Electricity sector in New Zealand

The electricity sector in New Zealand uses mainly renewable energy sources such as hydropower, geothermal power and increasingly wind energy. , 82% of energy for electricity generation is from renewable sources, making New Zealand one of the lowest carbon dioxide emitting countries in terms of electricity generation. Electricity demand has grown by an average of 2.1% per year from 1974 to 2010 but decreased by 1.2% from 2010 to 2013.
Regulation of the electricity market is the responsibility of the Electricity Authority (formerly the Electricity Commission). Electricity lines businesses, including Transpower and the distribution lines companies, are regulated by the Commerce Commission. Control is also exerted by the minister of energy in the New Zealand Cabinet, though the minister for state-owned enterprises and the minister for climate change also have some powers by virtue of their positions and policy influence in the government.
History.
In New Zealand electricity was first generated within factories for internal use. The first generation plant "where power left the building" was established at Bullendale in Otago in 1885, to provide power for a twenty stamp battery at the Phoenix mine. The plant used water from the nearby Skippers Creek, a tributary of the Shotover River.
Reefton on the West Coast became the first electrified town in 1888 after the Reefton Power Station was commissioned, while the first sizable power station was built for the Waihi gold mines at Horahora on the Waikato River. This set a precedent that was to dominate New Zealand's electricity generation, with hydropower becoming and remaining the dominant source. From 1912 to 1918 the Public Works Department issued licenses for many local power stations. By 1920, there were 55 public supplies, with 45 megawatts of generating capacity between them.
Early public electricity supplies used various voltage and current standards. The 230/400-volt 50-hertz three-phase system was chosen as the national standard in 1920. At the time, 58.6% of the country's generating capacity used the 50 Hz three-phase system; 27.1% used direct current systems while 14.3% used other alternating current standards.
While industrial use quickly took off, it was only government programmes in the first two-thirds of the 20th century that caused private demand to climb strongly as well. Rural areas were particular beneficiaries of subsidies for electrical grid systems, where supply was provided to create demand, with the intention of modernising the countryside. The results were notable – in the 1920s, electricity use increased at a rate of 22% per year. In fact, the 'load building' programmes were so successful that shortages started to occur from 1936 on, though a large number of new power stations built in the 1950s enabled supply to catch up again.
After the massive construction programmes had created a substantial supply of energy not dependent on international fossil fuel prices, New Zealand became less frugal with its energy use. While in 1978, its energy consumption (as expressed against economic output) hovered around the average of all OECD countries, during the 1980s New Zealand dropped far behind, increasing its energy use per economic unit by over 25%, while other nations slowly reduced their energy usage levels. Based on this economic comparison, in 1991 it was the second-least energy-efficient country out of 41 OECD countries.
All of the government's energy assets originally came under the Public Works Department. From 1946, the management of generation and transmission came under a new department, the State Hydro-Electric Department (SHD), renamed in 1958 as the New Zealand Electricity Department (NZED). In 1978, the Electricity Division of the Ministry of Energy assumed responsibility for electricity generation, transmission, policy advice and regulation. Distribution and retailing was the responsibility of local electric power boards (EPBs) or municipal electricity departments (MEDs).
New Zealand's electrical energy generation, previously state-owned as in most countries, was corporatised, deregulated and partly sold off over the last two decades of the twentieth century, following a model typical in the Western world. However, much of the generation and retail sectors, as well as the entire transmission sector, remains under government ownership as state-owned enterprises.
The Fourth Labour Government corporatised the Electricity Division as a State Owned Enterprise in 1987, as the Electricity Corporation of New Zealand (ECNZ), which traded for a period as Electricorp. The Fourth National Government went further with the Energy Companies Act 1992, requiring EPBs and MEDs to become commercial companies in charge of distribution and retailing.
In 1994, ECNZ's transmission business was split off as Transpower. In 1996, ECNZ was split again, with a new separate generation business, Contact Energy, being formed. The Fourth National Government privatised Contact Energy in 1999. From 1 April 1999, the remainder of ECNZ was split again, with the major assets formed into three new state-owned enterprises (Mighty River Power (now Mercury Energy), Genesis Energy and Meridian Energy) and with the minor assets being sold off. At the same time, local power companies were required to separate distribution and retailing, with the retail side of the business sold off, mainly to generation companies.
Organisation.
New Zealand's electricity sector is split into six distinct parts:
Regulation and policy.
Renewable energy sources provide much of the nation's electricity production, with the New Zealand energy industry for example reporting a 75% share in 2013. The Fifth Labour Government of New Zealand had the goal of increasing this to 90% by 2025, the subsequent Fifth National Government put priority on security of supply.
New Zealand's Labour government introduced a number of measures in the 2000s as part of the vision of New Zealand becoming carbon neutral by 2020, and intended to collect levies for greenhouse effect emissions from 2010 onwards, to be added to power prices depending on the level of emissions. However, the incoming National government quickly tabled legislation to repeal various of these measures, such as obligatory targets for biofuel percentages, a ban on construction of new fossil fueled generation plants and a ban on future sales of incandescent light bulbs.
On 1 January 2010, the energy sector was required to report greenhouse gas emissions under the New Zealand Emissions Trading Scheme (NZETS). From 1 July 2010, the energy sector had formal compliance obligations to buy and surrender one emission unit for every two tonnes of reported emissions. As of December 2011, there were 78 energy firms compulsorily registered in the NZETS and five voluntary participants. Energy sector firms in the NZETS do not receive a free allocation of emissions units and they are expected to pass on to their customers the costs of buying emission units.
In April 2013, the Labour Party and the Green Party said if they were to win the 2014 general election, they would introduce a single buyer of electricity akin to Pharmac (the single buyer of pharmaceutical drugs in New Zealand), in order to cut retail costs. The Government responded by calling it "economic vandalism", comparing it to the Soviet Union, but Greens co-leader Russel Norman said it would boost the economy and create jobs. By the following day, shares in privately owned power company Contact Energy had fallen by more than 10 percent.
Electricity market.
Electricity is traded at a wholesale level in a spot market.
The market operation is managed by several service providers under agreements with the Electricity Authority. The physical operation of the market is managed by Transpower in its role as System Operator.
Generators submit offers (bids) through a Wholesale Information and Trading System (WITS). Each offer covers a future half-hour period (called a trading period) and is an offer to generate a specified quantity at that time in return for a nominated price. The System Operator (Transpower) uses a scheduling, pricing and dispatch (SPD) system to rank offers, submitted through WITS, in order of price, and selects the lowest-cost combination of offers (bids) to satisfy demand.
The market pricing principle is known as bid-based security-constrained economic dispatch with nodal prices.
The highest-priced bid offered by a generator required to meet demand for a given half-hour sets the spot price for that trading period.
Electricity spot prices can vary significantly across trading periods, reflecting factors such as changing demand (e.g. lower prices in summer when demand is subdued) and supply (e.g. higher prices when hydro lakes and inflows are below average). Spot prices can also vary significantly across locations, reflecting electrical losses and constraints on the transmission system (e.g. higher prices in locations further from generating stations).
Generation.
In 2017, New Zealand generated 42,911 gigawatt-hours (GWh) of electricity with hydroelectricity making up just over half of this. The installed generating capacity of New Zealand (all sources) as of December 2017 was 9,237 megawatts (MW), with hydroelectricity, natural gas, geothermal, wind, coal, oil, and other sources (mainly biogas, waste heat and wood) featuring. Note that some power stations can use more than one fuel, so their capacity (see below table) has been split in line with the amount of electricity generated by each fuel.
Comparing the two main islands, nearly all South Island's electricity is generated by hydroelectricity – 98% in 2014. The North Island has a wider spread of generation sources with geothermal, natural gas and hydroelectricity all generating a share of between 20–30% each in 2014.
Hydro.
Hydroelectric power stations generate the majority of New Zealand's electricity, with 22,815 GWh generated by hydroelectricity in 2013 – 55 percent of New Zealand's electricity generated that year. The total hydroelectricity installed capacity is 5,262 MW. The South Island is heavily reliant on hydroelectricity, with 98% of its electricity generated by hydroelectricity in 2013.
There are three major hydroelectric schemes in the South Island: Waitaki, Clutha and Manapouri. Waitaki has three distinct parts – the original Waitaki and Tekapo A powerhouses (1936 and 1951 respectively), the 1960s Lower Waitaki development consisting of Benmore and Aviemore, and the 1970–80s Upper Waitaki development of Tekapo B and Ohau A, B, and C. In total, the nine powerhouses generate approximately 7600 GWh annually, around 18% of New Zealand's electricity generation and more than 30% of all its hydroelectricity. Manapouri Power Station is a single underground power station in Fiordland, and the largest hydroelectric station in the country. It generates 730 MW of electricity and produces 4800 GWh annually, mainly for the Tiwai Point aluminium smelter near Invercargill. Both Waitaki and Manapouri are operated by Meridian Energy. The Clutha River scheme is operated by Contact Energy, and consists of two powerhouses: Clyde Dam (464 MW, commissioned 1992) and Roxburgh Dam (320 MW, commissioned 1962).
The North Island has two major schemes: Tongariro and Waikato. The Tongariro Power Scheme consists of water taken from the catchments of the Whangaehu, Rangitikei, Whanganui and Tongariro Rivers passing through two powerhouses (Tokaanu and Rangipo) before being deposited in Lake Taupo. The scheme is operated by Genesis Energy and has an installed capacity of 360 MW. The Waikato River Scheme, operated by Mercury Energy, consists of nine powerhouses on the river between Lake Taupo and Hamilton, generating 3650 GWh annually.
Other smaller hydroelectricity facilities and schemes are scattered around both islands of mainland New Zealand.
Hydroelectric schemes have largely shaped hinterland New Zealand. Towns including Mangakino, Turangi, Twizel and Otematata originally were founded for workers on the construction of hydroelectric schemes and their families. The hydroelectric reservoirs of Lake Ruataniwha and Lake Karapiro are world-class rowing venues, with the latter having hosted the 1978 and the 2010 World Rowing Championships. Other schemes have shaped political New Zealand. In the 1970s, the original plans to raise Lake Manapouri for the Manapouri station were scrapped after major protests. Later in the 1980s, protests were made against the creation of Lake Dunstan behind the Clyde Dam, which would flood the Cromwell Gorge and part of Cromwell township, destroying many fruit orchards and the main street of Cromwell. However, the project was given the go ahead and Lake Dunstan was filled in 1992–93.
Hydroelectricity generation has remained relatively steady since 1993 – the only major hydroelectricity projects since then was the completion of the second Manapouri tailrace tunnel in 2002, increasing the station from 585 MW to 750 MW, and due to resource consent the station increases further to 800 MW. No major new hydroelectric projects have been committed as of December 2011, but there are proposals for further developments on the Waitaki and Clutha Rivers, and on the West Coast of the South Island.
Geothermal.
New Zealand lies on the Pacific Ring of Fire, creating favourable geological conditions for the exploitation of geothermal power. Geothermal fields have been located across New Zealand, but at present, most geothermal power is generated within the Taupo Volcanic Zone – an area in the North Island stretching from Mount Ruapehu in the south to White Island in the north. As at December 2012, the installed capacity of geothermal power was 723 MW, and in 2013, geothermal generated 6,053 GWh of electricity – 15% of the country's electricity generation that year.
The majority of New Zealand's geothermal power is generated north of Lake Taupo. Eight stations generate electricity here, including Wairakei Power Station, New Zealand's oldest (1958) and largest (176 MW) geothermal power station, and the world's second large-scale geothermal power facility. Also in this area are Nga Awa Purua, which is home to the world's largest geothermal turbine at 147 MW (although the plant only generates 140 MW); and Ohaaki, which has a 105-metre tall hyperboloid natural draft cooling tower: the only one of its kind in New Zealand. A significant amount of geothermal electricity is also generated near Kawerau in the eastern Bay of Plenty, and a small amount is generated near Kaikohe in Northland.
Much of New Zealand's geothermal power potential still lies untapped, with the New Zealand Geothermal Association estimating an installation capacity (using only existing technology) of around 3,600 MW.
Wind.
According to a 2018 report published by the New Zealand government, wind generation provided 5% of the electricity supply for 2017. This was down from 7% in 2016 and 9% in 2015. As of 2018, wind power accounts for 690 MW of installed capacity. Consents have been granted for wind farms with a further capacity of 2,500 MW.
New Zealand has abundant wind resources. The country is in the path of the Roaring Forties, strong and constant westerly winds, and the funneling effect of Cook Strait and the Manawatu Gorge increase the resource's potential.
These effects make the Lower North Island the main region for wind generation.
