the large areas of tropical rainforests (the Guinean Forests of West Africa and much of the Congo Basin), since desert and savannah regions of Africa stand up as Earth's largest cloud-free area.
Africa is dominated by clear skies even beyond deserts (ex : Sahara, Namib, Kalahari), however, the regions located along the equator are considerably cloudier than the tropics and subtropics.
The eastern Sahara/northeastern Africa is particularly noted for its world sunshine records. The area experiences some of the greatest mean annual duration of bright sunshine, as the sun shines bright during approximatively as much as 4,300 hours a year, which is equal to 97% of the possible total.
This region also has the highest mean annual values of solar radiation (the maximum recorded being over 220 kcal/cm2).
The low latitude of the landmass is another asset: much of the continent lies in the intertropical zone, where the intensity and the strength of the sunlight are always high.
The area contains lots of vast sun-drenched arid and semi-arid expanses in the north, in the south, and to a lesser extent in the east. About two fifths of the continent are desert, and thus continuously sunny.
The combination of all these geographical and climatic factors is the cause of the large solar potential of Africa. The number of days of sunlight allows the potential of bringing solar power to much of Africa without large scale grid infrastructure.
The distribution of solar resources across Africa is fairly uniform, with more than 85% of the continent's landscape receiving a global solar horizontal irradiation at or over 2,000 kWh/(m2 year).
Also, the theoretical reserves of Africa's solar energy are estimated at 60,000,000 TWh/year, which accounts for almost 40% of the global total, thus definitely making Africa the most sun-rich continent in the world.
Solar photovoltaics.
Declining solar equipment costs are expected to significantly increase solar installations in Africa with an industry projection forecasting that the continent's annual PV market will expand to 2.2 GW by 2018.
Future installations for harvesting solar energy in Africa will tend not to be found within the equatorial and subequatorial climate zones, that are located in the western part of Central Africa usually near the equator but that extend as far north and south as the 8th or 9th parallel in both hemispheres, since they are systematically linked with almost permanent cloud cover and only intermittent bright sunshine. Therefore, countries that entirely lie in this wet-humid zone such as the Republic of the Congo, Equatorial Guinea, Gabon, Rwanda, Uganda, Burundi, Liberia, Sierra Leone and Senegal are by far the least favoured in solar power of all the continent and except for these eight quoted nations, each other African country experiences over 2,700 hours of bright sunshine on at least a part of its territory. Many perpetually sunny African nations like Egypt, Libya, Algeria, Niger, Sudan, South Africa and Namibia for instance could rely on developing their tremendous solar resources on a large scale thanks to the immense surface of their territory and at reduced prices.
South Africa is a leader in solar power in Africa with 1329 MW installed by 2016. Solar power in South Africa is rapidly growing. Several 75 MW PV plants and 2 CSP plants at 100 MW each were the largest in the country and among the largest in Africa. South Africa has announced a plan to install a minigrid on Robben Island; adding PV and battery storage is predicted by reduce diesel usage by half.
A 50 MW photovoltaic power plant is planned for Garissa in Kenya, a city located at the equator where the sun is said to shine for about 3,144 hours each year on average, and it is expected to produce approximately 76,473 MWh/year.
A 155 MW photovoltaic power plant is planned for Ghana and the government plans to increase solar power in the country from 22.5MW in 2017 to 300MW in 2020.
There are also many small-scale modular solar power installations being implemented across the continent at the village and household levels.
In 2015, Sub-Saharan Africa was the leading region for purchases of off-grid solar products.
Solar thermal power.
The Kingdom of Morocco’s solar plan, which is one of the world’s largest solar energy projects and estimated to cost about $9 billion, was introduced in November 2009 with the aim of establishing 2,000 MW of solar power by 2020. Five sites have been selected for the development of solar power plants combining a number of technologies including concentrated solar power, parabolic trough as well as photovoltaics, with the 500MW phase one solar power complex at Ouarzazate being the first to be developed. The first part of the 500MW project, the 160MW Noor I came online in 2016 and uses parabolic trough concentrated solar power technology. Morocco, the only African country to have a power cable link to Europe, aims to benefit from energy sales to Europe. One such initiative was Desertec.
South Africa has developed several solar thermal plants, both parabolic trough and power tower types. In 2017, it was the leading country in Africa for both solar thermal and PV solar energy.


