2006 Auckland Blackout

The 2006 Auckland Blackout was a major electrical blackout in Auckland, the largest city in New Zealand, on 12 June 2006. It started at 8:30 am local time, with most areas of Auckland regaining power by 2:45 pm local time. It affected some 230,000 customers and at least 700,000 people in and around the city.
Immediate effect.
Power went off at around 8:30 am local time on 12 June 2006 over half of Auckland in New Zealand. Most of Southern and Central Auckland, including the central city were without power.
Cause.
The cause of the blackout was traced back to the Otahuhu sub-station, the city's main transmission switching station. A corroded shackle connecting the Otahuhu to Penrose 220 kV line's earth wire had dislodged in winds, letting the earth wire fall across the 220 kV line and the 110 kV busbar below it, tripping both the line and three sections of the busbar, disconnecting lines to Mount Roskill, Penrose and Pakuranga. The trip also disconnected Otahuhu B and Southdown power stations from the national grid. The trip left only one line, the now-dismantled Arapuni to Pakuranga 110 kV line, supplying Pakuranga, Penrose, and the central city. Eight seconds after the failure, this line tripped from overloading, leaving Penrose, Pakuranga, and central city substations without power, as well as parts of Otahuhu and Mount Roskill substations.
Investigation of this incident found that maintenance of the electricity transmission system was not adequate and that this substation had major and minor design deficiencies.
Effects.
Due to the power outage, many public services and business operations were disrupted:
Since the central city was without power from the morning rush hours, business operations and traffic were disrupted severely. Many businesses sent their staff home.
Restoration of service.
Power was restored to Auckland central at 12:40 local time, 12 June 2006. It was estimated that all affected areas would have their power restored by 16:30 local time. At approximately 14:45, power was restored to most of Auckland, except Penrose, Glen Innes, East Tamaki, and Otahuhu.
Improving security of supply.
The incident at Otahuhu in June 2006 had a major influence on subsequent decisions about the development of the grid.
On 11 December 2006, the Electricity Commission (NZ) received an application from Transpower for the establishment of a new 220 kV gas insulated switchgear (GIS) facility at Otahuhu, adjacent to but geographically separate from the existing outdoor 220 kV switchyard. This project was described as the Otahuhu substation diversity project, and included transferring approximately half of the circuits from the existing switchyard to the new GIS switchyard, to improve network resilience. The project was approved in August 2007.
Further steps have been taken to increase security of supply to Auckland, by reducing the dependence on Otahuhu. These include the diversity provided as part of the North Island Grid Upgrade Project by connecting the new Whakamaru to Brownhill Road transmission line to Pakuranga substation, rather than directly to Otahuhu. A second major project, the North Auckland and Northland grid upgrade project provides underground 220 kV cables from Pakuranga to Penrose, and from Penrose to Albany on the North Shore, via Hobson Street in the Auckland CBD. A 220 kV- capable overhead transmission line between Pakuranga and Otahuhu has also been upgraded from 110 kV to 220 kV.


Solar power in Myanmar

Solar power in Myanmar has the potential to generate 51,973.8 TWh/year, with an average of over 5 sun hours per day. Even though most electricity is produced from hydropower in Myanmar, the country has rich technical solar power potential that is the highest in the Greater Mekong Subregion; however, in terms of installed capacity Myanmar lags largely behind Thailand and Vietnam.
The country aims to generate 8% of electricity through renewable energy sources—through wind and solar energy—by 2021 and 12% by 2025. In general, foreign direct investment in renewable energy in Myanmar was very limited during the period of 2012-2018.
In rural areas, photovoltaics are used for charging batteries and pumping water. 70% of the Burmese population of 50 million live in rural areas.
Myanmar's opened its first solar power plant in Minbu, Magway Division, in November 2018. The plant will produce 40 megawatts (MW) of electricity in its first phase of operations and will produce 170 MW once fully operational.
The country has plans to build two solar energy plants—in Myingyan and Wundwin in Mandalay Division—each to have a generation capacity of 150 MW.
To accelerate the development of solar energy in the country, Myanmar needs to improve renewable energy governance, build an effective regulatory framework for renewable energy and simplify the business environment for investors. As of 2021, Myanmar is not yet a member of the International Renewable Energy Agency (IRENA), an international organization that facilitates cooperation and promotes the adoption of renewable energy; joining IRENA could help Myanmar receive external support and attract more investment in renewables.


Flooding (nuclear reactor core)

Flooding refers to a fluid flow phenomenon whereby counter-current two-phase flow is reversed and runs concurrent in the direction of the initial gas/vapor phase flow when filling, or "flooding", a nuclear reactor core with coolant. This phenomenon is generally discussed with respect to a loss-of-coolant accident (LOCA). As this phenomenon proceeds, annular flow running counter-current begins as liquid water is inserted into the system. Then if conditions are correct, the frictional force at the gas-liquid interface begins to reverse the flow of the liquid. Finally, the flow of the liquid reverses, running concurrently in a slug (or other) flow regime. The significance of this phenomenon is that, if not properly designed for, it can present issues when trying to fill the core with liquid (the phenomenon works against gravity, forcing liquid out of the core).
Light water reactor examples.
In a boiling water reactor (BWR), the emergency core cooling system (ECCS) injects liquid water into the reactor core from the top. Water vapor produced from boiling will flow in the opposite direction. Given a high enough flow rate of steam, reversal of the ECCS-injected liquid water occurs.
In a pressurized water reactor (PWR), the ECCS injects liquid into the hot and/or cold leg of the reactor. The cold leg flows through a downcomer on the outside of the core, before flowing up through the core. The core barrel and the reactor vessel wall form a cylindrical shell that is referred to as the downcomer. In the cold leg, boiling in the downcomer creates an upward flow of steam that can reverse the flow of liquid water coming in through the cold leg. The flooding rate in a PWR is pressure dependent.
Similar terminology.
Flooding as a fluid flow phenomenon should be distinguished from the act of filling the core with coolant ("flooding of the reactor core"), as the fluid flow phenomenon occurs during the filling process. "Flooding of containment" refers to filling the nuclear reactor containment with liquid (usually water), which is distinctly different from either reactor core flooding or flooding as a fluid flow phenomenon.


Busbar

In electric power distribution, a busbar (also bus bar) is a metallic strip or bar, typically housed inside switchgear, panel boards, and busway enclosures for local high current power distribution. They are also used to connect high voltage equipment at electrical switchyards, and low voltage equipment in battery banks. They are generally uninsulated, and have sufficient stiffness to be supported in air by insulated pillars. These features allow sufficient cooling of the conductors, and the ability to tap in at various points without creating a new joint.
The term busbar is derived from the Latin word "omnibus", which translates into English as "for all", indicating that a busbar carries all of the currents in a particular system.
Design and placement.
The material composition and cross-sectional size of the busbar determine the maximum amount of current that can be safely carried. Busbars can have a cross-sectional area of as little as , but electrical substations may use metal tubes in diameter () or more as busbars. An aluminium smelter will have very large busbars used to carry tens of thousands of amperes to the electrochemical cells that produce aluminium from molten salts.
Busbars are produced in a variety of shapes, such as flat strips, solid bars, or rods, and are typically composed of copper, brass, or aluminium as solid or hollow tubes. Some of these shapes allow heat to dissipate more efficiently due to their high surface area to cross-sectional area ratio. The skin effect makes 50–60 Hz AC busbars more than about thickness inefficient, so hollow or flat shapes are prevalent in higher current applications. A hollow section also has higher stiffness than a solid rod of equivalent current-carrying capacity, which allows a greater span between busbar supports in outdoor electrical switchyards.
A busbar must be sufficiently rigid to support its own weight, and forces imposed by mechanical vibration and possibly earthquakes, as well as accumulated precipitation in outdoor exposures. In addition, thermal expansion from temperature changes induced by ohmic heating and ambient temperature variations, as well as magnetic forces induced by large currents, must be considered. In order to address these concerns, flexible bus bars, typically a sandwich of thin conductor layers, were developed. These require a structural frame or cabinet for their installation.
Distribution boards split the electrical supply into separate circuits at one location. Busways, or bus ducts, are long busbars with a protective cover. Rather than branching from the main supply at one location, they allow new circuits to branch off anywhere along the route of the busway.
A busbar may either be supported on insulators, or else insulation may completely surround it. Busbars are protected from accidental contact either by a metal earthed enclosure or by elevation out of normal reach. Power neutral busbars may also be insulated because it is not guaranteed that the potential between power neutral and safety grounding is always zero. Earthing (safety grounding) busbars are typically bare and bolted directly onto any metal chassis of their enclosure. Busbars may be enclosed in a metal housing, in the form of bus duct or busway, segregated-phase bus, or isolated-phase bus.
Busbars may be connected to each other and to electrical apparatus by bolted, clamped, or welded connections. Often, joints between high-current bus sections have precisely-machined matching surfaces that are silver-plated to reduce the contact resistance. At extra high voltages (more than 300 kV) in outdoor buses, corona discharge around the connections becomes a source of radio-frequency interference and power loss, so special connection fittings designed for these voltages are used.