About 70 percent of the nation's current installed capacity lies within this region, with some turbines have a capacity factor of over 50 percent in this area.
Electricity was first generated by wind in New Zealand in 1993, by a 225 kW demonstration turbine in the Wellington suburb of Brooklyn. The first commercial wind farm was established in 1996 – the Hau Nui Wind Farm, 22 km southeast of Martinborough had seven turbines and generated 3.85 MW. The Tararua Wind Farm was first commissioned in 1999 with 32 MW of generating capacity, gradually expanding over the next eight years to 161 MW – the largest wind farm in New Zealand. Other major wind farms include Te Apiti, West Wind and White Hill.
Wind power in New Zealand shares the difficulties typical to other nations (uneven wind strengths, ideal locations often remote from power demand areas). New Zealand wind farms provide on average a 45% capacity factor (in other words, wind farms in New Zealand can produce more than double their average energy during periods of maximum useful wind strengths). The Tararua Wind Farm averages slightly more than this. The New Zealand Energy Efficiency and Conservation Authority figures indicate that wind power is also expected to operate at maximum capacity for around 4,000 hours a year, much more than for example the approximately 2,000 hours (Germany) to 3,000 hours (Scotland, Wales, Western Ireland) found in European countries.
Fossil fuels.
Fossil fuels, specifically coal, oil and gas, produced 10,383 GWh of electricity in 2013 – 25% of all electricity generated that year. This was split into 8,143 GWh by gas, 2,238 GWh by coal, and 3 GWh by oil. Total combined installed capacity in 2012 was 2,974 MW. The North Island generates nearly all of New Zealand's fossil-fuelled electricity.
Up until the 1950s, fossil-fuelled stations were small-scale and usually fuelled by coal or coal by-products, providing electricity to cities yet to be connected to hydro schemes and to provide additional support to such schemes. Large-scale coal-fired generation came in 1958 with the establishment of the 210 MW Meremere Power Station. Oil-fired stations such as Otahuhu A, Marsden A&B, and New Plymouth were commissioned in the late 1960s and early 1970s. The discovery of natural gas off the Taranaki coast, and the oil crises of the 1970s, saw oil-fueled stations converted to gas operation or mothballed, while gas-fired stations proliferated, especially in Taranaki and Auckland, well into the 2000s. Only in recent years has coal made a comeback, as Taranaki gas has slowly depleted.
Today, there are three major fossil-fuelled stations in New Zealand. Smaller gas- and coal-fuelled industrial generators are found across New Zealand and especially in Auckland, Waikato, Bay of Plenty, and Taranaki. Genesis Energy's Huntly Power Station in northern Waikato is New Zealand's largest power station – with 1000 MW of coal- and gas-fired generators and 435 MW of gas only generators, it supplies around 17% of the country's electricity. A gas-fired power station exists in Taranaki at Stratford (585 MW). Whirinaki is a 155 MW diesel-fired station north of Napier, providing backup generation for periods when generation is not otherwise available, such as when plants break down, or during dry seasons where there is limited water available for hydroelectricity generation.
Diesel-fuelled generation using internal combustion engines is popular in hinterland New Zealand where the national network doesn't reach, such as on offshore islands, alpine huts, sparsely populated areas and isolated homes and farm sheds. Diesel fuel suitable for generators is readily available across the country at petrol stations – diesel is not taxed at the petrol pump in New Zealand, and instead diesel-powered vehicles pay Road User Charges based on their gross tonnage and distance travelled.
As of 2012 none of the power generators appear to be committed to the construction of any new fossil-fuelled power stations. However, for several years there have been two unactioned but reasonably well defined proposals for gas-fired power stations with 880 MW of generating capacity in the Auckland area. Both the proposed Rodney Power Station (Genesis Energy) near Helensville and the proposed Otahuhu Power Station C plant (Contact Energy) have resource consents.
Other sources.
Solar.
As of January 2019 the installed solar generation capacity of 90.1MW represented just 1% of New Zealand generation capacity.
Marine.
New Zealand has large ocean energy resources but does not yet generate any power from them. TVNZ reported in 2007 that over 20 wave and tidal power projects are currently under development. However, not a lot of public information is available about these projects. The Aotearoa Wave and Tidal Energy Association was established in 2006 to "promote the uptake of marine energy in New Zealand". According to their latest newsletter, they have 59 members. However the association doesn't list these members or provide any details of projects.
From 2008 to 2011, the government Energy Efficiency and Conservation Authority allocated $2 million each year from a Marine Energy Deployment Fund, set up to encourage the utilisation of this resource.
The greater Cook Strait and Kaipara Harbour seem to offer the most promising sites for using underwater turbines. Two resource consents have been granted for pilot projects in Cook Strait itself and in the Tory Channel, and consent has been granted for up to 200 tidal turbines at the Kaipara Tidal Power Station. Other potential locations include the Manukau and Hokianga Harbours, and French Pass. The harbours produce currents up to 6 knots with tidal flows up to 100,000 cubic metres a second. These tidal volumes are 12 times greater than the flows in the largest New Zealand rivers.
Nuclear.
Although New Zealand has nuclear-free legislation, it covers only nuclear-propelled ships, nuclear explosive devices and radioactive waste. The legislation does not prohibit the building and operation of a nuclear power station.
The only significant proposal for a nuclear power station in New Zealand was the Oyster Point Power Station, on the Kaipara Harbour near Kaukapakapa north of Auckland. Between 1968 and 1972, there were plans to develop four 250 MW reactors at the site. By 1972, the plans were dropped as the discovery of the Maui gas field meant there was no immediate need to embark on a nuclear programme. Since 1976, the idea of nuclear power, especially in the Auckland region, has popped up from time to time, but there are no definite plans.
Transmission.
New Zealand's national electricity transmission grid connects its generating facilities to its demand centres, which are often more than from each other. The national grid is owned, operated and maintained by state-owned enterprise Transpower New Zealand. The grid contains of high-voltage lines and 178 substations.
The first major transmission lines were built in 1913–14, connecting the Horahora hydro station to Waikino, and Coleridge hydro station with Addington in Christchurch. The interwar years saw the first major construction of a national network of 110 kV lines connecting towns and cities to hydroelectric schemes. By 1940, the transmission network stretched from Whangarei to Wellington in the North Island, and Christchurch to Greymouth and Invercargill in the South Island. Nelson and Marlborough, the last regions, joined the national grid in 1955. The 220 kV network began in the early 1950s, connecting the Waikato River dams to Auckland and Wellington, and Roxburgh Dam to Christchurch. The two islands were joined together by the HVDC Inter-Island link in 1965. The first 400 kV transmission line was completed between Whakamaru Dam on the Waikato River and Brownhill substation east of Auckland in 2012, but presently is operated at 220 kV.
Existing grid.
The backbone of the grid in each island is the network of 220 kV transmission lines. These lines connect the larger cities and power users with the major power stations. Lower capacity 110 kV, 66 kV and 50 kV transmission lines connect smaller towns and cities and smaller power stations, and are connected to the 220 kV core grid through points of interconnection at major transmission substations. These stations include Otahuhu and Penrose in Auckland, Whakamaru, Wairakei and Bunnythorpe in the central North Island, Haywards in Wellington, Islington and Bromley in Christchurch, and Twizel and Benmore in the Waitaki Valley.
The grid today has ageing infrastructure, and increasing demand is placing significant loads on some parts of the network. Transpower is currently upgrading existing lines and substations to ensure supply security.
Investments in new transmission are now regulated by the Commerce Commission. In a news release in January 2012, the Commerce Commission reported that Transpower was planning to invest $5 billion over the next 10 years in upgrades of critical infrastructure.
Since 2006, Transpower has spent nearly $2 billion reinforcing the supply into and around Auckland. A 400 kV-capable transmission line was completed in 2012, linking Whakamaru to Brownhill substation in Whitford, east of Auckland, with 220 kV cables linking Brownhill to Pakuranga. In 2014, a new 220 kV cable was commissioned between Pakuranga and Albany (via Penrose, Hobson Street and Wairau Road), forming a second high-voltage route between northern and southern Auckland.
HVDC Inter-Island.
The HVDC Inter-Island scheme is New Zealand's only high voltage direct current (HVDC) system, and links the North and South Island grids together.
The link connects the South Island converter station at the Benmore Dam in southern Canterbury with the North Island converter station at Haywards substation in the Hutt Valley via a 610 km long overhead bipolar HVDC line with submarine cables across Cook Strait.
The HVDC link was commissioned in 1965 as a ±250 kV, 600 MW bipolar HVDC scheme using mercury-arc valve converters, and was originally designed to transfer surplus South Island hydroelectric power northwards to the more populous North Island. In 1976, the control system of the original scheme was modified to allow power to be sent in the reverse direction, from Haywards to Benmore.
The HVDC link provides North Island consumers with access to the South Island's large hydro generation capacity, which may be important for the North Island during peak winter periods. For South Island consumers, the HVDC link provides access to the North Island's thermal generation capacity, which is important for the South Island during dry periods. Without the HVDC link, more generation would be needed in both the North and South Islands. In addition, the HVDC link is essential for the electricity market, as it allows generators in the North and South Islands to compete, putting downward pressure on prices and minimising the need to invest in costly new generating stations. The HVDC link also plays an important part in allowing renewable energy sources to be managed between the two islands.
In 1992, the original mercury-arc equipment was paralleled to create a single pole (Pole 1), and a new thyristor-based pole (Pole 2) was commissioned alongside it. The transmission lines and submarine cables were also upgraded to double the link's maximum capacity to 1240 MW. The mercury-arc valve converter equipment was partially decommissioned in 2007, and fully decommissioned in August 2012. New thyristor converter stations (known as Pole 3) were commissioned on 30 May 2013 to replace the mercury arc converters. Further work to Pole 2 brought the link's capacity to 1200 MW by the end of the year.
Distribution.
Electricity from Transpower's national grid is distributed to local lines companies and large industrial users via 180 grid exit points (GXPs) at 147 locations. Large industrial companies, such as New Zealand Steel at Glenbrook, the Tasman Pulp and Paper Mill at Kawerau, and the Tiwai Point Aluminium Smelter near Bluff, draw directly from Transpower substations and not the local lines companies' local grids.
Distribution of electricity to local consumers is the responsibility of one of 29 local line companies. Each company supplies electricity to a set geographic area based on the grid exit points they draw from.
The line companies are:
In most areas, the local lines company operates a subtransmission network, connecting the GXP to zone substations. At the zone substation (or at the GXP if there is no subtransmission network), the voltage is stepped down to distribution voltage. Three-phase distribution is available in all urban and most rural areas. Single- or two-phase distribution utilising only two phases or single wire earth return systems are used in outlying and remote rural areas with light loads. Local pole-mounted or ground-mounted distribution transformers step-down the electricity from distribution voltage to the New Zealand mains voltage of 230/400 volts (phase-to-earth/phase-to-phase) for use in homes and businesses.
Subtransmission is typically at 33 kV, 50 kV, 66 kV or 110 kV, although parts of Auckland isthmus use 22 kV subtransmission. Distribution is typically at 11 kV, although some rural areas and high-density urban areas use 22 kV distribution, and some urban areas (e.g. Dunedin) use 6.6 kV distribution.
Isolated areas.
New Zealand's national electricity network covers the majority of both the North and South Islands. There are also a number of offshore islands which are connected to the national grid. Waiheke Island, New Zealand's most populous offshore island, is supplied electricity via submarine cables between Maraetai and the island. Arapaoa Island and d'Urville Island, both in the Marlborough Sounds, are supplied via overhead spans across Tory Channel and French Pass respectively.
However, many offshore islands and some parts of the South Island are not connected to the national grid and operate independent generation systems, mainly due to the difficulty of building lines from other areas. These places include:
Many other schemes exist on offshore islands that have permanent or temporary habitation, mostly generators or small renewable systems. An example is the ranger / research station on Little Barrier Island, where twenty 175 watt photovoltaic panels provide the mainstay for local needs, with a diesel generator for backup.
Consumption.
In 2017, New Zealand consumed a total of 39,442 GWh of electricity. Industrial consumption made up 37% of that figure, agricultural consumption made up 6%, commercial consumption made up 24%, and residential consumption made up 31%. There were just over 1,964,000 connections to the national electricity network in 2014, with 87% being residential connections.
New Zealand's largest single electricity user is the Tiwai Point Aluminium Smelter in Southland, which can demand up to 640 megawatts of power, and annually consumes around 5400 GWh. The smelter effectively has the Manapouri power station as a dedicated power generator to supply it. Other large industrial users include the Tasman pulp and paper mill at Kawerau (175 MW demand), and New Zealand Steel's Glenbrook mill (116 MW demand).
The other major consumers are the cities, with Auckland, the nation's largest city, demanding up to 1722 MW and consuming 8679 GWh in 2010–11. Wellington, Christchurch, Hamilton and Dunedin are also major consumers, with other large demand centres including Whangarei-Marsden Point, Tauranga, New Plymouth, Napier-Hastings, Palmerston North, Nelson, Ashburton, Timaru-Temuka, and Invercargill.