RKM engine

The Rotary Piston Machine () is a proposed (still in development) form of machine. It can be used either to transform pressure into rotational motion (an engine), or the converse - rotational motion into pressure (pump). It is still in development, but has possible applications in fields requiring oil, fuel or water pumps, as well as pumps for non-abrasive fluids when moderate or high pressure is required. For instance: Hydraulics, fluid and gas transport systems, presses, fuel injection, irrigation, heating systems, hydraulic lifts, water jet engines, hydro- and pneumatic engines, and medical pumps. The machine's inventor is , along with co-inventors Lev B. Levitin and Naum Kruk.
Design.
All versions of the RKM incorporate a working chamber formed by smoothly conjugated circular arcs. The piston, shaped to conform to the chamber's walls, "jumps" from wall to wall, thus performing a rotary motion. The piston has an appropriately shaped aperture fitted with a gear structure, and this drives the power shaft (or two power shafts in some models).
The piston, its aperture and the working chamber of the RKMs represent, in their cross sections, multi-oval figures which, mathematically, are related to the class of figures of equal width. Those multi-ovals are non-analytical figures with a discontinuous second derivative of the contour line (the curvature). Hence, generally speaking, the trajectories of their centers of curvature are also non-analytical and, within the RKMs' geometry, have to have singular points.
In relation to the piston, the trajectory of the power shaft axis has corner points, which correspond to extreme positions of the piston as related to the working chamber. Those corners, which represent singular points of the power shaft's trajectory, cannot be avoided or rounded to provide for the kinematically closed functioning of the gear.
The reason why until now the geometry of curves of constant width could not be put to practical use in the gear design is that no conventional gear structure with the regular rolling on of the gears would permit the exact rolling-on of the singularities. The RKMs solve this problem by introducing the "inversely conjugated gear system", which makes it possible to have singular trajectories of the axes of rolling-on gears and, thus, allows the transfer of the angular momentum during the passage of the piston through its stop positions.
In simple words, the gear mechanism introduces corrections to the piston's motion, correcting the axis of rotation as it leaves the stop positions, so as to create a smooth motion.
Possible configurations.
In theory, there is no limit to the number of "sides" that a working chamber may have. However, in practice, it is likely that configurations incorporating no more than seven arcs will be used.
In addition, there can be either one or two power shafts in the aperture in the center of the piston.
Of course, the exact configuration of every model depends upon its use. For instance, internal combustion engines would include injection valves and after-burning chambers. These, however, are not part of the RKM concept.
Applications.
Potential areas of application for the RKM engines include:
One area where RKMs offer very high potential is in the pump market. RKM pumps can be as, or more efficient than today's preferred pump technologies, while offering overall advantages in pricing, size, reliability and energy efficiency.
Comparison to the Wankel engine.
Despite their apparent geometrical similarity, the RKM and the Wankel engine are quite different in design. The main similarities between them are the shape of the working chamber and the use of rotary motion.
However, there are many differences between the two. The Wankel engine working chamber is mobile while the RKM chamber is stationary. The axis of rotation in the Wankel engine moves in a circle while that of the RKM is fixed (in the single power shaft version, temporarily with two possible positions). In the RKM motor, the ignition takes place in a compact recess, while the Wankel's is in the work chamber itself. The RKM's sealing elements are in surface contact with the work chamber and pistons, as opposed to the Wankel's line contact. This makes for a number of advantages of the RKM motor over the Wankel:
One application that the two may indeed have in common is miniaturization. A miniature Wankel engine has been successfully constructed, and it stands to reason that the same can be done for an RKM.
Although developed in the 1960s, today there are no runnable RKM engine demonstrated.


Aquadag

Aquadag is a trade name for a water-based colloidal graphite coating commonly used in cathode ray tubes (CRTs). It is manufactured by Acheson Industries, a subsidiary of ICI. The name is a shortened form of "Aqueous Deflocculated Acheson Graphite", but has become a generic term for conductive graphite coatings used in vacuum tubes. Other related products include Oildag, Electrodag and Molydag. Deflocculation refers to the distribution of powdered high purity graphite in an aqueous solution containing approximately 2% to 10% by weight of various Tannic/Gallotannic acid variants and separating the colloidal graphite suspension from the remaining unsuspended graphite particulates. The product names are often printed with DAG in upper case (e.g. AquaDAG). It is used as an electrically conductive coating on insulating surfaces, and as a lubricant.
Properties.
Aquadag consists of a dispersion of colloidal graphite in distilled water. It is provided in concentrated paste form and is usually diluted with distilled water to a desired consistency before application. It can be applied by brushing, swabbing, spraying, or dipping, after which the surface is dried, leaving a layer of pure graphite.
After drying the coating is electrically conductive. Its resistance and other electrical properties vary with degree of dilution and application method. When diluted 1:1 and applied by brush its resistance is:
Use in cathode ray tubes.
A conductive aquadag coating applied to the inside of the glass envelope of cathode ray tubes, serves as a high-voltage electrode. The coating covers the inside walls of the "bell" of the CRT tube, from just inside the neck, and stops just short of the screen. Due to the graphite, it is electrically conductive and forms part of the high-voltage positive electrode, the second anode, which accelerates the electron beam. The second anode is a metal cylinder inside the neck of the tube, connected to a high positive voltage of 18 to 25 kilovolts. It has spring clips, which press against the walls of the tube, making contact with the aquadag coating so it also carries this high positive voltage. The electron beam from the electron gun in the neck of the tube is accelerated by the high voltage on the anode and passes through it to strike the screen.
The aquadag coating has two functions: it maintains a uniform electric field inside the tube near the screen, so the electron beam remains collimated and is not distorted by external fields, and it collects the electrons after they have hit the screen, serving as the return path for the cathode current. When the electron beam hits the screen, in addition to causing the fluorescent phosphor coating to give off light, it also knocks other electrons out of the surface. These "secondary electrons" are attracted to the high positive voltage of the coating and return through it to the anode power supply. Without the coating a negative space charge would develop near the screen, deflecting the electron beam. A typical value of beam current collected by the anode coating is 0.6 mA.
In some CRTs the aquadag coating performs a third function, as a filter capacitor for the high-voltage anode supply. A second conductive coating is applied to part of the outside of the tube facing the inside coating. This outside coating is connected to the ground side of the anode supply, thus the full anode voltage is applied between the coatings. The sandwich of the two coatings separated by the dielectric glass wall of the tube form a final capacitor to filter out ripple from the anode supply. Although the capacitance is small, around 500 pF, due to the low anode current it is sufficient to act as a filter capacitor.
In the television tube manufacturing industry, the manufacturing step that applies the aquadag is called "dagging".
Other uses.
Aside from its use in the production of CRTs, Aquadag is used in many types of high-voltage lab apparatus where a conductive coating is needed on an insulating surface. The surfaces of some metals (most notably aluminum) can develop nonconductive oxide layers, which tend to disrupt the electrostatic field produced around the surface of the metal when used as an electrode. Aquadag is not subject to such effects and provides a completely uniform equipotential surface for electrostatics.
Producers of continuous filament fiberglass will coat their product with Agadag when a conductive property is required.
Aquadag was also used in the production of some copper oxide rectifiers, to help make the ohmic connections to their counterelectrodes.
Other dags.
There are also deflocculated graphite products dispersed in liquids other than water. Acheson has extended the use of the dag brandname to non-graphite products e.g. the copper-based Electrodag 437 conductive paint.