Electricity sector in Ghana

Ghana generates electric power from hydropower, fossil-fuel (thermal energy), and renewable energy sources. Electricity generation is one of the key factors in order to achieve the development of the Ghanaian national economy, with aggressive and rapid industrialisation; Ghana's national electric energy consumption was 265 kilowatt hours per capita in 2009.
Ghana exports some of its generated energy and fossil fuels to other countries. Electricity transmission is under the operations of Ghana Grid Company. The distribution of electricity is under Northern Electricity Distribution Company and Electricity Company of Ghana.
History.
The first Ghana government-sponsored public electricity supply in Ghana commenced in the year 1914 at Sekondi-Takoradi, operated by the Ghana Railway Administration (Ghana Railway Corporation). Power supply was extended to Sekondi-Takoradi in 1928. The Ghana Public Works Department had commenced a limited direct current (DC) supply in Accra during 1922. A large alternating current (AC) project started on 1 November 1924, and a small plant consisting of three horizontal single cylinder oil-powered engines was installed in Koforidua in 1925.
In 1926, work started on electrical distribution to Kumasi. A restricted evening supply commenced in May 1927, and a power station was brought into full operation on 1 October 1927. In the same year DC supply was installed at Winneba but this was subsequently changed to AC by extending an existing supply from Swedru and during the period 1929-30, a limited electricity supply was extended to Tamale until a new AC plant was installed in 1938.
The next power station to be established was Cape Coast in 1932. This was taken over by the Ghana Electricity Department in 1947. A Ghanaian power station at Swedru was commissioned in 1948 and this was followed by the installation of generating plants at Akim Oda, Dunkwa-on-Offin and Bolgatanga in 1948. On 27 May 1949, an electricity supply was made available at Nsawam through the building of an 11 kV overhead transmission line from Accra. The Keta electricity supply which was included in the programme was delayed by staff difficulties and was not commissioned until 1955.
The Tema power station was commissioned in 1956 with a 3 x diesel generating set. The Ho power station followed in 1957 and from 1961-64. The Tema power station was extended to a maximum capacity of , thus, making it probably the biggest single diesel-powered generating station in Africa.
In 1963 the Ghana Electricity Division brought into operation the first 161 kV transmission system in Ghana, which was used to carry power from the Tema Power Station. At its peak in 1965, about 75 percent of the power was used in Accra.
In 1994, Ghana's total generating capacity was about 1.187GW, and annual production totaled approximately 4.49GW. The main source of supply was the Volta River Authority with six 127MW turbines installed at the Akosombo Hydroelectric Project. At this time, this project provided the bulk of all electricity consumed in Ghana, some 60 percent of which was purchased by Volta Aluminum Company (Valco) for its smelter. The power plant export amounted to an estimated equivalent of 180,000 tons of oil in 1991.
The balance of Ghana's electricity was produced by diesel units owned by the Electricity Corporation of Ghana, by mining companies, and by a 160MW hydroelectric plant at Kpong, about 40 kilometers downstream from Akosombo. A third dam at Bui on the Black Volta River had been studied, and was completed in 2013.
Other sites with the potential for power generation, on the Pra River (Ghana), the Tano River, the White Volta River, and the Ankobra River, would also require substantial investment.
Ghana has attempted to increase distribution of its electricity throughout the country. One program Ghana has initiated will provide reliable and widespread electricity in the urban and southern parts of the country. In addition, the extension of the national grid to the Northern Region was commissioned in 1989. The extension links northern Ghana to the power generated from the Akosombo Dam.
The second phase of the extension will connect major towns in Upper East Region with the regional capital, Bolgatanga, at a cost of US$100 million. The final phase will see exports of electricity across the northern national border of Ghana to Burkina-Faso. In early 1991 the Electricity Corporation of Ghana began the expansion of electricity networks in the northwestern areas of Accra and the Ghanaian corporation aimed to extend the supply of electricity to all isolated centers in Ghana where diesel is the main source of power. Plans were also afoot to increase the supply of electricity by utilisation of thermal energy and construction was anticipated by late 1994 on the country's first thermal power generating plant near Sekondi-Takoradi and scheduled for completion in 1997, the plant contributed 300MW of electricity to the Ghana national grid.
Since 2007, Ghana has become an electricity exporter and since 2011 an exporter of crude oil, and natural gas, and a generator of electricity by thermal energy, hydropower, solar energy and renewable energies since 2012.
Fossil fuel.
Crude oil and Natural gas production.
Ghana produces 140–200 million cubic feet of natural gas per day and in which natural gas production in Ghana has been restrained from full production capacity since December 2012, due to delays in construction of a Ghanaian gas refinery in Sekondi-Takoradi that was scheduled to be completed by December 2012 and now scheduled to be completed by December 2013, and due to which in turn has led to gas flaring and Ghana losing hundreds of millions a day since December 2012 in revenues from natural gas production. Since December 2012 billions of dollars a year have been lost from the Ghanaian GDP due to the delays in construction of a gas refinery in Sekondi-Takoradi.
A Ghanaian oilfield which is reported to contain up to of crude oil was discovered in 2007, and according to the Ghanaian government, the country could expand its petroleum reserves up to of crude oil in reserves within a few years.
Ghana produces 200,000 barrels of crude oil per day on average from an expected 1–2 million barrels of crude oil per day, and an expected crude oil production revenue of US$ 30 billion a year; as with Angola, also a crude oil producer, has an expected 2 million barrels of crude oil production per day and receives an expected $33.7 billion a year in crude oil revenues.
Tremendous inflow of economic capital from fossil fuel into the Ghanaian economy began from the first quarter of 2011 when Ghana started producing crude oil and natural gas in commercial quantities and the Ghana crude oil industry accounted for 6% of the Ghanaian economic revenue for 2011. Oil and Gas exploration in Ghana continues and the amount of both crude oil and natural gas in Ghana continues to increase.
Solar energy.
The biggest photovoltaic (PV) and the largest solar energy plant in Africa, the Nzema project, based in Ghana, will be able to provide electricity to more than 100,000 homes. The 155MW plant will increase Ghana's electricity generating capacity by 6%.
Construction work on the GH¢ 740 million (GB£ 248 million) and the 4th largest solar power plant in the world, is being developed by Blue Energy, a UK-based renewable energy investment company, majority owned and funded by members of the, Stadium Group, a large European private asset and development company with GB£ 2.5 billion under management. Project director is Douglas Coleman, from Mere Power Nzema Ltd, Ghana.
Unlike many other solar projects in Africa that use concentrated solar power, solar plants will use photovoltaic (PV) technology to convert sunlight directly into electricity. Installation of more than 630,000 solar PV modules will begin by the end of 2017.
As of August 2015, the project is still under development.
Wind energy.
In addition to hydropower and solar energy, Ghana also produces a lot of other renewable energy, other forms of energy that produce electricity in Ghana are wind power, geothermal and biomass. It is the official goal of Ghana energy industry to have 10% of Ghana's energy mix come from renewable sources (not counting large-scale hydropower) by 2015, or at the very latest by 2020.
Ghana has Class 4-6 wind resources at locations of the high wind areas – such as Nkwanta, the Accra Plains, and Kwahu and Gambaga mountains. The maximum energy that could be tapped from Ghana's available wind resource for electricity is estimated to be about 500 – 600 GWh/year. To give perspective – In 2011, from the same Energy Commission, the largest Akosombo hydroelectric dam in Ghana alone produced 6,495 GWhrs of electric power and, counting all Ghana's geothermal energy production in addition, total energy generated was 11,200 GWhrs in the same year.
These assessments do not take into consideration further limiting factors such as land-use restrictions, the existing grid (or how far the wind resource may be from the grid) and accessibility. Wind energy has the potential to contribute significantly to the country's energy industry – 10% can certainly be attained in terms of installed capacity, and about 5% of total electric generation potential from wind alone.
Bio energy.
Ghana has put in place mechanisms to attract investments into its biomass and bio-energy sectors to stimulate rural development, create jobs and save foreign exchange.
The vast arable and degraded land mass of Ghana has the potential for the cultivation of crops and plants that could be converted into a wide range of solid and liquid bio-fuels, as the development of alternative transportation fuels could help Ghana to diversify and secure its future energy supplies. Main investments in the bio-energy subsector existed in the areas of production, are transportation, storage, distribution, sale, marketing and exportation.
The goal of Ghana regarding bio-energy, as articulated its energy sector policy, is to modernise and examine the benefits of bio-energy on a sustainable basis. Biomass is Ghana's dominant energy resource in terms of endowment and consumption, with the two primary bio-fuels consumed being ethanol and biodiesel. To that effect, the Ghana ministry of Energy in 2010 developed the energy sector strategy and development plan. Highlights of the key policy objectives strategy for the renewable energy subsector include sustaining the supply and efficient use of wood-fuels while ensuring that their utilisation does not lead to deforestation.
The plan would support private sector investments in the cultivation of bio-fuel feedstock, extraction of bio-oil and its refining into secondary products, thereby creating appropriate financial and tax incentives. The Ghana Renewal Energy Act provides the necessary fiscal incentives for renewable energy development by the private sector, and also details the control and management of bio-fuel and wood- fuel projects in Ghana. The Ghana National Petroleum Authority (NPA) was tasked by the Renewable Energy Act 2011 to price Ghana's bio-fuel blend in accordance with the prescribed petroleum pricing formula.
The combined effects of climate change and global economic turbulence, had triggered a sense of urgency among Ghanaian policymakers, industry and development practitioners to find sustainable and viable solutions in the area of bio-fuels.
Currently, Brazil, which makes ethanol from maize and sugarcane, is the world's largest bio-fuel market.