Gregory Minor

Gregory Charles Minor was one of three American middle-management engineers (known as the GE Three) who resigned from the General Electric nuclear reactor division in 1976 to protest against the use of nuclear power in the United States. A native of Fresno, California, Minor received a BS degree in electrical engineering from the University of California in 1960. He gained an MS degree at Stanford University in 1966. He began working for G.E. in 1960 and died of leukemia in 1999.
All three of the engineers were members of the Creative Initiative Foundation, a California group that "seeks to strengthen human relations" and "change the world for the better". The engineers' resignations were coordinated by another CIF member, who helped them orchestrate the announcement for maximum effect.
Gregory Minor said that he had developed "a deep conviction that nuclear reactors and nuclear weapons now present a serious danger to the future of all life on this planet".


Tata Power

Tata Power Limited is an Indian electric utility company based in Mumbai, Maharashtra, India and is part of the Tata Group. The core business of the company is to generate, transmit and distribute electricity. With an installed electricity generation capacity of 10,577 MW, it is India's largest integrated power company. Tata Power has been ranked 3rd in 2017 Responsible Business Rankings developed by IIM Udaipur. In February 2017, Tata Power became the first Indian company to ship over 1 GW solar modules.
History.
The firm started as the Tata Hydroelectric Power Supply Company in 1910, which amalgamated with the Andhra Valley Power Supply Company in 1916. It commissioned India's Second hydro-electric project in 1915 in Khopoli for 72 MW. Then second and third power plants were installed in Bhivpuri (75 MW) in 1919 and Bhira (300 MW) in 1922.
Operations.
Tata Power has operations in India, Singapore, Indonesia, South Africa and Bhutan. Tata Power Group has its operations based in 35 locations in India.The thermal power stations of the company are located at Trombay in Mumbai, Mundra in Gujarat, Jojobera and Maithon in Jharkhand, Kalinganagar in Odisha, Haldia in West Bengal and Belgaum in Karnataka. The hydro stations are located in the Western Ghats of Maharashtra and the wind farms in Ahmednagar, Supa, Khanke, Brahmanwel, Gadag, Samana and Visapur. The company installed India's first 500 MW unit at Trombay, the first 150 MW pumped storage unit at Bhira, and a flue gas desulphurization plant for pollution control at Trombay. It has generation capacities in the States of Jharkhand and Karnataka, and a distribution company in Delhi, servicing over one million consumers spread over 510 square km in the North Delhi. The peak load in this area is about 1,150 MW. Tata Power announced on 24 July 2012, commissioning of the second unit of 525 MW capacity of the Maithon mega thermal project in Dhanbad. The first unit of identical capacity was commissioned in September 2011.
International operations.
The company has executed overseas projects in the Middle East, Africa and South East Asia including the Jebel Ali 'G' station (4×100 MW + desalination plant) in Dubai, Al-Khobar II (5×150 MW + desalination plant) and Jeddah III (4×64 MW + desalination plant) in Saudi Arabia, Shuwaikh (5×50 MW) in Kuwait, EHV substations in UAE and Algeria, and power plant operation and maintenance contracts in Iran and Saudi Arabia.
Tata Power has a Russian subsidiary, Far Eastern Natural Resources LLC, that has a license for a coal mine in Kamchatka Krai.
Strategic Engineering Division.
The firm's Strategic Engineering Division (SED) has engaged in defence systems and engineering for over four decades. It works with the MoD and laboratories to provide products and solutions for the defence requirements of the country.
It has already cleared the Joint Receipt Inspection (JRI) for the first two lots of Pinaka launchers and command posts; the third and fourth lots have successfully undergone factory acceptance tests. Tata Power's Strategic Electronics Division won a tightly contested Rs. 1,000-crore contract for modernising 30 Indian Air Force airbases.
Problems.
In cause of dramatically higher coal prices as assumed in the plannings and a fixed price arrangement the Mundra plant in 2012 made big losses. After three successive years of losses as a result, cash flow was becoming an issue for the company. In January 2014 the company sold a 30 percent stake in Indonesian coal company PT Arutmin for $500 million. In July 2014 it signed an option to sell a 5 percent stake in Indonesian coal company Kaltim Prima Coal for $250 million.
Future projects.
Tata Power has a 51:49 joint venture with PowerGrid Corporation of India for the Tata transmission project, India's first transmission project executed with public-private partnership financing.
Tata Power has plans to expand generation capacity of 4,000 MW Mundra plant, the country's first operational ultra mega power project, to 5,600 MW.
The company has also a 74:26 joint venture with Damodar Valley Corporation for 1,050 MW coal-based thermal power plant at Maithon in Dhanbad district of Jharkhand, named as Maithon Power Limited. The both units are commissioned on 24 July 2012. It has another a 74:26 joint venture with Tata Steel Limited for thermal power plants to meet the captive requirements of Tata Steel, under name Industrial Energy Limited.
Tata Power has announced its partnership with Sunengy an Australian firm to build India's first floating solar plant based on Liquid Solar Array technology.
In 2016, Tata Power made significant inroads into the renewable energy market in India by means of its acquisition of Welspun Renewables, for a record price of $1.3 billion, the largest acquisition in the Indian renewables sector.
Tata Power bagged a 25-year licence for distribution and retail supply of electricity in Odisha's five circles, together constituting Central Electricity Supply Utility of Odisha (CESU) for about Rs 175 crore.
Shareholding.
As on 15 November 2017, Tata Group held 32.47% shares in Tata Power. Around 210,000 individual shareholders hold approx. 14% of its shares. Life Insurance Corporation of India is the largest non-promoter shareholder in the company with 12.90% shareholding.
The equity shares of Tata Power are listed on the Bombay Stock Exchange, where it is a constituent of the BSE SENSEX index, and the National Stock Exchange of India, where it is a constituent of the NIFTY 50.Its Global Depository Receipts (GDRs) are listed on the London Stock Exchange and the Luxembourg Stock Exchange.