Enneode


Columbus, Delaware and Marion Railway

The Columbus, Delaware and Marion Electric Company (originally Columbus, Delaware and Marion Railway Company) or CD&M was an interurban electric railroad that operated passenger and freight service in northern Ohio from 1903 to 1933.
Railroad and service.
The Columbus, Delaware and Marion Railway, or CD&M, provided interurban service connecting Columbus, Delaware, Marion, Worthington, and Bucyrus, Ohio.
It also provided local street car service in Marion and Delaware.
The CD&M provided local and interurban service on of track as The Columbus, Delaware and Marion Electric Railway Company. It operated service to Bucyrus through the Delaware, Marion and Bucyrus Railroad on an additional of track. At Bucyrus the railway met the Cleveland, Southwestern and Columbus Railway for connecting service to Cleveland.
The CD&M also generated electricity for Marion and sold power to the Middle West Utilities System. As a means of increasing off hours riders, the company developed Glenmary Park north of Worthington to attract interurban passengers with playing fields and picnic areas, and provided partial funding for Crystal Lake Amusement Park north of Marion, Ohio.
History.
The Columbus, Delaware, and Marion Railway was formed in 1901 to establish interurban service north of Columbus, Ohio. The CD&M Railway purchased the Columbus, Clinton and Worthington Street Railway. At the same time, a rival company, the Columbus, Delaware and Northern Railroad, acquired a right-of-way between Columbus and Marion. The CD&M Railway bought its rival and the railroad began interurban service in 1903. In October 1904, the CD&M incorporated as a holding company operating through its subsidiary the Columbus, Delaware, and Marion Electric Railroad.
In 1908, the company built the Columbus, Marion, and Bucyrus Railway to connect Columbus to the Cleveland, Southwestern and Columbus Railway at Bucyrus with plans for service to Cleveland, Sandusky, and Toledo.
The Columbus Marion and Bucyrus operated passenger service from Columbus to Bucyrus and nightly through freight service between Columbus and Cleveland.
In 1909, both the CD&M Railway Company and its Bucyrus subsidiary went bankrupt. The Columbus, Marion and Bucyrus emerged from bankruptcy in 1914, and in 1917, the CD&M was reorganized as the Columbus, Delaware and Marion Electric Company.
Decline and abandonment.
The Columbus, Marion and Bucyrus Railway lost money during the late 1920s. The railway went bankrupt in 1930 and was absorbed into Columbus, Delaware, and Marion in 1931.
In 1931, the Cleveland, Southwestern and Columbus Railway abandoned its rail lines, causing the CD&M to lose revenue from its Cleveland freight service in 1933
The company filed for bankruptcy in March 1933 and abandoned rail passenger service in August 1933. Passenger rail was replaced by bus service.
The CD&M Electric Company was merged with the Reserve Power Company to form Marion-Reserve Power Company in 1937.
The Ohio Railway Museum in Worthington operates on about one mile of former Columbus, Delaware and Marion right-of-way. The museum's collection includes a preserved CD&M parlor car numbered 501. Until 1969, another segment of CD&M track, leading to a power plant, was used in Marion.
Beginning in 2006, the Marion County Park District was working to establish a trail along the abandoned right of way.