History of photovoltaic growth

The history of photovoltaic growth includes previous forecast and annual deployment figures by country.
Deployment reports.
Most PV deployment figures in this article are provided by the European Photovoltaic Industry Association in the "Global Outlook for Photovoltaics" report, the "Observatoire des énergies renouvelables" or EurObserv'ER's "Photovoltaic Barometer" report, and the IEA-PVPS (photovoltaic power systems) "Snapshot" and "Trends" report.
Deployment by country.
In 2013, worldwide deployment of solar PV amounted to almost 40 GW (39,953 MW)—an increase of about 35 percent over the previous year. Cumulated capacity increased by 38 percent to more than 139 GW. This is sufficient to generate at least 160 terawatt-hours (TWh) or 0.85 percent of the world's total electricity consumption of 18,400 TWh.
An uncertainty in Chinese deployment was the reason for a significant discrepancy between EPIA's "outlook" and IEA's "Trends" reports. EPIA did not take 1.1 GW of additional Chinese deployment into account, since at the time it was unsure whether these installations were connected to the grid. In IEA's final "Trends" report, the confirmed figures not only raised domestic Chinese deployment from 11.8 GW to 12.92 GW, but also contributed to increase global figures to almost 40 GW.
In 2013, Asia has been the fastest growing region, with China and Japan accounting for 49% of worldwide deployment. About a quarter has been installed in Europe (10,975 MW). The remaining quarter of the 38,400 MW deployed in 2013 is split between North America and other countries.
Europe is still the most developed region with a cumulative capacity of 81.5 GW, about 59 percent of the global total, followed by the Asia-Pacific region (APAC), including countries such as Japan, India and Australia with 22 GW or about 16 percent of worldwide cumulative capacity (due to its significance, China is excluded from the APAC region in all PV statistics and listed separately). European solar PV now covers 3 percent of the electricity demand and 6 percent of the peak electricity demand. However, deployment in Europe has slowed down by half compared to the record year of 2011, and will most likely continue to decrease. This is mainly due to the strong decline of new installations in Germany and Italy.
Cumulative capacity in the MEA (Middle East and Africa) region and ROW (rest of the world) accounted for less than 3 GW or about 2.2% of the global total. A great untapped potential remains for many of these countries, especially in the Sunbelt.
In 2013, the world's top installer were China (+12.92 GW), followed by Japan (+6.97 GW) and the United States (+4.75 GW), while Germany remained the world's largest overall producer of power from solar PV, with a total capacity around 36 GW and contributing 5.7% to its net electricity consumption. Italy met more than 7% of its electricity demands with solar PV, thus leading the world in that respect.
The top ten leading countries in terms of deployed and overall PV-capacity are shown above. Other mentionable PV deployments above the 100-megawatt mark included France (643 MW), Canada (445 MW), South Korea (445 MW), Thailand (437 MW), The Netherlands (360 MW), Switzerland (319 MW), Ukraine (290 MW), Austria (263 MW), Israel (244 MW), Belgium (237 MW), Taiwan (170 MW) Denmark (156 MW) and Spain (116 MW).
In 2013, Europe added 11 gigawatts of new PV installation (including non-EU countries). It is still the most developed region with a cumulated total of 81.5 GW, about 59 percent of the worldwide installed capacity. Solar PV now covers 3 percent of the electricity demand and 6 percent of the peak electricity demand. However, European PV deployment has slowed down by half compared to the record year of 2011, and will most likely continue to decrease. This is mainly due to the strong decline of new installations in Germany and Italy.
Off grid refers to photovoltaics which are not grid connected. On grid means connected to the local electricity grid. Δ means the amount installed during the previous year. Σ means the total amount installed. Wp/capita refers to the ratio of total installed capacity divided by total population, or total installed Wp per person. Module price is average installed price, in Euros. kW·h/kWp·yr indicates the range of insolation to be expected. While National Report(s) may be cited as source(s) within an International Report, any contradictions in data are resolved by using only the most recent report's data. Exchange rates represent the 2006 annual average of daily rates (OECD Main Economic Indicators June 2007).
Module Price: Lowest:2.5 EUR/Wp (2.83 USD/Wp) in Germany 2003. Uncited insolation data is from maps dating 1991–1995.
Notes: While National Report(s) may be cited as source(s) within an International Report, any contradictions in data are resolved by using only the most recent report's data. Exchange rates represent the 2006 annual average of daily rates (OECD Main Economic Indicators June 2007)
Module Price: Lowest:2.5 EUR/Wp (2.83 USD/Wp) in Germany 2003. Uncited insolation data is lifted from maps dating 1991–1995.
Original source gives these individual numbers and totals them to 37,500 kW. The 2004 reported total was 30,700 kW. With new installations of 6,800 kW, this would give the reported 37,500 kW.


Variable shunt reactor

Variable Shunt Reactors are used in high voltage energy transmission systems to stabilize the voltage during load variations. A traditional shunt reactor has a fixed rating and is either connected to the power line all the time or switched in and out depending on the load. Recently Variable Shunt Reactors (VSR) have been developed and introduced on the market. The rating of a VSR can be changed in steps, The maximum regulation range are depending on the capability of the on-load tap changer used in combination with the regulation winding used for the shunt reactor, the maximum regulation range has increased over the years, from 50%, now up to 80% at some voltage levels
The variability brings several benefits compared to a traditional fixed shunt reactors. The VSR can continuously compensate reactive power as the load varies and thereby securing voltage stability. Other important benefits are:
VSRs are considered as technically advanced products and are mainly supplied by larger global manufacturers.


Unitil Corporation

Unitil Corporation is an interstate electricity and natural gas utility company that serves the areas in New Hampshire, Massachusetts and Maine. Its earliest predecessor company, the Portland Gas Light Company, was founded in Maine in 1849. The current company was set up in 1984 and is based in New Hampshire. It provides electric services to about 102,400 customers and natural gas to over 75,900 customers. The service territory of Unitil includes business districts and recreational centers as well as commercial and industrial business, such as electronic component manufacturers and education institutes. The company has an enterprise value of $766.54 million. The non-utility business is operated through the company's subsidiary, U-source, which is a national energy brokering and consulting company.
Background.
Unitil Through The Years
1849 Portland Gas Light Company founded in Maine.
1852 Fitchburg Gas and Electric Light Company is organized to illuminate gas streetlights in downtown Fitchburg, Massachusetts.
1901 Concord Electric Company is founded.
1908 Exeter & Hampton Electric Company is founded.
1979 Northern Utilities is incorporated. Its predecessor companies include Portland Gas Light Company.
1984
Unitil Corporation is incorporated as a public utility holding company, with utility operating subsidiaries Concord Electric Company and Exeter & Hampton Electric Company. Unitil Service Corp. is founded to provide joint administrative services for Unitil's subsidiary companies.
1992 Unitil merges with Fitchburg Gas and Electric Light Company, and Fitchburg remains as one of Unitil's operating utility companies.
1993 Unitil founds Unitil Resources, Inc. as a non-utility subsidiary. Its affiliate, Usource LLC., provides energy brokerage services to large energy users throughout the northeast seeking competitive electricity or natural gas supply.
2002 Concord Electric Company and Exeter & Hampton Electric Company merge, and Unitil Energy Systems is the new name of the combined companies.
2008 Northern Utilities and Granite State Gas Transmission are acquired by Unitil.
2018 Tom Meissner was named Unitil's Chairman of the Board, Chief Executive Officer, and President.
The Company generates revenue mainly distributing utility to customers through operating the underground transmission pipeline and providing energy consulting service and real estate service. 2013, the revenue of gas operation is $170.4 million accounting for 46% of the total operation revenue, and the electricity operation revenue, $190.7 million, represents 52% of the total revenue.
The company has four segments, three wholly owned distribution utilities and five subsidiaries, providing utilities and relevant advice and management service to customers. The three distribution utilities are Unitil Energy Systems, Inc., Fitchburg Gas and Electric Light Company and Northern Utilities, Inc.
The cold weather made more and more people switch to the service of Unitil, which resulted in a gas sale increase, so the company has planned to invest $570 million to expand its distribution infrastructure to serve a larger number of customers.
In winter 2014, the company has asked for a price increase to part of its customers in Greater Portland and the Lewiston-Auburn because of the high demand and harsh weather. The Maine Public Utilities Commission (PUC) approved its price increase but cut its request by one-third.


Uwe Rau

Uwe Rau is a German physicist that made important contributions to the physics of the photovoltaic device, notably on explaining energy losses in thin-film solar cells and on the use of the reciprocity principle to characterize solar cells by electroluminescence techniques. This led to the development of this technique as a standard in research and industry.
Career.
Rau studied physics at the University of Tübingen, Germany, and the Université Claude Bernard, Lyon. Both his diploma thesis (1987) and his doctoral thesis (1991) were obtained for work performed in the group of Huebener, at the University of Tübingen, on the breakdown of Germanium under high magnetic fields, and for non-linear charge transport in semiconductors. He then moved to the Max Planck Institute for Solid State Physics in Stuttgart, where he first did work on crystalline silicon solar cells. In 1995, he moved to Bayreuth where he worked dominantly on the device physics of Cu(In,Ga)Se2 solar cells. 1997, he moved back to Stuttgart to work at the University of Stuttgart, Institute of Physical Electronics, which was led by Jürgen Werner. In Stuttgart, he continued work on Si and Cu(In,Ga)Se2, but also started work on dye-sensitized solar cells, organic solar cells, and the fundamental aspects of luminescence in solar cells. In 2002, he obtained his habilitation from the University of Oldenburg, Germany, for work on the electrical transport properties of semiconductors and interfaces for photovoltaics. Since 2007, Rau is a full professor at the RWTH Aachen and Director of the Institute for Energy and Climate Research at the Forschungszentrum Jülich. Since 2011, he is in addition, the scientific director of the HITEC graduate school at the Forschungszentrum Jülich. Currently, he is the director of the JARA-Energy, (JARA = Jülich-Aachen Research Alliance) which coordinates research at Forschungszentrum Jülich and RWTH Aachen in the field of renewable energy.
Achievements.
Rau is well known for his various contributions to the basic principles of photovoltaic energy conversion and to improving the understanding of solar cell device physics. Most notable, perhaps, is his publication in 2007 of a paper on a "reciprocity relation between photovoltaic quantum efficiency and electroluminescent emission of solar cells". This work uses the principle of detailed balance to derive basic relationships between the photovoltaic and the light-emitting mode of a semiconductor diode. This work had substantial influence on the field of characterizing solar cells or modules using luminescence-based techniques. In addition, it has provided a framework for analyzing voltage losses at the open circuit in solar cells.
Uwe Rau also contributed towards the analysis of thin film solar cells, with seminal papers on the ideality factor, on metastability of the electronic conduction in Cu(In,Ga)Se2, on photovoltaic device stability and self-healing, and on the passivation of grain boundaries in polycrystalline thin film solar cells.
He also contributed to several important papers to understand the conversion efficiency limitations of solar cells, among which the role of disorder and potential fluctuations, and on the impact of light trapping on the Voc of solar cells.


CPC (company)

CPC is a British end-user and business-to-business distributor of electrical and related products. Since 1995 it has been a brand of Farnell, which itself was acquired by Avnet in 2016.
History.
Established in 1967, Combined Precision Components Ltd was acquired by British company Farnell Electronics (later Premier Farnell) in May 1995. Premier Farnell was in turn acquired by American company Avnet in 2016.
CPC's distribution centre is at Preston, Lancashire, close to the M6 motorway.
CPC was the host of the UK's first Raspberry Pi hack day, held in Leeds in December 2012. The 24-hour event focused on programming solely using the credit card-sized computer.