Sakuma Dam

The is a dam on the Tenryū River, located on the border of Toyone, Kitashitara District, Aichi Prefecture on the island of Honshū, Japan. It is one of the tallest dams in Japan and supports a 350 MW hydroelectric power station. Nearby a frequency converter station is installed, allowing interchange of power between Japan's 50 Hz and 60 Hz AC networks.
History.
The potential of the Tenryū River valley for hydroelectric power development was realized by the Meiji government at the start of the 20th century. The Tenryū River was characterized by a high volume of flow and a fast current. Its mountainous upper reaches and tributaries were areas of steep valleys and abundant rainfall, and were sparsely populated. However, the bulk of investment in hydroelectric power generation in the region was centered on the Ōi River, and it was not until the Taishō period that development began on the Tenryū River. Private entrepreneur Fukuzawa Momosuke founded the , which later became before it was nationalized into the pre-war government monopoly in 1938. The first dam on the main stream of the Tenryu River, the Yasuoka Dam was completed in 1935. This was followed by the Iwakura Dam in 1938. The Hiraoka Dam was started in 1938, but not completed until 1951 due to the start of World War II.
After the end of World War II, the American occupation authorities ordered the dissolution of Nippon Hassoden, which was divided into regional power companies. Central Japan came under Chubu Electric Power, which inherited the various dams and projects on the Tenryū River, all of which were located in Nagano Prefecture. To tap into the hydroelectric potential of the river in Shizuoka Prefecture, the government turned to the Electric Power Development Company. The new company, in part through foreign aid loans from the United Nations, began work on a new dam in 1952, based on plans which had begun as early as 1921. The main contractor for the project was Hazama Corporation, and construction was completed in 1956. Construction was facilitated by the steep V-shaped walls of the site, and its proximity to the Iida Line train (several stations of which had to be relocated once the reservoir began to fill. Construction also involved the relocation of 240 households with 296 families. The official opening ceremonies on October 28, 1957 were attended by Emperor Hirohito and Empress Kojun and was the occasion for the issuance of a commemorative postage stamp.
Design.
Sakuma Dam is a hollow-core concrete gravity dam with several central spillways. It supplies water to both the Sakuma Hydroelectric Power Station and serves as the lower reservoir for the Shin-Toyone Hydroelectric Power Station, with a rated capacity of 350,000 kW and 1,200,000 kW respectively.
Surroundings.
The Sakuma Dam Reservoir is a popular attraction for canoeing and camping, due to its proximity to downtown Hamamatsu and ease of access. The surrounding area is part of the Tenryū-Okumikawa Quasi-National Park.
HVDC frequency converter.
The western part of Japan uses 60 Hz and the eastern part uses 50 Hz as power grid frequency. In 1965 an HVDC back-to-back station was installed about 1 kilometre southwest of the power plant (). It was rated 300 MW with an operating voltage of ±125 kV. The converter station is connected to the 275 kV 50 Hz grid and the 275 kV level of the 60 Hz grid. Initially the converter used mercury arc valves manufactured by ASEA. In 1993 it was converted to use light triggered thyristors, which were installed in the same valve hall that had contained the mercury arc valves.
Each inverter consists of two series-connected six pulse inverters forming a twelve pulse inverter. As in many other HVDC facilities, quadrivalves (serial connections of four valves forming a unit) are used. Each valve consists of 7 series-connected thyristors designed for a current of 2,500 A and a blocking voltage of 6 kV. Each of the two inverters uses 84 thyristors.
The station has three transformers on the 60 Hz side. One transformer is the power supply of the station, and two 275 kV/55 kV transformers feed the valves. The transformers have their low-voltage windings connected one in a delta and other in a wye. All these transformers share a common tank. On the 50 Hz side, two 275/54 kV transformers, in separate tanks, feed the valves, again with one in delta and the other in star connection of the low-voltage windings.
The DC smoothing reactor has an inductance of 0.12 H and is designed for a current of 2,400 A.
On each side filters for the 5th, 7th, 11th and 13th harmonic exist, which consist of a series connection of a capacitor, an inductor and a resistor. In addition, a high pass filter is used, which consists of a capacitor switched in series with a coil to which a resistor is switched in parallel.


UniSource Energy Services

UniSource Energy Services is an electric and natural gas utility company serving Arizona in the United States. It is a subsidiary of Fortis.
W. B. Foshay Co., a predecessor of Citizens Communications, acquired Southern Arizona Power of Nogales and Desert Power and Water of Kingman in 1927.
In 2003, UniSource Energy (later UNS) acquired Citizen's Arizona gas and electric operations in 2003 and renamed them UniSource Energy Services. In 2013, Fortis announced its acquisition of UNS.


Wolmirstedt substation

Wolmirstedt substation is a large node in the power grid of former East Germany and termination of Germany's longest powerline, running from Lubmin nuclear power station to Wolmirstedt substation.
Via Wolmirstedt substation the first power exchange between both parts of Germany took place. On October 3, 1989, the 380 kV powerline between Helmstedt and Wolmirstedt substation went in service. This line was the first section of the 380 kV powerline between former West Germany and former West-Berlin, which went in service in 1994, one year later as planned in the mid 1980s.
As power grids between former GDR and former West Germany were not synchronized until 1993, power exchange between both systems were much limited.
In order to allow a full power exchange already in the 1980s the construction of an HVDC-back-to-back station at Wolmirstedt was planned. At the beginning of 1989 construction work on this facility, whose inauguration was planned in 1992, started. However it was decided after opening of Inter-German Border to synchronize the power grids of East- and West-Germany, in order not to require expensive HVDC systems with their limiting transmission rate.
For this reason construction work on Wolmirstedt HVDC-back-to-back station, which was designed to allow a maximum power exchange of 600 MW by using a DC voltage of 160 kV, was stopped in April 1990.
At this time of point the static inverter hall, situated at 52°16'21" N and 11°38'10" E, was already built. Also an earth wall for the protection of the inhabitants of Mose, an urban part of Wolmirstedt, and the road equipped with a rail running to Wolmirstedt substation for delivering the electrical equipment was already completed.
In opposite to the HVDC-back-to-back facilities in Etzenricht, Dürnrohr and Vienna, which were on both sites connected to the corresponding 380 kV-grids, it was planned at Wolmirstedt HVDC back-to-back plant only to realize the connection to the West German powergrid on the 380 kV-level. The link to the East German power grid was planned to be realized on the 220 kV-level as the grid for this voltage level was in former Eastern Germany at those days much stronger than that of the 380 kV-level.
The static inverter hall was, because of its noise protection wall, sold after termination of construction work to a company doing glass recycling and is today part of Farsleben Recycling Yard.
The components designed for the realization of Wolmirstedt HVDC back-to-back station were - except of the inverter transformers planned for the connection of the inverter to the East German 220 kV-grid, for which no demand existed and were scrapped afterwards - used at Etzenricht HVDC-back-to-back station.


Victorian Model Solar Vehicle Challenge

The Victorian Model Solar Vehicle Challenge is a competition held annually at Scienceworks in Melbourne, Australia. The challenge gives school age children a chance to design and build a car or boat, and more recently a Mars Rover, that operates solely on solar power. It is run by MSV, a voluntary organisation created to administer the challenge.
History.
A solar car challenge for schools' was first thought of in 1987 during the first World Solar Challenge. Everyone who attended—car makers, staff and students from universities and secondary schools—believed it to be a great experience. Two men, Paul Wellington (teacher at Chisholm Institute of Technology, part of Monash University), and Ted Mellor (Warragul Technical School), felt that such an opportunity should be available to a wider range of students, because at the time, the high cost of making a life-size solar car meant that only rich schools could afford it. Thus, it was decided that a competition for model solar cars would be created; model cars being much cheaper and less time-consuming to make than life-size cars, but still requiring the same amount of thought and skill. Paul and Ted assembled a team of science and technology teachers, curriculum developers, sponsors, representatives and former World Solar Challenge team members (today known as MSV), and with the financial support of Energy Victoria, they established a Model Solar Car Challenge in Victoria. The first race was run in May 1990, at the Exhibition Buildings in Melbourne.
Sponsors.
The Sponsors of the event past and present are:


833A

The 833A is a vacuum tube constructed for medium power oscillator or class B or C amplifier applications. It is a medium-mu power triode with 300 watts CCS or 350 watts ICAS anode dissipation. The long grid and anode leads, plus high internal capacitance, limits this tube to 15-30 MHz maximum frequency. Being medium mu, it is normally not suitable for grounded grid operation.
Specifications.
The 833A is a large tube of the type sometimes known as a "cookie jar" tube, with the envelope nominally measuring 116.8 mm (4.60 in.) in diameter and 219.2 mm (8.63 in.) in height. The 833A contains a thoriated tungsten filament rated at 10 volts and 10 amps. A pair of 833A's with adequate forced air cooling can deliver 1000 watts of CCS RF power operating as a class C amplifier plate modulated stage.
A pair of tubes used in a class B modulator can deliver 1800 watts of "peak" AF power in ICAS service with speech, or 1600 watts in CCS service with music or high duty cycle operation. Two 833A's are capable of approximately 800 watts sine wave power in a class B audio amplifier or modulator. This assumes approximately 58% efficiency, 1400 watts input, and 300 watts per tube anode dissipation. The anode normally shows a dull to medium red color when operating at full power.
The tube is supported solely by its two filament posts. These posts are keyed with the F1 and F2 connection having a diameter of 9.5 mm (0.375 in) and 11.1 mm (0.438 in) respectively.
The 833A was preceded by the 833.
Characteristics.
Amplification factor, 35
Anode to Grid capacitance, 6.3 pF
Anode to Filament capacitance, 8.5 pF
Filament to Grid capacitance, 12.3 pF
Values for "two 833s" working class B as an audio amplifier or modulator.
Va "max", 3 kV
Ia "max", 500 mA (Averaged over one cycle of signal waveform per 833.)
Pin "max", 1.125 kW (Averaged over one cycle of signal waveform per 833. This is the total input power to each 833 at maximum drive.)
Pa "max", 300 W (Averaged over one cycle of signal waveform per 833. This is the maximum anode dissipation and at this power level the anode reaches a temperature of about 800 °C, and glows red hot.)
Vg1 "max", -70 V
A.F. grid to grid voltage, 400 V Pk.
No signal D.C. anode current, 100 mA
Max signal D.C. anode current, 750 mA
Load resistance, (Per 833), 2.375 kΩ
Effective load resistance, (anode to anode), 9.5 kΩ
Max signal driving power, 20 W avg.
Max output power, 1.65 kW avg.
Values "per 833" working class B as an R.F. amplifier with a maximum modulation factor of 1.0.
Va "max", 3 kV
Ia "max", 400 mA
Pin "max", 450 W (This is the total input power to each 833 at maximum drive.)
Pa "max", 300 W (This is the maximum anode dissipation and at this power level the anode reaches a temperature of about 800 °C, and glows red hot.)
Vg1 "max", -70 V
Peak R.F. grid voltage, 90 V.
D.C. anode current, 150 mA
D.C. grid current, 2 mA
Driving power, 10 W appx.
Output power, 150 W appx.
Values "per 833" working class C as an R.F. amplifier with a maximum modulation factor of 1.0.
Va "max", 2.5 kV
Ia "max", 400 mA
Pin "max", 850 W (This is the total input power to each 833 at maximum drive.)
Pa "max", 200 W (This is the maximum anode dissipation.)
Vg1 "max", -500 V, "nom", -300v
Peak R.F. grid voltage, 460 V.
D.C. anode current, 335 mA
D.C. grid current, 75 mA
Driving power, 30 W appx.
Output power, 630 W appx.
Values "per 833" working class C as an R.F. amplifier or oscillator, (C.W. conditions, unmodulated, 50% Duty cycle.)
Va "max", 3 kV
Ia "max", 500 mA
Pin "max", 1.25 kW (This is the total input power to each 833 at maximum drive.)
Pa "max", 300 W (This is the maximum anode dissipation.)
Vg1 "max", -500 V, "nom", -200 V
Peak R.F. grid voltage, 360 V.
D.C. anode current, 415 mA
D.C. grid current, 55 mA
Driving power, 20 W appx.
Output power, 1 kW appx.
Grid voltages measured with respect to the midpoint of the directly heated cathode.
80% efficiency at A.F., dropping to 60% at 100 MHz when used as an amplifier.
Applications.
The 833A was widely used in small (1 kW class) AM broadcast transmitters. Typically, a pair of 833As would be used in the final amplifier, plate modulated by another pair. It was also used in small induction heaters. This tube has also been used by hobbyists to construct a vacuum tube Tesla coil.


Chattanooga and Tennessee Electric Power Company

The Chattanooga and Tennessee Electric Power Company was formed in 1905 by Josephus C. Guild, Charles E. James and Anthony N. Brady to produce hydroelectric power and improving the navigation of the Tennessee River.
Josephus Guild, a young engineer from Chattanooga, became interested in a plan drawn by Major Dan C. Kingman, the head of the local office of the Army Corps of Engineers. The plan was originally developed to control the turbulent waters below Chattanooga in the Tennessee River Gorge known as the Suck, the Pot and the Skillet. These river features, long feared by riverboat navigators, impeded trade along the waterway
Rep. John A. Moon, a Democrat first elected in 1896, introduced a bill in 1904 that enabled the project. The bill said the construction cost would be borne by the recipient of the power franchise to be operated for 99 years and the government would hold title to the Dam.
After the city of Chattanooga failed to exercise its option on the project, Josephus Guild sought financial help from Charles James, a prominent Chattanooga businessman who was always eager to help promote the city's interests. James approached Anthony Brady, a New York financier with large interests in electrical utilities, who agreed to participate in the venture.
The Hales Bar Dam was built after Congressional action, on January 7, 1905, changed the site of the dam from Scott's Point. The cost of the dam was over $10,000,000. Josephus Guild died during the construction of the dam; his son, Jo Conn Guild, took an active role in the project. The dam was completed in 1913.
In the 1920s, the company merged with the Chattanooga Railway and Light Company and Drexel and Company, which had a competing project on the Ocoee River, to form the Tennessee Electric Power Company (TEPCO). In 1933, Congress established the Tennessee Valley Authority (TVA) to develop the economy by a series of flood control dams on the Tennessee River and to sell the electricity generated from the dams. After the Supreme Court in 1939 dismissed a challenge to the authority of the TVA to sell electricity in the service territory of the company, TEPCO's electric system was purchased for $78,425,095 by the Tennessee Valley Authority and other participating municipal public utilities and electric cooperatives. TEPCO continued to operate as a street car company in Chattanooga and was reorganized in 1941 as Southern Coach Lines. The company operated street cars until 1946, when it focused on bus travel. The company was purchased by the Chattanooga Area Regional Transportation Authority in 1973.


Electricity sector in Imperial Russia

The Electricity sector in Imperial Russia developed in the late nineteenth century. Vladimir Chikolev founded the electrical engineering section of the Imperial Russian Technical Society in 1878.


Thermophotonics

Thermophotonics (often abbreviated as TPX) is a concept for generating usable power from heat which shares some features of thermophotovoltaic (TPV) power generation. "Thermophotonics" was first publicly proposed by solar photovoltaic researcher Martin Green in 2000. However, no TPX device is known to have been demonstrated to date, apparently because of the stringent requirement on the emitter efficiency.
A TPX system consists of a light-emitting diode (LED) (though other types of emitters are conceivable), a photovoltaic (PV) cell, an optical coupling between the two, and an electronic control circuit. The LED is heated to a temperature higher than the PV temperature by an external heat source. If no power is applied to the LED, the system functions much like a very inefficient TPV system, but if a forward bias is applied at some fraction of the bandgap potential, an increased number of electron-hole pairs (EHPs) will be thermally excited to the bandgap energy. These EHPs can then recombine radiatively so that the LED emits light at a rate higher than the thermal radiation rate ("superthermal" emission). This light is then delivered to the cooler PV cell over the optical coupling and converted to electricity.
The control circuit presents a load to the PV cell (presumably at the maximum power point) and converts this voltage to a voltage level that can be used to sustain the bias of the emitter. Provided that the conversion efficiencies of electricity to light and light to electricity are sufficiently high, the power harnessed from the PV cell can exceed the power going into the bias circuit, and this small fraction of excess power (originating from the heat difference) can be utilized. It is thus in some sense a photonic heat engine.
Possible applications of thermophotonic generators include solar thermal electricity generation and utilization of waste heat. TPX systems may have the potential to generate power with useful levels of output at temperatures where only thermoelectric systems are now practical, but with higher efficiency.
A patent application for a thermophotonic generator using a vacuum gap with thickness on the order of a micrometer or less was published by the US Patent Office in 2009 and assigned to MTPV Corporation of Austin, Texas, USA. This proposed variant of the technology allows better thermal insulation because of the gap between the hot emitter and cold receiver, while maintaining relatively good optical coupling between them due to the gap's being small relative to the optical wavelength.