Hydroelectric power in Himachal Pradesh

Himachal Pradesh is extremely rich in its hydroelectricity resources. The state has about twenty five percent of the national potential. About 27,436 MW of hydroelectric power can be generated in the state by the construction of various hydroelectric projects on the five perennial river basins. Out of total hydroelectric potential of the state, 10,519 MW is harnessed so far, out of which only 7.6% is under the control of Himachal Pradesh Government while the rest is exploited by the Central Government. The state government has been giving the highest priority for its development, since hydroelectric generation can meet the growing need of power for industry, agriculture and rural electrification. It is also the biggest source of income to the state as it provides electricity to other states.
Himachal has enough resources to generate surplus power but in winter less flow of water in rivers and increases in lighting and heating load can result in power shortages that overshoot ten lakh units per day. Due to increased industrialization and rural electrification this figure is expected to rise even further.
Completed projects.
Girinagar Hydel Project.
Situated on the river Giri of the Sirmour District, Girinagar Hydel project has an installed capacity of 60 MW, with 2 units of 30 MW each. This project, which is run-off-the-river scheme comes under HPSEB and is operational for 29 years.
This project completed in 1966 by state government.
Binwa Hydel Project.
The project has an installed capacity of 6 MW comprising 2 units of 3 MW each., located near Baijnath in District Kangra. The project is situated 25 km from Palampur and 14 km from Baijnath is constructed at an elevation of 1515 meters above sea level. This project constitutes a 62-meter-long tunnel that connects trench weirs in Banu Khad and Prahal Khud.
Sanjay Vidyut Pariyojna.
Located in the Kinnaur district, on the river Bhaba is a completely underground project with an installed capacity of 120 MW, comprising 3 units each of 40 MW. The uniqueness of this project lies in its underground switchyard, a feature that no other hydel project in Asia can brag about. Completed in 1989-90, the estimated cost was about 167 crore rupees. The total length of tunnels including those secured in after completing the project is 12 km.
Bassi Hydroelectric Project.
Bassi project (66 MW) is an extension of Beas Power House (Mandi District) constituting 4 units of 16.5 MW each. It utilizes the tail water of Shannon Power House of Joginder Nagar project.
Larji Hydroelectric Project.
Larji hydroelectric project is on river Beas in Kullu district with an installed capacity of 126 MW. The project was completed in September 2007.
Andhra Hydel Project.
Commissioned during the year 1987-88, the project has 3 units of 5.5 MW which makes it 16.5 MW of installed capacity. It is located in Rohru tehsil of Shimla district. The cost of the project was estimated to be around 9.74 crores, transmitting to the state grid via the Nogli power house near Rampur.
Rongtong Hydel Project.
Rongtong is a 2 MW project that is located in the "Lahaul-Spiti district" on Rongtong Nullaha, a tributary of "Spiti" river. Located at an elevation of 3,600 metres in a snow adhered region, this was the first hydel project executed for the socio-economic upliftment of the tribals of this area. It is one of the highest in the world. The snow fed water runnel tapped at an elevation of 3,788 m is diverted through 2,825 m long channel and 259 m long tunnel into an open reservoir with a capacity of 14,000 cubic m. Renovated by APE Power Pvt. Ltd., APE Power also renovate RUKTI (4 × 375 KW) Hydro Electric project.
Baner and Neugal Project.
With the combined installed capacity of 12 MW the projects are situated on Baner and Neugal streams respectively in Kangra District. Both of the streams emerge from Dhauladhar and join Beas in the form of tributaries in south.
Is is in 2 districts the power house is in shimla and the dam is in nathpa which is in Kinnaur district.
Nathpa Jhakri Project.
One of the major project on the Sutlej river is the "Nathpa Jhakri Dam" which generates nearly 1500 MW of electricity. The project is funded by World Bank.
its construction cost is around 8000 crores.
Sainj Hydroelectric Project.
Installed Capacity 100 MW. [2×50 MW]. It is situated in Kullu district.
Bhakra Dam.
The Bhakra Dam has the first Dam to have come up on the Satluj river, it is one of the highest gravity dams in the world and has an Installed capacity of 1325 MW.
The dam holds excess waters during the monsoon and provides a regulated release during the year . It also prevents damage due to monsoon floods. The dam provides irrigation to 10 million acres (40,000 km²) of fields in Punjab, Haryana, and Rajasthan. Bhakra Dam is established on 1954.
References.
4. Economic survey of Himachal Pradesh 2014-15


Electricidad de Caracas

Electricidad de Caracas (BVC: EDC) is the integrated electricity company for Caracas, Venezuela and surrounding areas, with more than 1 million connections. It was acquired by AES Corporation in 2000 and sold to the state-owned oil company PDVSA in 2007, which now owns 93.62%. Paul Hanrahan, president and CEO of AES said the deal had been a fair process that respected the rights of investors. Since 2007 and the nationalization of the electricity generation and transportation, it has been incorporated into Corpoelec.


Marcy South

Marcy South is a 2 circuit high voltage power line in the U.S. State of New York. Each circuit is 345,000 volts, the one circuit runs from Fraser Substation in Delaware County to Marcy Substation in Oneida County and the other circuit runs from Coopers Corners Substation to the Marcy Substation. It was constructed amid heavy controversy in the late 1980s by the New York Power Authority.
History.
The Power Authority of the State of New York announced plans to deliver hydroelectric power from Canada to the New York City region in 1982.
It became fully operational on June 1, 1988.
Controversy.
The power line met with vigorous and sometimes highly contentious and violent opposition from local property owners from its proposition to its planning and surveying, and even its construction.
Power grid improvement.
The "Marcy South Series Compensation Project" began in 2016 and involved the installation of three series capacitor banks. The capacitor banks were installed to raise the voltage and keep it constant, which enhances transmission efficiency. Two capacitor banks were installed by New York Power Authority, the other installed by NYSEG at the Fraser Substation.
Future plans.
Since its construction, other projects including a high-voltage DC line have been proposed for the same route.


Demand factor

In telecommunication, electronics and the electrical power industry, the term demand factor is used to refer to the fractional amount of some quantity being used relative to the maximum amount that could be used by the same system. The demand factor is always less than or equal to one. As the amount of demand is a time dependent quantity so is the demand factor.
The demand factor is often implicitly averaged over time when the time period of demand is understood by the context.
Electrical engineering.
In electrical engineering the demand factor is taken as a time independent quantity where the numerator is taken as the maximum demand in the specified time period instead of the averaged or instantaneous demand.
This is the peak in the load profile divided by the full load of the device.
Example:
If a residence has equipment which could draw 6,000 W when all equipment was drawing a full load, drew a maximum of 3,000 W in a specified time, then the demand factor = 3,000 W / 6,000 W = 0.5
This quantity is relevant when trying to establish the amount of load for which a system should be rated. In the above example, it would be unlikely that the system would be rated to 6,000 W, even though there may be a slight possibility that this amount of power can be drawn. This is closely related to the load factor which is the average load divided by the peak load in a specified time period.