Solar power in Azerbaijan

Solar power in Azerbaijan includes individual and commercial scale systems. Due to its climatic conditions and locations Azerbaijan has greater potential for solar power than the rest of the region. Insolation values are higher and other conditions for solar power generation are comparable to neighboring countries in the South Caucasus. The country features 250 sunny days per annum: changing from 2210 to 2700 hours and from 865 to 1000 hours in summer and winter periods, respectively.
Insolation.
Annual solar radiation reaches 4.7 kWh/ m2/day and approximately 5000–6500 MJ/m2/year. The highest insolation areas are on the Absheron peninsula and Nakhchivan region. Solar radiation ranges from 1900 to 2800 in different regions such as high-mountain zones of the Great and Small Caucasus. Absheron Peninsula receives almost 1600 kWh/m2 per year of solar radiation.
Three locations of intensive solar radiation in Azerbaijan: Pirallahi-Island, Minguechaur and Nakhichivan.
Policies.
Existing legislation on renewable energy:


List of United States electric companies

The following page lists electric utilities in the United States.
Largest utilities by revenue (2014).
Reference:
List of US electric companies by state.
Arizona.
Page Power and Water http://www.pageutility.com/


Lower Wonga Solar Farm

The Lower Wonga Solar Farm is a proposed photovoltaic power station, located in the rural locality of Lower Wonga, Gympie Region, Queensland, Australia. If the station is completed to its final configuration of 3 million solar panels capable of powering about 315,000 homes, it would become Australia's largest solar power station.
Location.
The Lower Wonga Solar Farm would be located on previously cleared lands used for grazing, on the corner of the Wide Bay Highway and Gympie Woolooga Road, Lower Wonga, Queensland. The farm site is also located next to the Woolooga Substation and transmission lines, providing a cheap and easy point to distribute power into the grid.


Adelanto Converter Station

Adelanto Converter Station in Adelanto, California, is the southern terminus of the 2,400 MW Path 27 Utah–California high voltage DC power (HVDC) transmission line. The station contains redundant thyristor-based HVDC converters rated for 1,200 MW continuous or 1,600 MW short term overload. The station was completed in July, 1986 at a cost of US$131 million. The northern terminus of Path 27 is fossil fueled Intermountain Power Plant in Utah.
An adjacent $45 million AC switching station owned by Los Angeles Department of Water and Power links to the Southern California grid via five 500-kV AC lines.
ABB, who had built the station in 1986, upgraded its original 1,600 MW capacity to 2,400 MW in 2011.
In 2012, an 11.4 MW solar array (less than 1% of the Utah plant's capacity) was installed at the facility at a cost of $48 million obtained with loans subsidized by the American Recovery and Reinvestment Act of 2009.
Interconnects.
Adelanto substation is connected to the following via 500 kV AC lines:


Reedy Creek Energy Services

Reedy Creek Energy Services (RCES) is a wholly owned subsidiary of The Walt Disney Company. It operates the electric and other utility transmission and distribution systems of the Reedy Creek Improvement District (RCID) on behalf of the district which specifically covers Walt Disney World outside Orlando, Florida. Some power is produced by the district-owned power plant north of the Magic Kingdom with the remainder purchased from the public power grid. Officially the utility systems are owned by the district entity itself and the district "contracts" with RCES to operate the systems.
In addition to electric power, RCES handles all public services and public works for the RCID including water, natural gas, roadway maintenance, waste and recycling, sewage and wastewater treatment.
RCES is currently Disney's only non-entertainment-related subsidiary. Until 2001, Disney and Sprint owned Vista-United Telecommunications, a telephone company that served the RCID. That company has since been sold to Smart City Telecom.


EBOR

The Experimental Beryllium Oxide Reactor (EBOR) was a 10MWt helium cooled beryllium moderated nuclear reactor at Idaho National Laboratory. It never achieved criticality. The project started on February 17, 1958 as the Maritime Gas-Cooled Reactor. The project started with a contract between the U.S. Atomic Energy Commission and General Dynamics. The Goal of the project was to create a small nuclear reactor for use in merchant shipping or in a medium sized power plant. The main goals for the reactor were a simple design, low maintenance costs and maximum efficiency over a wide range of power settings. In December 1960 the project was authorized to construct a 10-Mw test reactor to determine the characteristics of the Beryllium Oxide gas cooled system. The EBOR was designed to test the basic fuel element and moderator designs for the final reactor. The EBOR used a Helium cooling system and was an intermediate step towards a prototype power plant. The plan was to use a closed cycle turbine or a steam cycle with the reactor to make a small land based or maritime power plant. This plan was abandoned as the reactor never achieved criticality.


Photovoltaic engineering in Australia

Photovoltaic and renewable energy engineering is an area of research, development, and demonstration in Australia. Two Australian Research Council Centres play a role.
School of Photovoltaic and Renewable Energy Engineering.
The School of Photovoltaic and Renewable Energy Engineering at the University of NSW offers undergraduate training and postgraduate and research training opportunities in the area of photovoltaics and solar energy. It is widely recognised for its research in the area of photovoltaics, most of which is now conducted under the ARC Centre of Excellence for Advanced Silicon Photovoltaics and Photonics.
School of Engineering and Energy.
The School of Engineering and Energy at Murdoch University offers a degree programs in physics, nanotechnology, engineering and energy.
ARC Centre of Excellence for Advanced Silicon Photovoltaics and Photonics.
The ARC Centre of Excellence for Advanced Silicon Photovoltaics and Photonics opened on 13 June 2003. The Centre is engaged in silicon photovoltaic research and applying these advances to the related field of photonics. The Centre is made up of five research teams seeking ways of improving the efficiency and cost of silicon based photovoltaic and photonic devices.
ARC Centre of Excellence for Solar Energy Systems.
The focus for the ARC Centre of Excellence for Solar Energy Systems is the development of improved silicon concentrator solar cells for 10-50 sun linear concentrators. Centre activities are located at the Centre for Sustainable Energy Systems in the Faculty of Engineering and Information Technology at the Australian National University. The Director of the ARC Centre for Solar Energy Systems is Professor Andrew Blakers and the Deputy Director is Dr Vernie Everett.
Innovation.
A sound barrier composed of solar panels helps light a section of the Tullamarine Calder Interchange in northern Melbourne and received an award.
External links.
Renewable energy in Australia


PTC India

PTC India Limited, formerly Power Trading Corporation of India Limited, is an Indian company that provides power trading solutions, cross border power trading, and consultancy services. Headquartered in New Delhi, India, the company also has operations in Nepal, Bhutan, and Bangladesh. PTC India's subsidiaries PTC India Financial Services Limited and PTC Energy Limited provide financial assistance for companies in the power sector and run renewable energy projects respectively.
The investment decisions of PTC management was criticized as "value destructive" by some institutional investors in August 2018.
As of January 2019, PTC Energy managed a renewable energy portfolio of around 290 megawatts of wind assets across Madhya Pradesh, Karnataka and Andhra Pradesh.


Hydroelectricity in China

Hydroelectricity is currently China's largest renewable energy source and the second overall after coal.
China's installed hydroelectric capacity in 2015 was 356 GW, up from 172 GW in 2009, including 23 GW of pumped storage hydroelectricity capacity.
According to the International Hydropower Association China is the worlds largest producer of hydroelectricity in 2020. In 2018, hydropower generated 1,232 TWh of power, accounting for roughly 18% of China's total electricity generation.
Due to China's insufficient reserves of fossil fuels and the government's preference for energy independence, hydropower plays a big part in the energy policy of the country.
China's potential hydropower capacity is estimated at up to 400 GW. There is therefore considerable potential for further hydro development.
Hydroelectric plants in China have a relatively low productivity, with an average capacity factor of 31%, a possible consequence of rushed construction and the seasonal variability of rainfall. Moreover, a significant amount of energy is lost due to the need for long transmission lines to connect the remote plants to where demand is most concentrated.
Although hydroelectricity represents the largest renewable and low greenhouse gas emissions energy source in the country, the social and environmental impact of dam construction in China has been large, with millions of people forced to relocate and large scale damage to the environment.
History.
The first hydroelectric power plant in China was built in Yunnan province in 1912, with a capacity of 240 kW. Due to the subsequent period of political and social instability, little additional progress was made in power infrastructure in the country at that time. The total installed capacity before the Japanese occupation was only about 10 MW. During the Japanese occupation several large scale hydroelectric projects were built, and total capacity reached 900 MW. Energy infrastructure however suffered heavy damage during the second World War, and the operational capacity after the war was only about 580 MW.
After the Chinese Communist Revolution of 1949, a program of dam construction was initiated. However, most of these dams were built for irrigation and not intended to produce electricity. Moreover, construction was carried out mostly by unskilled peasants. During this period, the steady supply of cheap domestic coal hindered the development of hydroelectricity.
Installed hydroelectric capacity grew somewhat after the 1960s, with plants of growing size and complexity, reaching a total of 20 GW in 1980.
After completion of the Baihetan Dam in 2021, all planned large scale dams had been completed.
Environmental impact.
Hydropower is considered a renewable and clean energy source. However large dams, such as the Three Gorges Dam or the Xiluodu Dam have had environmental impacts on the areas surrounding dam reservoirs. Typical problems have been erosion, flooding of farmland and destruction of fish breeding habitats.
Flooding of large areas for reservoirs also forced about 15 million people to be relocated since 1949.


Rede Energia

Rede Energia was a Brazil-based utility holding dedicated on electricity energy, is one of the biggest Brazilian electricity companies.
Through nine distributors, one generator and one transmitter, operates in distribution, marketing and power generation. It is responsible for supplying about 34% of the entire national territory, which means attending 16 million people in 578 municipalities in seven different Brazilian states: São Paulo, Minas Gerais, Paraná, Tocantins, Mato Grosso, Mato Grosso do Sul and Pará.
Rede Energia distributes 18.5 terawatts/hours per year through its 563 substations, which travels 15,000 km of transmission lines and 300,000 km of distribution networks. The company has more than 14,000 people in its workforce to deliver electric energy at 4.5 million consumer units.
The company is headquartered in Paulista Avenue in São Paulo and is listed in BM&F Bovespa.


Delaware Municipal Electric Corporation

The Delaware Municipal Electric Corporation (DEMEC) is a Joint Action Agency and wholesale electric utility that represents nine municipal electric departments in the state of Delaware in the United States. The agency, which was created in 1979, is headquartered in Smyrna.
About.
DEMEC is Joint Action Agency and wholesale electric utility that represents nine municipal electric departments in the state of Delaware in the United States, which consists of all the major cities and towns in Delaware except Wilmington. The agency's members combined provide electricity to over 125,000 customers and have a peak load of over 460 MW. DEMEC serves as the generation owner and PJM Interconnection Load Serving Entity for eight of the municipal electric departments (the exception being Dover), providing all of the wholesale electric supply to these communities, while DEMEC provides partial wholesale electric supply to Dover. The agency also provides legal and technical consulting service to its nine members and represents them at the federal and regional level.
DEMEC is governed by nine-member Board of Directors which consists of one director from each electric department. The Board of Directors appoints a President and CEO who is in charge of the daily operations of the agency.
DEMEC owns a generation plant in Smyrna that consists of two 50 MW units, supplying electricity to seven of its member utilities. The agency purchases solar power from the Dover SUN Park in Dover, which is owned by SunPower and supplies electricity to the city of Dover, and the Milford Solar Farm in Milford, which is owned by the Public Service Enterprise Group. Solar power is also produced from smaller facilities in DEMEC's member utilities' communities. DEMEC purchases wind power from the Laurel Hill Wind Farm in Lycoming County, Pennsylvania and from a 2 MW turbine at the University of Delaware's Hugh R. Sharp Campus in Lewes.
Members.
DEMEC's membership is composed of nine municipal electric departments in Delaware:
History.
DEMEC was created by an act of the Delaware General Assembly on June 6, 1978 and was incorporated on July 12, 1979. In 2002, DEMEC constructed a 50 MW generation plant in Smyrna at a cost of $35 million. A second 50 MW unit was added at this plant in June 2012.


Astron (fusion reactor)

The Astron is a type of fusion power device pioneered by Nicholas Christofilos and built at the Lawrence Livermore National Laboratory during the 1960s and 70s. Astron used a unique confinement system that avoided several of the problems found in contemporary designs like the stellarator and magnetic mirror. Development was greatly slowed by a series of changes to the design that were made with limited oversight, leading to a review committee being set up to oversee further development. The Astron was unable to meet the performance goals set for it by the committee; funding was cancelled in 1972 and development wound down in 1973. Work on similar designs appears to have demonstrated a theoretical problem in the very design that suggests it could never be used for practical generation.
History.
Strong focusing.
Christofilos is best known for independently inventing the concept of strong focusing, a feature used in particle accelerators. He had first started work along these lines in the late 1940s while running an elevator installation company, and in 1948 he wrote a letter to what was then the University of California's Radiation Laboratory at Berkeley outlining several ideas on accelerator focusing. When they returned his letter pointing out several problems, he solved these and wrote them again. This second letter was ignored. In 1950 Christofilos filed a patent application, which was granted in 1956 as US Patent 2,736,799.
Around the same time, Ernest Courant, Milton Stanley Livingston, and Hartland Snyder of Brookhaven National Laboratory were considering the same problem and devised the same solution, writing about it in the 1 December 1952 issue of "Physical Review". When he saw the paper, Christofilos arranged a trip to the US, arriving two months later. Making his way to Brookhaven, he angrily accused them of stealing the idea from his patent. He also met with members of the Atomic Energy Commission, and after meeting with his attorneys, they paid him $10,000 for the patent.
Astron proposal.
With the patent purchase came some fame and enough money that Christofilos was able to enter the US physics world. In April 1953 he attended a meeting of Project Sherwood, and presented another idea he had been working on in Greece, the Astron.
The basic idea was to inject high-energy electrons into a magnetic mirror (the "tank"). The electrons would be captured in the mirror, and build up a layer of current near the outside surface of the tank volume, which he called the "E-layer". The E-layer would itself produce a powerful magnetic field as it built up, and once the current reached a critical density, the fields would "reverse", and fold into a new configuration of closed lines that formed a continuous confinement area. Once the E-layer had successfully formed, fusion fuel would be injected into the area inside it, and heated by interactions with the E-layer to bring it to fusion temperatures.
This arrangement solved one of the main problems with the basic magnetic mirror concept, which had open field lines at the ends. Fuel could follow these lines right out of the reactor. Mirrors thus naturally leaked plasma, although designers believed they could address this problem by operating the machines at very high temperatures. In practice the leakage proved to be even higher than basic theory suggested, and never operated at the levels they hoped to achieve.
At the time, Sherwood was still secret, which presented problems when he first outlined the concept. Prior to his taking the stage, the formulas from the previous session on the blackboard had been carefully erased. As he filled the blackboard with his own equations, someone helpfully showed him the buttons that would raise it and reveal a fresh one underneath. This one had not been erased and led to a rushed effort to prevent any sensitive material leaking. Looking to avoid a repeat event, Christofilos was given a job at Brookhaven, where he could continue working on the Astron theory.
Astron testing.
In 1956, Christofilos finally received his security clearance, and he immediately moved to what was now the Lawrence Livermore National Laboratory (LLNL) to start work on the Astron concept. After two years enough progress had been made that he was able to present the idea at the 1958 Atoms for Peace conference in Geneva, along with a model of the system they proposed to build. This consisted of two main parts, the magnetic bottle where the plasma would be held, and a particle accelerator that provided the relativistic electrons.
In spite of his success, Christofilos was always an outsider at the lab. "Time" reported that "He still has no degree in physics, and his Greek accent, Greek volubility and love of passionate argument keep him an outsider." This led to friction within the physics establishment, and early calls for termination of the Astron program. A 1963 review of the entire Project Sherwood effort led to formal calls for cancellation. However, the program had backers within the management of the controlled fusion program, notably Glenn Seaborg and John S. Foster, both with strong ties to LLNL. Foster, in particular, was concerned about groups in Washington dictating development to the labs. After considerable argument, it was decided that the program would be allowed to continue, but would need to demonstrate field reversal by 1965.
By 1963 the team had designed and built a new type of linear induction accelerator with the required properties. The accelerator design led to interest as a particle beam weapon studied under Project Seesaw. However, during construction the team realized that the electrons were free to travel back into the accelerator area. Christofilos solved this by introducing resistor wires that slightly slowed the electrons after entering the tank, so they no longer possessed the energy needed to flow back out.
After some work ironing out bugs, the first results were published in June 1964. The accelerator worked, operating at 4 MeV and 120 amps, and a stable E-layer was confirmed, albeit generating only 2 A/cm of current, just 0.05% of the diamagnetic field required to reverse the field. Work continued to meet the 1965 goal of reversal, but ultimately failed. However, the electron layer was stable, so the Herb-Allison committee recommended it continue to the next milepost.
By 1967 this had been improved to 6%, but was still a long way from the stable E-layer the device needed to achieve. In 1968, Christofilos and T. Kenneth Fowler wrote a report asking for a more powerful accelerator, and upgrades to the tank.
Scrutiny.
Funds for the upgrades were eventually granted, but only at the cost of direct oversight by an Ad Hoc Panel created by the AEC. By this point the "conventional" designs, the stellarator and magnetic mirror, had long been working on real-world plasmas and were slowly increasing the pressures and temperatures. Astron, on the other hand, was still a long way from building its first useful E-layer, a prerequisite for plasma experiments.
The Ad Hoc Panel returned a negative report, complaining that far too much effort had been put into operational issues like accelerator performance, with little or no effort into theoretical studies on whether or not the plasma would ever be stable even if an E-layer could be formed. Moreover, the panel pointed out that no one had seriously studied whether or not an operating and stable Astron would require more power to operate than it would release. This was a serious concern in Astron, because its relativistic electrons would radiate away large amounts of power due to electron synchrotron radiation.
Christofilos had already considered this and suggested that an operational design would use protons in place of the electrons, and would not suffer from the same level of energy losses. However, no such accelerator existed at the time, and the panel was highly skeptical that it would be simple to build.
Upgrade.
The upgrades to Astron went ahead and started operation in 1969. During this period, following the advice of the Panel, the theoretical divisions at LLNL started taking a much more serious look at the concept. Building computer models of the system, they first attacked the problem of "stacking", that individual pulses of electrons from the accelerator did not build up in the E-layer as expected. Bruce Langdon demonstrated that stacking simply would not work.
However, a suggestion by Fowler proved to save the Astron from this problem. He had noted that adding a second magnetic field running down the centre of the tank would reduce the amount of external field needed to create the E-layer. Christofilos went ahead with this change and started testing in 1971; this demonstrated greatly improved performance both with the reduction in current and success in trapping the electrons. This also allowed two pulses to be stacked, raising the field to 15% diamagnetic strength.
While Astron worked towards multiple pulses, a team at Cornell University had been working on a similar design. However, this Relativistic Electron Coil Experiment (RECE) used a single long pulse of electrons rather than the stacking concept. Late in 1971 they announced they had achieved complete field reversal. Christofilos was unimpressed; this design would not be useful for a steady state fusion generator, only by continually adding pulses could the machine maintain itself.
Cancellation.
Faced with the continued problems with Astron, and the seeming ease that the RECE team had managed to reach the goals they had originally suggested in 1968, a second Ad Hoc Panel published a scathing report. Among the problems they noted that the Astron team had been looking "for ingenious ways to avoid or circumvent difficulties rather than to understand them." Roy Gould, head of the AEC's controlled fusion program, was specific in allowing the Astron project to continue, but only if it met a series of goals on a specific timeline.
When Robert Hirsch took over the AEC's controlled fusion arm in 1972, he instituted a sweeping review to classify the approaches under study and eliminate duplication and low-payoff projects. Given the exciting results with the tokamak released in 1968, Hirsch favoured a program with relatively few projects each given much larger budgets. Many programs like Astron simply didn't appear to have any near-term payoff, and Hirsch was keen to cancel them.
On 24 September 1972, Christofilos met with James Schlesinger of the AEC, but no record of the meeting remains. After a long day, he went to a local Holiday Inn to save a long commute home. That night he suffered a massive heart attack and died.
Richard Briggs took over direction of the project until its planned shutdown date in June 1973. Under his direction, Astron returned to study of the new stabilizing field introduced by Fowler, and using single larger pulses the device hit 50% diamagnetic strength, much greater than Christofilos' efforts with pulse chains. Their final report stated that "buildup of the E-layer by multiple-pulse injection was generally unsuccessful" and noted that at the time of the shutdown they still did not understand what physics problem was limiting the buildup.
After Astron.
Although Astron shut down, work continued with RECE at Cornell for some time. As part of their work, the team attempted to make the switch from electrons to protons. However, as some suspected, the "P-layer" proved difficult to build, and field reversal with protons was never achieved. The last version of this effort, FIREX, shut down in 2003, having demonstrated what appears to be a purely theoretical reason why the Astron concept will never work.
The relativistic electron ring also played a part in the bumpy torus design. This was another attempt to "plug the ends" of mirrors, by linking a number of mirrors end-to-end to form a torus. Electrons were driven to high energies not through direct injection, but external microwave-driven electron-cyclotron heating (ECH).
Description.
The Astron device consisted of two sections, the linear accelerator and the magnetic mirror "tank". These were constructed at right angles, with the accelerator's output firing into the side of the tank at one end.
The tank was a relatively simple example of the magnetic mirror concept, consisting largely of a long solenoid with additional windings at both ends to increase the magnetic field in those regions and form the mirror. In a simple mirror the ions in the fuel plasma were injected at an angle so they could not simply flow right out of the ends where the field was roughly linear. However, there was an annular region on either end where ions of the right energy could escape, and various calculations demonstrated the rate would be fairly high.
By injecting electrons into the mirror before the fuel, the E-layer would create a second magnetic field that would cause the annular areas to fold back into the center of the tank. The resulting field was shaped like a tube, and very similar to the Field-Reversed Configuration, or FRC. The main difference between these devices is the way the field reversal is achieved; with the E-layer in the Astron, and by currents in the plasma for the FRC. Like the classic mirror, Astron injected the electrons into the mirror at a slight angle to ensure they would circulate into the center of the mirror.
Today, the Astron is often considered a sub-class of the FRC concept.