Electricity sector in Canada

The electricity sector in Canada has played a significant role in the economic and political life of the country since the late 19th century. The sector is organized along provincial and territorial lines. In a majority of provinces, large government-owned integrated public utilities play a leading role in the generation, transmission, and distribution of electricity. Ontario and Alberta have created electricity markets in the last decade in order to increase investment and competition in this sector of the economy.
Hydroelectricity accounted for 60% of all electric generation in Canada in 2018, making Canada the world's third-largest producer of hydroelectricity after China and Brazil. Since 1960, large hydroelectric projects, especially in Quebec, British Columbia, Manitoba, and Newfoundland and Labrador, have significantly increased the country's generation capacity.
The second-largest single source of power (15% of the total) is nuclear power, with several plants in Ontario generating more than half of that province's electricity, and one generator in New Brunswick. This makes Canada the world's sixth-largest producer of electricity generated by nuclear power, producing 95 TWh in 2017.
Fossil fuels generate 18% of Canadian electricity, about half as coal (7% of the total) and the remainder a mix of natural gas and oil. Only four provinces use coal for electricity generation. Alberta, Saskatchewan, New Brunswick, and Nova Scotia rely on coal for less than half their generation while other provinces and territories burn none for electricity. Alberta and Saskatchewan also use a substantial amount of natural gas. Remote communities including all of Nunavut and much of the Northwest Territories produce most of their electricity from diesel generators, at high economic and environmental cost. The federal government has set up initiatives to reduce dependence on diesel-fired electricity. However, in 2018, the NWT generated 70% of their electricity from hydroelectric dams and 4% from wind. In Nunavut, solar generates a small amount of electricity though small installations and projects.
Non-hydro renewables are a fast-growing portion of the total, at 7% in 2016. Notably, Prince Edward Island generates nearly all its electricity via wind power.
Canada has substantial electricity trade with the neighbouring United States amounting to 72 TWh exports and 10 TWh imports in 2017.
Canadian homes, offices and factories are large users of electricity, or "hydro", as it is often called in many regions of Canada. In 2007, Canadian per capita electricity consumption was among the highest in the world, with a yearly average of 17MWh. In 2017, the average annual electricity consumption per capita in Canada dropped to 14.6 MWh. Quebec had the highest annual consumption at 21 MWh per capita, while Nunavut had the least, 6.1 MWh per capita. In 2018, electricity generation accounted for 9% of Canada's emissions, a 32% decrease from 1990.
History.
Electricity has been significant for Canada's economy and politics since the late 19th century. In the 1890s, three firms competed to develop the Canadian Niagara Falls. After the First World War, the provincial utilities were created. The public companies focused on rural electrification and hydroelectric development.
Organization.
The electricity sector in Canada is organized along provincial and territorial lines as part of their jurisdiction over natural resources. All provinces and territories have set up utilities boards and regulate transmission and distribution rates.
The liberalization process of the 1990s changed some parameters such as the unbundling of generation, transmission and distribution functions of incumbent utilities in order to foster a competitive wholesale market or, as in the cases of large exporters like Quebec and British Columbia, to comply with Order 888 of the Federal Energy Regulatory Commission and other U.S. market rules. Most provincial governments still maintain a strong financial stake as operators in the electrical markets.
In a majority of provinces and territories, utilities are vertically integrated Crown corporations operating as regulated monopolies. This is by and large the case in New Brunswick, Quebec, Manitoba, Saskatchewan, British Columbia and Nunavut. A second model involves a Crown corporation as a large generator or in transmission, alongside an investor-owned distributor, as in Newfoundland and Labrador, Yukon, the Northwest Territories and, to a lesser degree, Prince Edward Island. Nova Scotia has granted a virtual monopoly to Nova Scotia Power, when it divested its investments in the sector in 1992. However, there remain half a dozen small public electric distributors - the Municipal Electric Utilities of Nova Scotia who have the right to buy power from other parties, or generate their own. NS has a feed-in tariff program to encourage smaller generators.
Two provinces, Ontario and Alberta, have deregulated their electric industry to different degrees over the last decade. Both provinces operate electricity markets, but there are significant differences between the two systems. The Ontario market is a hybrid, with the Ontario Power Authority (now merged with the IESO) "contracting for supply, integrated system planning, and regulated pricing for much of Ontario's generation and load". In Alberta, the generation business is competitive, while transmission and distribution are rate-regulated.
A number of municipalities operate local distribution systems. Some of them, such as EPCOR in Edmonton, are also significant players in the power generation business, under their name or through their control of publicly traded companies.
The federal government, through the National Energy Board, issues permits for inter-provincial and international power lines. The Canadian Nuclear Safety Commission has jurisdiction over nuclear safety. Ottawa and the provinces share jurisdiction over environmental issues such as air pollution and greenhouse gas emissions. Also, major hydroelectric developments trigger federal environmental assessment processes, as the Government of Canada has the power to regulate waterways and fisheries.
Energy-intensive businesses, such as the aluminium smelting and pulp and paper industries have made significant investments over time in power generation. One such company is Rio Tinto Alcan, which owns and operates 7 hydroelectric generating stations in Quebec and British Columbia, with a combined installed capacity of 3,300 MW.
In recent years, partial or complete deregulation of the wholesale generation business have created a number of Independent Power Producers, who build and operate power plants and sell over the long-term, through power purchase agreements — with terms of up to 35 years — and in day-ahead and hour-ahead transactions, where such markets exist.
Generation.
In 2013, Canada generated 651.8 terawatt-hours (TWh), a 10% increase since 2003. Approximately 822 generating stations are scattered from the Atlantic to the Pacific, for a nameplate capacity of 130,543 MW. The 100 largest generating stations in Canada have a combined capacity of 100,829 MW. In comparison, the total installed capacity of Canada was 111,000 MW in 2000.
In 2013, the leading type of power generation by utilities in Canada is hydroelectricity, with a share of 60.1%. Nuclear (15.8%), natural gas (10.3%), coal (10%), wind (1.8%), fuel oil (1.2%), biofuels and waste (0.
8%), wood (0.4%) and solar (0.1%) follow. Other sources, such as petroleum coke make up the remaining 0.5%.
However, these figures do not account for the variety of provincial generation mixes. Historic producers of coal, like Alberta (66.9%), Nova Scotia (58.2%), and Saskatchewan (54.8%) have come to rely mainly on coal-fired generating stations. In hydro-rich provinces, such as Manitoba (99.5%), Quebec (97.2%), Newfoundland and Labrador (97.1%), and British Columbia (88.7%), hydroelectric power accounts for the bulk of all electric generation.
In Canada's most populated province, Ontario Hydro has developed 11,990 MW of nuclear capacity between 1966 and 1993, building 20 CANDU reactors at 3 sites: Pickering, Darlington and Bruce. New Brunswick and by extension, Prince Edward Island, which buys 96% of its power from the neighbouring province, has a diversified mix, including a nuclear reactor and hydroelectric dams. However, the province is dependent on expensive fuel oil generation.
The electrical generating capacities of the provinces and territories in Canada are broken down below. Numbers are given in megawatts (MW) and gigawatt-hours (GWh). The tables below use 2010 data from Statistics Canada.
Utilities generation by fuel.
Note: Ontario eliminated coal in 2014.
Electricity per person and by power source.
In 2009 the Canadian production of electricity was 18,566 kWh per person and domestic use about 94% of production (17,507 kWh/person). In 2008 the OECD average was 8,991 kWh/person. 64.5% of Canadian domestic electricity use was produced with the renewable sources. The non renewable electricity use, i.e. fossil and nuclear, in Canada in 2009 was 6,213 kWh/person, respectively in UK 5,579; Germany 5,811; Denmark 4,693; Spain 4,553; Finland 11,495 and the United States 12,234.
Transmission.
The Canadian transmission networks extend over . The grids generally follow north-south orientations since most population centres in Canada are concentrated in southern regions along the American border while the largest hydroelectric and nuclear projects are located in sparsely inhabited areas to the north. This particular situation forced Canadian utilities to innovate. In November 1965, Hydro-Québec commissioned the first 735-kV AC power line linking the Manic-Outardes project to the Lévis substation. In 1972, Manitoba Hydro connected generating stations part of the Nelson River Hydroelectric Project to the Winnipeg area through a high-voltage direct current power line, the Nelson River Bipole.
The Canadian transmission networks are largely integrated to the US power grid. There is greater integration and trade with the US than there is between Canada's provinces. The transmission utilities of provinces sharing a border with the United States are taking part in regional reliability organizations such as the North American Electric Reliability Corporation (NERC); the Maritime provinces, Quebec and Ontario are part of the Northeast Power Coordinating Council (NPCC) with utilities in New England and in New York State, Manitoba participates in the Midwest Reliability Organization (MRO), while Alberta and British Columbia are linked to the Western Electricity Coordinating Council (WECC).
Utilities across Canada are making large investments in the maintenance of ageing infrastructure and in the construction of new power lines and substations to connect new generation sources to the bulk power system. For instance, in 2009 Ontario spent $2.3 billion on a series of transmission projects aimed at connecting new renewable capacity fostered by the Green Energy Act. In Alberta, the AESO recommended in 2008 the construction of a $1.83 billion, 240 kV looped system in the southern part of the province to integrate up to 2,700 MW of new wind generation. In Quebec, Hydro-Québec TransÉnergie filed a $1.47 billion investment plan to connect 2,000 MW of new wind generation scheduled to come on-stream between 2011 and 2015.
Rates.
As of February 2020, the average residential cost of electricity in Canada was $0.174/kWh, and $0.135/kWh if excluding the territories, based on a monthly usage of 1,000 kWh.
Provinces.
Alberta.
Alberta was the first Canadian province to implement a deregulated electricity market. The market was established in 1996, following the adoption of the "Electric Utility Act", the year before. Local distribution utilities, either investor- or municipally owned, retained the obligation to supply and the 6 largest utilities were assigned a share of the output of existing generators at a fixed price. The province moved to full retail access in 2001 and a spot market, under the Alberta Electric System Operator, was established in 2003. After consumers complained about high prices in 2000, the government implemented a Regulated Rate Option (RRO), as a means to shield consumers from price volatility.
The generation sector in Alberta is dominated by TransAlta, ENMAX, and Capital Power Corporation, a spin-off of Edmonton's municipally owned company EPCOR. Although 5,700 MW of new generation was added and 1,470 of old plants were retired between 1998 and 2009, coal still accounted for 73.8% of utility-generated power in 2007, followed by natural gas, with 20.6%.
Installed capacity reached 12,834 MW in 2009, with coal (5,692 MW) and natural gas (5,189 MW) representing the bulk of the province's generation fleet. Recent additions to the grid have increased wind capacity to 657 MW, while hydroelectric capacity stands at 900 MW. Despite tougher new emission measures announced by the federal government in June 2010, industry officials believed the province will continue using coal to generate electricity into 2050. In November 2015, the government announced a coal phase-out by 2030. Syncrude's Mildred Lake and Aurora North Plant Sites, the coal fired Sundance Power Station and the coal fired Genesee Generating Station are the top three sources of greenhouse gases in Canada.
British Columbia.
BC Hydro was created in 1961 when the government of British Columbia, under Premier W. A. C. Bennett, passed the BC Hydro Act. This act led to the amalgamation of BC Electric Company and the BC Power Commission, and the creation of the British Columbia Hydro and Power Authority (BCHPA).
BC Hydro is the main electric distributor, serving 1.8 million customers in most areas, with the exception of the Kootenay region, where FortisBC, a subsidiary of Fortis Inc. directly provides electric service to 111,000 customers and supplies municipally owned utilities in the same area.
Between 1960 and 1984, BC Hydro completed six large hydro-electric generating projects, including the 2,730 MW W. A. C. Bennett Dam and Gordon M. Shrum Generating Station and Peace Canyon on the Peace River, Mica and Revelstoke on the Columbia River, Kootenay Canal on the Kootenay River and Seven Mile Dam, on the Pend d'Oreille River.
A third dam and 900 MW generating station on the Peace River, the Site C dam near Fort St. John, has been discussed for decades and was rejected in the early 1990s. In April 2010, the British Columbia government announced moving the project to a regulatory review phase. A notice of Site C construction commencing in 2015 was issued July 2015. Revelstoke Dam built in 1984 was the last new dam built by BC Hydro.
The province's Liberal government has promoted the construction of a slew of small-scale hydro projects by private businesses. As of April 2010, 63 long-term power purchase agreements have been signed with Independent Power Producers for 2,629 MW of capacity and 10.3 TWh of energy.
In 2015 Hydropower made up 87% of total generation, the rest being biomass, wind and some natural gas.
BC Hydro via Powerex trades electricity eastward with Alberta and south to all of the western US through the Pacific-Intertie. In 2014 BC had the largest volume of electricity imports in Canada (9700 Mwh), from the Western Interconnection in the US which is 60% fossil fueled. BC Hydro typically imports power during off-peak hours when thermal plants in the US and Alberta have excess power for sale, Then exports hydropower during peak hours when prices are higher.
Manitoba.
Manitoba Hydro is the crown corporation in charge of electricity generation, transmission and distribution in Manitoba. Its installed capacity stands, as of 2015, at 5,701 MW, mostly generated at 15 hydroelectricity generation stations on the Nelson, Saskatchewan, Laurie and the Winnipeg Rivers.
The company has completed the 200-MW Wuskwatim hydroelectric project in partnership with the Nisichawayasihk Cree Nation, with first power from the project in June 2012. By advancing the completion date of the project by 3 years, Manitoba Hydro hopes to cash in on lucrative exports in the Midwestern United States. The utility is currently building a new 695 MW station at Keeyask on the Nelson River, expecting completion in 2019.
The utility has completed the construction of a third HVDC power line linking northern Manitoba and the Winnipeg area. The Bipole III project involves the construction of a 1,364 km power line and two new converter stations. With Keeyask under construction, Manitoba Hydro has also undertaken studies of one more large hydroelectric project, the Conawapa generation station.
New Brunswick.
New Brunswick has a diversified generation mix, featuring fossil fuel, hydroelectric and nuclear capacity. Established in 1920, the provincial utility, NB Power owned 3,297 MW of installed capacity as of March 31, 2008. Since then, the company retired 2 power plants and plans to permanently shut down the 300-MW oil-fired Dalhousie generating station.
In the last decade, the government-owned utility has faced problems with the failure of a plan to switch two of its large thermal facilities to Orimulsion, a heavy bitumen fuel produced by PDVSA, the Venezuelan government oil company, and a 2-year delay in the mid-life refit of the Point Lepreau Nuclear Generating Station.
In October 2009, the provincial government signed a memorandum of understanding with Quebec to sell most of NB Power's assets to Hydro-Québec. The controversial deal was cancelled in March 2010.
Since then, a couple of options are discussed to modernize New Brunswick electricity infrastructure, including a plan to build a 500-MW intertie with Nova Scotia and a preliminary agreement with France's Areva to evaluate the feasibility of a second nuclear generating station at the Point Lepreau site. However, the nuclear expansion plan was shelved within hours of the election of a Progressive Conservative government led by David Alward in September 2010.
Newfoundland and Labrador.
Newfoundland and Labrador Hydro, a subsidiary of government-owned Nalcor Energy, has an installed generating capacity of 7289 MW and is the fourth largest of all utility companies in Canada. It owns and operates most generation in the province, the transmission grid and sells directly to large industrial customers. The company also serves remote communities not connected to the main power grids, on Newfoundland and in Labrador.
Newfoundland Power, a subsidiary of St. John's-based Fortis Inc., is a regulated distributor serving 239,000 customers, making up 85% of all electricity consumers in the province. The company buys 90% of its energy from Newfoundland and Labrador Hydro.
Newfoundland and Labrador mainly relies on hydropower for its generation needs, supplemented by the 500-MW Holyrood Thermal Generating Station, near St. John's. The province's main power station, the 5,428-MW Churchill Falls Generating Station, was commissioned between 1971 and 1974. The generating station is owned by the Churchill Falls Labrador Corporation Limited, a joint venture between Newfoundland and Labrador Hydro (65.8%) and Hydro-Québec (34.2%). Most of the output of the plant is sold at a fixed price to the Quebec utility under a 65-year power purchase agreement due to expire in 2041.
The Lower Churchill Project is a planned hydroelectric project in Labrador, to develop the remaining 35 per cent of the Churchill River that has not already been developed by the Churchill Falls Generating Station. The Lower Churchill's two installations at Gull Island and Muskrat Falls will have a combined capacity of over 3,074 MW and have the ability to provide 16.7 TWh of electricity per year. The Muskrat Falls Generation Facility will consist of a dam, a spillway, and a powerhouse with four Kaplan turbines and a total generating capacity of 824 MW. Construction of the Muskrat Falls Generation Facility began in 2013 and is expected to be complete in 2019.
Nova Scotia.
Nova Scotia Power Inc. (NSPI), a subsidiary of Halifax-based Emera, is the public utility in charge of the generation, transmission and distribution of electricity in Nova Scotia. Formerly a government-owned company, it was privatized in 1992 by the conservative government of premier Donald Cameron, in what was called at the time the biggest initial public offering (IPO) in Canadian history. From the $816 million proceeds, "$616 million was used to recapitalize Nova Scotia Power by paying down debt owed by the utility".
NS Power has a generating capacity of 2,293 MW: 5 thermal plants fired with a mix of coal, petroleum coke, fuel oil and natural gas, provide the bulk of the 13 TWh yearly supply. The company also operates the Annapolis Royal Tidal Generating Station, the only one of its kind in North America and 33 hydroelectric generating stations, most of them small ones, with the exception of the 230 MW Wreck Cove Generating Station, inaugurated in 1978.
Over the years, NS Power has been blamed by Nova Scotia residents for its poor maintenance record and its failure to quickly reconnect customers after storms. In September 2003, 700,000 Nova Scotia residents were without power for up to two weeks after the passage of Hurricane Juan. The Category 2 storm damaged 27 main transmission lines, several transmission towers, 117 distribution feeders, and 31 major electrical substations. More recently, the issue of the company's investment in the provincial grid has been raised at a leaders' debate during the 2009 election campaign. The company received praise from premier Darrell Dexter for its efforts in restoring power after the passage of Hurricane Earl in September 2010.
"For information on the small utility cooperative of Riverport and public utility electric distributors (of Lunenburg, Mahone Bay, Antigonish, Berwick and Canso) see those towns' main articles. For information on their cooperative see Municipal Electric Utilities of Nova Scotia."
Ontario.
Electricity is generated in Ontario from nuclear power, hydroelectric power, natural gas and renewables such as wind, solar and biomass. Total production in 2017 was 132.1 TWh (i.e. 132.1 billion kWh.) The various sources of generation used in 2017 are shown in the pie chart to the right. In April 2014, Ontario eliminated coal as a source of electricity generation. The generation mix for the current hour can be viewed at the Independent Electricity System Operator (IESO) webpage.
As noted above, total electricity production in Ontario 2017 was 132.1 TWh. Adding imports of 6.6 TWh and subtracting exports of 19.1 TWh leaves 119.6 TWh usage within Ontario. With an estimated 2017 population of 14,193,384, electricity usage per person in Ontario in 2017 was 9,307 kWh per year, or about 60% of the Canadian average shown in the table Electricity per person and by power source displayed earlier in this article. (Note that this number includes all use—commercial, industrial and institutional use as well as household use—and it is at the point of production, i.e. before subtracting transmission and distribution losses.) Usage per person in Ontario may be lower than the national average because natural gas is more widely available and has a significant cost advantage for heating.
Ontario has been considered a summer peaking grid since 2000, however due to particularly cold winter temperatures and moderate summer temperatures, Ontario was winter peaking in 2014. In its 18-Month Outlook issued September 2014, the Independent Electricity System Operator (IESO) predicts a winter 2014–2015 peak of 22,149 MW under a normal weather scenario, and a summer 2015 peak of 22,808 MW, also under a normal weather scenario. The all-time record for Ontario demand was set on August 1, 2006, when peak demand for electricity reached 27,005 megawatts. (See 2006 North American heat wave.)
Overall, Ontario is a net exporter of electricity. Ontario imports electricity, primarily from its neighbouring provinces of Quebec and Manitoba (both of which are primarily hydroelectric systems), and exports electricity, primarily to Michigan and New York State, which rely heavily on fossil fuels—coal in the case of Michigan, and natural gas in the case of New York.
In 2017, Ontario's gross exports were 19.1 TWh, i.e. roughly equal to half its hydro generation of 37.7 TWh in 2017. (Although Canada is the world's third-largest producer of natural gas, Ontario imports natural gas from the United States and from western Canada.) If all the carbon emissions associated with natural gas-fueled generation were allocated to the exports, almost all the electricity consumed within Ontario would be from non-carbon or carbon neutral sources. (Note however that the natural gas generation is not necessarily coincident with exports and natural gas plants sometimes need to be operated due to regional transmission constraints, and as backup for wind generation which is intermittent and somewhat unpredictable.)
Ontario embraced nuclear power in the 1970s and 1980s, building 3 major nuclear facilities and 18 CANDU reactors, which in 2013 provided 59% of the province's electricity production, or kilowatt-hours equal to 65% of the electricity consumed within the province. The completion of the Darlington Nuclear Generating Station in 1993, "at a cost several times the original estimates", caused huge rate increases and a reassessment of Ontario's electricity policy. Three major policy documents, the Advisory Committee on Competition in Ontario's Electricity System (1996), chaired by former federal minister Donald Macdonald, a government White Paper on electricity policy (1997) and the Market Design Committee report (1999) paved the way for a major overhaul of the industry.
In April 1999, Ontario Hydro was split into five successor companies: Ontario Power Generation (OPG), in charge of generation; Hydro One, a transmission and distribution utility; the Independent Market Operator, responsible for the operation of a deregulated wholesale electric market in the province; the Electrical Safety Authority and the Ontario Electricity Financial Corporation, in charge of the $38.1 billion stranded debt, derivatives and other liabilities of the former integrated public utility.
In 2001, OPG leased Canada's largest power plant, the Bruce Nuclear Generating Station to Bruce Power, a private consortium originally led by British Energy, reducing its share of the provincial generation market to 70%. The government opened the competitive market on May 1, 2002, but heat waves and droughts in the summer of 2002 caused wholesale prices to soar to peaks of $4.71/kWh in July and $10.28/kWh in September. Faced with bitter complaints from consumers, the Ernie Eves government announced a price freeze for small customers while leaving the wholesale market intact, on November 11, 2002.
Although Eves was praised for the pause in generation market deregulation the cancellation of Hydro One's initial public offering and his handling of the 2003 North American blackout, the Progressive Conservatives were defeated by Dalton McGuinty's Liberals in the provincial election of 2003. In the meantime, the phasing out of coal-fired generation — including North America's largest coal plant, the 3,640-MW Nanticoke Generating Station — became a political issue. In 2002, the Conservatives promised to shut down Ontario's 5 coal plants by 2015, while McGuinty committed to a 2007 retirement date, which was pushed back to 2014.
In April 2009, the Ontario legislature passed the Green Energy Act establishing feed-in tariffs for power from renewable sources and streamlining the approval process for new generation sites. Two months after passing the bill, Ontario announced the suspension of a competitive process for the purchase of 2 new nuclear reactors at Darlington, citing the price tag, later evaluated at $26 billion. Critics of the government strategy stress the Act will increase the price of electricity and undermine the system's reliability, while pitting some local residents against wind developers.
The impact of the Act has been notable in terms of the price impact on end consumers. Since 2009, electricity prices have risen by 95% for homeowners and by 115% for small businesses in the province of Ontario.
As of June 2018, Ontario's wind capacity stood at 4,412 MW. As of 2010, Ontario's wind capacity represented more than a third of Canada's total.
Prince Edward Island.
Prince Edward Island is the only Canadian province without a hydroelectric power station. The province is largely dependent on imported power from NB Power generation facilities in New Brunswick. Two submarine power lines provide more than 80% of the provincial load. Since the early 2000, the provincial government has promoted the province as a good place to set up wind farms.
Maritime Electric, a subsidiary of St. John's-based Fortis Inc., operates the integrated public utility serving most of the province, with the exception of the city of Summerside, which has been providing electric service to its residents since 1920. Both utilities own and operate diesel plants, used as peakers or during emergencies.
Electricity rates in Charlottetown are the highest of the 12 large Canadian cities surveyed by Hydro-Québec in its annual compendium of North American electricity rates. According to the document, a residential customer using 1,000 kWh per month would pay 17.29 cents/kWh, a rate two and a half times higher than the one paid by consumers in Montreal, Winnipeg or Vancouver.
In November 2009, Premier Robert Ghiz hoped to reduce the price of electricity while limiting atmospheric emissions by opening talks with the government of Quebec for a long-term supply agreement. Negotiations, with Hydro-Québec, and other suppliers, including current supplier NB Power, are ongoing.
Quebec.
The Quebec electricity sector is dominated by Canada's largest utility, government-owned Hydro-Québec. With an installed capacity of 36,810 MW, including 34,118 MW of hydropower, the utility generated and bought 203.2 TWh in 2009, almost one-third of all electricity generated in Canada. Benefiting from low generation costs, favorable interest rates and high export prices, Hydro-Québec paid $10 billion in dividends to the Quebec government between 2005 and 2009.
Since 2003, the company commissioned 8 new hydroelectric generating stations for a total of 2,343 MW and is currently building 6 new power plants: Eastmain-1-A (768 MW) and Sarcelle (150 MW) scheduled for 2012, and 4 generating stations on the Romaine River (1,550 MW) to be commissioned between 2014 and 2020. Hydro-Québec's latest strategic plan, released in 2009, outline a further 3,500 MW of new generation capacity, including 3,000 MW of additional hydro projects, to be built by 2035. The company's total investments in generation, transmission, distribution and energy efficiency for the 2009–2013 timeframe are expected to reach $25.1 billion.
Quebec also intends to increase its wind generation capacity. The government's 2006 energy strategy calls for the construction of 3,500 MW by 2015. Two calls for tenders initiated in 2003 and 2005 resulted in the signing of 22 20-year Power Purchase Agreements between Hydro-Québec and independent power producers, for a total capacity of 2,990 MW. A third one, geared at small-scale community- or First Nations-led projects, is expected to be completed by the end of 2010. The province got 99% of its electricity from renewable sources in 2013.
Saskatchewan.
In 2007, Saskatchewan produced 12,362 GWh of electricity through its coal-fired power plants, on a total generation of 20,278 GWh. SaskPower, the government-owned public utility is the main power generator in the province. The company has a generating capacity of 3,371 MW and 17 generating facilities. These include three coal-fired baseload facilities (1682 MW), five natural gas-fired plants (674 MW), seven hydroelectric developments (854 MW), and two wind farms (161 MW). Two independent power producers, the Cory and Meridian cogeneration stations have a combined capacity of 438 MW, while 5 waste heat facilities have a maximum output of 31 MW.
The current state of the electric system will require heavy investments in the next decade. Discussion have been undertaken with Manitoba about building a 138-kV interconnection between the two neighbouring provinces. A new privately owned natural gas-fired combined-cycle generation turbine in North Battleford is under construction. The 260-MW facility is expected to be completed in 2013.
Yukon.
Yukon Energy Corporation is the crown corporation that generates most of the power consumed in Yukon. Hydro is the main generation source, with a 93.2% share in 2007. It is supplemented by a wind turbine in Whitehorse and diesel generators in remote communities. Yukon has two separate grids. Neither are connected to the continental power grid. Yukon Electrical Company is the main distributor in Yukon.
In its "Energy Strategy", released in 2009, the Yukon government has stated it wants to increase the supply of renewable energy, hydro and wind, by 20%. The government is also considering linking Yukon's two main power grids by completing the Carmacks to Stewart transmission line. No timetable has been set.
Northwest Territories.
Although the Northwest Territories are not connected to the North American power grid, there are two electric networks operating in the territory, the first one in the Yellowknife area and the other in Fort Smith. In most communities, loads are served by local diesel generators.
The government-owned Northwest Territories Power Corporation is in charge of power generation, while Northland Utilities, a subsidiary of ATCO, operate the distribution networks.
Nunavut.
The government-owned Qulliq Energy Corporation is the only power generator serving the remote communities of Nunavut. Qulliq, operating under the name Nunavut Power, has a total of 27 diesel-powered generators, serving 25 communities. The territory is not connected to the North American power grid.
Qulliq Energy plans to build a small hydroelectric project at Jaynes Inlet, not far from the territorial capital, Iqaluit, which is currently served by two diesel generators. The 5-MW generating station, which could cost upwards of $200 million, has been delayed by lower oil prices and the financial crisis. Construction could start in 2015 or 2016.
Climate change.
in 2013, electricity generation was responsible for 105 Mt of carbon dioxide emissions, 20% of the nation's total, second only to transport at 32%. This represents an 18% reduction since 2005.
While Canada reduces the carbon footprint in the US by exporting 10% of total hydroelectricity, more than half of all Canadian homes and businesses burn natural gas for heat. Hydro power, nuclear power and wind generate 80% of Canada's electricity, coal and natural gas are burned for the remaining 20%.
As of 2008, Alberta's electricity sector was the most carbon-intensive of all Canadian provinces and territories, with total emissions of 55.9 million tonnes of equivalent in 2008, accounting for 47% of all Canadian emissions in the electricity and heat generation sector. It is followed by Ontario (27.4 Mt eq.), Saskatchewan (15.4 Mt eq.) and Nova Scotia (9.4 Mt eq.). Of all provinces, Quebec has the lowest carbon intensity in the electricity sector with 2.45 g of eq. per kWh of electricity generated.
Ontario registered a large drop in emissions in 2008, due to lower demand, natural gas prices and government instructions to Ontario Power Generation regarding a gradual decommissioning of coal-fired generation by 2014. According to the Independent Electricity System Operator of Ontario, 4,700 MW of new natural gas-fired generation and 1,100 MW of wind farms have been commissioned in the province between 2003 and 2009. The new natural gas capacity will allow Ontario to retire 2 units each at the Nanticoke and Lambton generating stations by the end of 2010, on track for a complete phase-out by the end of 2014.
In Alberta, TransAlta and Capital Power Corporation undertook the construction of a carbon capture and storage project at the 450-MW Keephills-3 supercritical sub-bituminous coal-fired power station. The project, which received a $770 million grant from the federal and provincial governments, involved storing the captured through geological sequestration and enhanced oil recovery. It was scheduled to be operational by 2015; however, the project was canceled in 2012. In March 2010, SaskPower has announced its own carbon sequestration project at the Boundary Dam Power Station, the province's largest coal plant. In British Columbia, the provincial government ordered BC Hydro to remove the 50-year-old gas-fired Burrard Generating Station from its roster of baseload plants.
International trade.
Some provincial hydro companies benefited a great deal from the liberalization of the United States electricity sector brought by the Energy Policy Act of 1992 and the Federal Energy Regulatory Commission's Order 888. New Brunswick, Manitoba, Ontario and Quebec have been net exporters while BC Hydro has created an energy marketing subsidiary to actively trade on the neighbouring electricity market.
In 2009, Canada exported more than 53 TWh of electricity — approximately 9% of its output — to its southern neighbour the United States, while it imported 18 TWh. While occupying a relatively small part of the overall U.S. market, Canadian supplies constitute a significant share of the power consumed in key markets, such as New England, New York State, Ohio, Michigan, Minnesota and the Pacific Northwest.
In August 2010, Hydro-Québec signed a 26-year renewal of its 225-MW power contract with the largest Vermont public utilities, Central Vermont Public Service and Green Mountain Power. To facilitate the deal, a new renewable energy law, H.781, was signed into law by governor Jim Douglas on June 4, 2010, after passage in both houses of the Vermont Legislature. The Act makes Vermont the first U.S. state to declare large-scale hydroelectric power as "a renewable energy resource".


Hokuriku Electric Power Company

The Hokuriku Electric Power Company supplies power by a regulated monopoly to Toyama Prefecture, Ishikawa Prefecture, the northern part of Fukui Prefecture, and northwestern parts of Gifu Prefecture. It is often abbreviated within its area of service, but out of that area the name can also refer to the Hokkaidō Electric Power Company so it is also shortened to .
Their headquarters are in Toyama, Toyama. Recently, Kei Takahara was adopted as their image character. They have also launched a campaign called .
Fuel mix.
In 2011 Rikuden's power generating mix in percentage of total output was as follows:
Power Stations.
In 2011 Rikuden had a total generating capacity of 8,058 MW (9,185 MW, including purchased or contracted capacity).
Thermal power stations.
Rikuden has 4,400 MW of generating capacity through its thermal generating stations through 6 fossil fuels powered stations.
Hydroelectric.
Rikuden has 1,905 MW of hydroelectric capacity through 128 separate generating stations.
Nuclear Power Plants.
Rikuden generates 1,746 MW of electricity from nuclear power.
Renewables.
Rikuden generates 7 MW electricity from renewable sources at 5 sites.


Brookfield Renewable Partners

Brookfield Renewable Partners L.P. is a publicly traded limited partnership that owns and operates renewable power assets, with corporate headquarters in Toronto, Ontario, Canada. It is 60% owned by Brookfield Asset Management.
As of the end of 2017, Brookfield Renewable owned over 200 hydroelectric plants, 100 wind farms, over 550 solar facilities, and four storage facilities, with approximately 16,400 MW of installed capacity.
Brookfield Asset Management claims to have "more than 100 years of experience as an owner, operator and developer of hydroelectric power facilities." It was founded in the 1890s in Brazil, where the company installed the first electrical lights and tramways in São Paulo and Rio de Janeiro.
Corporate structure.
The company was established as Brookfield Renewable Energy Partners in 2011, when Brookfield Asset Management combined the hydroelectric stations and wind farms of the Brookfield Renewable Power Fund with those of Brookfield Renewable Power Inc. The company changed its name to Brookfield Renewable Partners in 2016.
Brookfield Renewable Power fund.
Brookfield Renewable Power Fund originated as the Great Lakes Hydro Income Fund before changing its name in 2009. Brookfield used its majority stake in Great Lakes Power as its primary vehicle to advance its interests in the renewable energy sector. When Great Lakes Hydro Income Fund completed its initial public offering on the Toronto Stock Exchange in 1999, Brookfield Asset Management (then known as EdperBrascan) owned 61% of outstanding units through its various subsidiaries. Initially, Great Lakes Hydro's assets were limited to three hydroelectric facilities in Western Quebec with a combined capacity of 238MW. By the end of 2008, the fund owned and operated 27 hydroelectric facilities and one wind farm with a cumulative capacity of 1,021MW. These assets were spread across four jurisdictions: Ontario, Quebec, British Columbia, and New England.
Brookfield Renewable Power Inc..
Brookfield Renewable Power Inc. was a wholly owned subsidiary of Brookfield Asset Management with a 50.01% share in Brookfield Renewable Power Fund. It was the subsidiary in which Brookfield Asset Management held all of its renewable energy assets, whereas the Brookfield Renewable Power Fund's scope was limited to the 1,652MW of generation capacity located in Ontario, Quebec, British Columbia, and New England.
Brookfield Renewable Energy Partners, LP.
On September 13, 2011 Brookfield Asset Management and Brookfield Renewable Power Fund announced they intended to merge the Fund and the power generating assets owned by Brookfield Renewable Power Inc to form Brookfield Renewable Energy Partners, LP. When the transaction closed, Brookfield Asset Management owned 73% of the combined entity, which trades on the Toronto Stock Exchange under the symbol BEP-UN and on the New York Stock Exchange as BEP. The new entity is the primary vehicle through which Brookfield acquires and operates renewable energy assets, with initial assets, and development projects in Canada, the US, and Brazil. The transaction closed on November 30, 2011.
In 2012, the company and its investment partners bought four hydroelectric power plants in the southeastern U.S. from Alcoa for $600 million.
In 2014, the company and its investment partners acquired a portfolio of wind power assets in Ireland, establishing its presence in Europe for a total enterprise value of approximately $960 million.
In 2016, the company and its investment partners acquired a majority stake in Colombian power company Isagen, which operates Colombia's largest hydropower plant, for approximately C$2.8 billion. The company subsequently increased its interest to almost 100%.
On May 10, 2016 Brookfield Renewable Energy Partners L.P. changed its name to Brookfield Renewable Partners L.P. The stock symbol and CUSIP will remain the same.
In March 2017, the company announced it would acquire a controlling interest in TerraForm Power and 100% of TerraForm Global, together representing a 3,600 MW global renewable power portfolio. The transaction was completed in December 2017. In March 2020, the company announced it would be acquiring the remaining stake of TerraForm Power. The acquisition is set to be completed in Q3 2020.
On December 14, 2020 Brookfield Renewable Partners and its institutional partners will purchase a 1 GigaWatt-plus distributed generation (DG) solar platform from Exelon Corp in a deal worth USD 810 million.


Hydroelectric power in Colombia

With seventy percent of Colombia's power generation, hydroelectric power is a very important national energy source. The total large hydropower potential for Colombia is estimated at 93GW, with an additional 25GW of small hydropower (<20MW). However, the potential for large hydropower faces difficulties, as the best sites have already been developed, also due to the escalating environmental and social costs associated with large dams, and the likely impacts of climate change and climate variability on the hydrological regime of the country (drastic increases in surface temperature in the Andes, changes in precipitation patterns, and increases in the intensity and frequency of El Niño-Southern Oscillation (ENSO) signals driving prolonged periods of drought).
Proposed hydroelectric power plants.
The large hydropower plants to be built in Colombia up to 2010 are listed below:


Synex International

Synex International Inc. () is a Vancouver-based company that has traded on the Toronto Stock Exchange since 1987. It is made up of two wholly owned subsidiary companies: Synex Energy Resources Ltd. (the Energy Division) and Sigma Engineering Ltd. (the Engineering Division).
Operational projects.
Mears creek (4MW, 20GWh/yr)
BC Hydro awarded this project a 20-year Power Purchase Agreement in 2001. Construction began in June 2003 and the project was commissioned in January 2004. In its 2004 Annual Report, Synex listed the project’s capital cost as $6.6m.
Cypress creek (3MW)
BC Hydro originally awarded this project a Power Purchase Agreement in 2003. However, it did not become operational until July 2009, when it became the first project to take advantage of BC Hydro’s Standing Offer Program. Additionally, revenues are supplemented by the Government of Canada's $10/MWh ecoENERGY subsidy.
Barr creek hydro (4MW, 15GWh/yr)
This project was awarded a Power Purchase Agreement in BC Hydro's 2006 Open Call for Power and later qualified for the $10/MWh ecoENERGY grant. Construction began on the access roads to the project site in May 2010 and the project is expected to be operational in November 2011. In October 2010, Synex announced that it owns 90% of Barr Creek LP and the remaining 10% is owned by the Ehattshat First Nation, which has the option to purchase an additional 10% from Synex before Jan 2011.
Development projects.
McKelvie creek hydro (3.4MW, 14GWh/yr)
Originally, the McKelvie Creek project was awarded a PPA in the 2006 Open Call for Power. Development was stalled in July 2007, as due higher than anticipated costs required for interconnection with the grid pushed capital costs up from $10m to $15m. Synex later revealed that it was expecting to receive a new PPA for this project via BC Hydro’s Standing Offer Program. However, BC Hydro has barred projects that received PPAs in the 2006 and 2008 Call processes from participating in the Standing Offer Program.
Victoria lake hydro (9.5MW, 39GWh/yr)
This was one of three PPAs awarded to Synex in the 2006 Open Call for Power (the firm bid four projects in total). Located near Port Alice, this project has an estimated capital cost of $18m. In its Q3 2009 report, Synex stated that regulatory work was progressing on this project. However, the firm has not mentioned any further developments since that time.


HVDC Cross-Channel

The HVDC Cross-Channel () is the name given to two different high-voltage direct current (HVDC) interconnectors that operate or have operated under the English Channel between the continental European and British electricity grids.
The first Cross-Channel link was a 160 MW link completed in 1961 and decommissioned in 1984, while the second was a 2,000 MW link completed in 1986.
The current 2,000 MW link, like the original link, is bi-directional and France and Britain can import/export depending upon market demands.
160 MW system (1961).
The first HVDC Cross-Channel scheme was built by ASEA and went into service in 1961 between converter stations at Lydd in England (next to Dungeness Nuclear Power Station) and Echinghen, near Boulogne-sur-Mer, in France. This scheme was equipped with mercury-arc valves, each having four anodes in parallel.
In order to keep the disturbances of the magnetic compasses of passing ships as small as possible, a bipolar cable was used. The cable had a length of and was operated symmetrically at a voltage of ±100 kV and a maximum current of 800 amperes. The maximum transmission power of this cable was 160 megawatts (MW). The cable was built by ABB Group. Given that the cable was laid on the surface of the seabed it was prone to being fouled by fishing nets, causing damage. Whilst repairs were undertaken there was considerable down time on the circuit resulting in a loss of trading. Indeed, by 1984 the circuit was disconnected from the Main Transmission System.
2000 MW system (1986).
Because the first installation did not meet increasing requirements, it was replaced in 1975–1986 by a new HVDC system with a maximum transmission rating of 2,000 MW between France and Great Britain, for which two new converter stations were built in Sellindge, between Ashford and Folkstone in Kent (UK) and in Bonningues-lès-Calais (Les Mandarins station), near Calais, (France). Unlike most HVDC schemes, where the two converter stations are built by the same manufacturer, the two converter stations of the 2,000 MW scheme were built by different manufacturers (although both have subsequently become part of the same parent company, Alstom). The Sellindge converter station was built by GEC and the Les Mandarins converter station was built by CGE Alstom.
This HVDC-link is long in route, with between the two ends. The undersea section consists of eight long 270 kV submarine cables, laid between Folkestone (UK) and Sangatte (France), arranged as two fully independent 1,000 MW Bipoles, each operated at a DC voltage of ±270 kV. Cables are laid in pairs in four trenches so that the magnetic fields generated by the two conductors are largely cancelled. The landside parts of the link consist of 8 cables with lengths of in England, and in France.
In common with the 1961 scheme, there is no provision to permit neutral current to flow through the sea. Although each station includes an earth electrode, this is used only to provide a neutral reference, and only one of the two electrodes is connected at a given time so that there can be no current flow between them.
The system was built with solid-state semiconductor thyristor valves from the outset. Initially these were air-cooled and used analogue control systems but in 2011 and 2012 respectively, the thyristor valves of Bipole 1 and Bipole 2 were replaced by more modern water-cooled thyristor valves and digital control systems supplied by Alstom.
This system remains the world's largest-capacity submarine cable HVDC system.
In November 2016 during Storm Angus a ship dragging an anchor cut four of the eight cable components, reducing capacity by 50%. Repairs were completed by the end of February 2017.
The equipment occasionally faults, causing capacity to drop: in a bad year, this might happen several times. To maintain grid frequency and power, the National Grid has a variety of frequency response assets, of which market batteries are the first to respond.
Significance.
Since the commissioning of the 2,000 MW DC link in the 1980s, the bulk of power flow through the link has been from France to Britain. However, France imports energy as needed during the winter to meet demand, or when there is low availability of nuclear or hydroelectric power.
 imports of electricity from France have historically accounted for about 5% of electricity available in the UK. Imports through the interconnector have generally been around the highest possible level, given the capacity of the link. In 2006, 97.5% of the energy transfers have been made from France to UK, supplying the equivalent of 3 million English homes. The link availability is around 98%, which is among the best rates in the world. The continued size and duration of this flow is open to some doubt, given the growth in demand in continental Europe for clean electricity, and increasing electricity demand within France.