Marinus Link

Marinus Link was a proposed HVDC interconnector, crossing Bass Strait and connecting the states of Tasmania and Victoria in Australia's National Electricity Market. If constructed, it would have been the second interconnector between these regions.
History.
The first interconnector between the two regions, Basslink, was commissioned in 2005 and had a power rating of 630 MW. This connector experienced a fault in December 2015, rendering it out of service for six months. Hydro Tasmania's role in the usage of the interconnector and short selling of water reserves six months prior was a major factor which resulted in the 2016 Tasmanian energy crisis. After the eventual restoration of service, power rating of the cable was limited to 500 MW.
In 2017 the Australian federal and Tasmanian state governments jointly established the study of the feasibility of a second interconnector between the two regions.
Project Marinus was established in 2018 and partially funded by the Tasmanian Government, through its ageing electricity transmission and distribution business TasNetworks, and the Australian Renewable Energy Agency. It was due to receive a further $56 million from the Federal Government in February 2019 to progress the initial development of the interconnector, subject to a viable feasibility study completion.
Project.
The feasibility study was released in February 2019 and modelled an interconnector with a capacity of either 600 MW or 1,200 MW, connecting North West Tasmania to the Latrobe Valley area of Victoria. Such a connector was found to be economically unviable under the retirement of Victorian coal power stations in the 2020s. These values were used to develop the business case assessment, which was released in December 2019.
The business case failed to support an increased capacity of 1,500 MW, constructed in two stages of 750 MW each. Various options for the schedule of construction was considered between 2027 and 2032.


Association of Power Producers of Ontario

The Association of Power Producers of Ontario (abbreviated APPrO) is a trade and professional body representing commercial electricity generators in Ontario, and the largest organization of its type in Canada. APPrO was established in 1986 as the Independent Power Producers' Society of Ontario (IPPSO) and changed its name to APPrO in 2003. It projects a unified voice of advocacy for Ontario-based generators of all types, addressing a range of public policy and regulatory issues of concern to the power industry. The organization also operates industry conferences and produces a number of publications, both hardcopy and electronic. The APPrO conference is the largest annual event of its type in Canada.
APPrO currently has about 100 corporate members including TransCanada Corporation, Bruce Power and Brookfield Renewable Power, along with many lesser-known companies. APPrO members produce electricity from a range of sources including natural gas, hydroelectricity (waterpower), cogeneration, windpower, solar energy, biomass (wood waste), biogas, nuclear energy, and other sources.
APPrO's current advocacy work is focused on regulatory and policy issues affecting generators in Ontario including electricity market rules, power procurement processes, the regulation of the natural gas market, both provincially and federally, climate change rules and compliance mechanisms, approval requirements, transmission development, distributed generation, and a number of other issues.
Structure and history.
APPrO has frequently put forward the view that the greatest benefits for consumers of electricity are likely to be achieved through the development of open and competitive markets for the production of electricity. Since it was established in 1986, APPrO has been one of the most vocal and consistent advocates for increasing the use of renewable energy in Ontario. Originally incorporated as the Independent Power Producers' Society of Ontario, the organization grew in scale and scope during the 1990s.
APPrO's predecessor IPPSO was one of the forces that helped convince the Ontario government to end the near-monopoly status of the former Ontario Hydro and introduce a competitive wholesale market for electricity in the province.
The organization is governed by a Board of 28 directors, and is operated on a day-to-day basis by a President, an Executive Director and support staff. 14 of the directors are appointed as direct representatives of major generator members or staff, and the remainder are elected from various categories of APPrO members. The first full-time (and current) president of APPrO is David Butters. The Executive Director is Jake Brooks.
Over the years, APPrO's efforts have affected important decisions in the areas of ramp rates, natural gas supply services, net load billing for network transmission services, market design, and large number of technical rules and procedures. APPrO has worked closely with the Ontario government to ensure that the concerns and perspectives of its members are reflected in the contracting process for various procurement processes. APPrO says it intends to continue to advocate for "fair access to the market for all generators, reasonable terms for interconnection to the electric grid, a more efficient system in the future, and lower costs for all users of the electric system in Ontario."
The Canadian Power Conference and Trade Show.
APPrO's annual conference is the only annual conference covering all types of generation in Canada.


PSNH

Public Service of New Hampshire, commonly known as PSNH, was the largest public utility in the U.S. state of New Hampshire for decades. Founded in 1926, it sold natural gas and electricity, and for a time ran electric street-railway services and, later, bus service. The company was bought in 1992 and became part of what is now Eversource Energy.
History.
Large-scale electricity production came to New Hampshire in 1882 when the New England Weston Electric Light Company of Boston built a generating station in Manchester, on the property of the Amoskeag Manufacturing Company. In 1885 the Manchester Electric Light Company bought the Weston property in the city and in 1901 merged with the Manchester Traction, Light and Power Company - so named because electric trolley cars, the "traction" portion of the name, were a major customer of electricity producers. PSNH records indicate that at least 39 small electric companies that were in business before 1900 were combined over the years. PSNH was incorporated in 1926 as a consolidation of five existing independent electric companies in New Hampshire.
In 1935 the Public Utility Holding Company Act was passed, setting the stage for PSNH to become a regulated utility. In 1946 the company went public.
Among the power plants that the company built are Schiller Generation Station, three coal-fired units in Portsmouth, New Hampshire, which when opened in 1950 was the country's first fully integrated binary cycle plant, and the Seabrook Station nuclear power plant in Seabrook, New Hampshire, which began operating in 1990. Cost and deadline overruns in the construction of Seabrook Station caused PSNH to declare bankruptcy in 1998, the first investor-owned utility to go bankrupt since the Great Depression. That led to its sale to what was then Northeast Utilities, since renamed Eversource Energy.
In 2018 Eversource sold all the former PSNH power plants, including a number of hydropower dams and gas-fired power plants, to a group of investors known as Granite Shore Power LLC, as the final step in electricity deregulation.


List of solar-powered products

The following is a list of products powered by sunlight, either directly or through electricity generated by solar panels.


List of power stations in Indonesia

The following lists some of the larger power stations in Indonesia. Data are not included for a large number of small isolated plants (mostly diesel) in the Outer Islands. In total, the PLN operated over 5,000 plants across Indonesia in 2010 of which over 4,500 were small diesel plants outside of Java. For further details about existing capacity and operations of the electricity sector, see information about the state-owned Indonesian electricity company "Perusahaan Listrik Negara".
Non-renewable.
Thermal.
Thermal power is the largest source of power in Indonesia. There are different types of thermal power plants based on the fuel used to generate the steam such as coal, gas, diesel etc. About 85% of electricity consumed in Indonesia is generated by thermal power plants.
Bituminous coal or lignite.
Existing.
"Note: IPP means independent power producer"
Renewable.
Geothermal.
"Note: IPP means independent power producer"
Hydroelectric.
"Note: IPP means independent power producer"
Pumped-storage hydroelectric.
Currently under construction or planned: