Electricity sector in Switzerland

The electricity sector in Switzerland relies mainly on hydroelectricity, since the Alps cover almost two-thirds of the country's land mass, providing many large mountain lakes and artificial reservoirs suited for hydro power. In addition, the water masses drained from the Swiss Alps are intensively used by run-of-the-river hydroelectricity (ROR). With 9,052 kWh per person in 2008, the country's electricity consumption is relatively high and was 22% above the European Union's average.
In 2013, net generated electricity amounted to 66.2 terawatt-hours (TWh). About 60% of Switzerland's electricity generation comes from renewable sources, most of it from hydro (56.6%), while non-hydro renewables supplied a small contribution of 3.4%. Nuclear contributed 37.6% to the country's electricity production and only about 2.5% were generated by fossil fuel based thermal power stations.
Consumption.
According to IEA the electricity use (gross production + imports – exports – transmission/distribution losses) in Switzerland was in 2004 60.6 TWh, (2007) 61.6 TWh and (2008) 63.5 TWh. In 2008 Switzerland consumed electricity per inhabitant 122% compared to the European Union 15 average (9,052 / EU15: 7,409 electricity use per inhabitant 2008, kWh/person) and 133% compared to the United Kingdom (2008: UK 372.19 TWh per 59.9milj. person and Switzerland 63,53 TWh per 7,71 milj.person).
Hydro power.
Hydroelectricity is by far the country's most important source of energy, and contributing more than half to its electricity generation. Hydro power is generally divided into conventional hydroelectricity (using a dam) and run-of-the-river hydroelectricity. In addition, pumped-storage hydroelectricity (PHS) plays an important role in Switzerland, being used in combination with base load power plants and to "green-washing" nuclear power from France.
Small hydro.
The "KEV remuneration" (see below) also applies to small-scale hydro power plants with nameplate capacities up to 10 megawatts.
Nuclear power.
There are four nuclear power plants, with a total of five operational reactors. In 2013, they produced 24.8 terawatt-hours (TWh) of electricity. Nuclear power accounted for 36.4% of the nation's gross electricity generation of 68.3 TWh
In addition, there are a number of research reactors in Switzerland, one of them at the EPFL.
In 2011, the federal authorities decided to gradually phase out nuclear power in Switzerland as a consequence of the Fukushima accident in Japan. In late 2013 the operator BKW decided to cease all electrical generation in 2019 in the Mühleberg plant
As of December 8, 2014, the National Council has voted to limit the operational life-time of the Beznau Nuclear Power Plant—which houses the oldest commercial reactor of the world—to 60 years, forcing decommissioning upon its two reactors by 2029 and 2031, respectively.
Non-hydro renewables.
Feed-in remuneration at cost (KEV).
The federal government adopted feed-in tariffs to offer a cost-based compensation to renewable energy producers. The feed-in remuneration at cost ("KEV", , , ) is the primary instrument for promoting the deployment of power systems using renewable energy sources.
It covers the difference between the production and the market price, and guarantees producers of electricity from renewable sources a price that corresponds to their production costs. The following renewable energy sources are supported by the KEV remuneration: distributed small hydro (with capacities up to 10 MW), solar photovoltaics, wind power, geothermal energy, biomass and biogas (from agriculture, waste and water treatment).
The KEV remuneration is financed by collecting a surcharge on the consumed kilowatt-hour of electricity. As in other countries, industries with a large electricity consumption are exempt from the surcharge, which has gradually been increased and stands at 1.5 cents per kWh as of 2014.
The remuneration tariffs for renewables have been specified based on reference power plants for each individual technology. Feed-in tariffs are applicable for 20 to 25 years, depending on the technology. In view of the anticipated technological progress and the increasing degree of market maturity of renewables energy technologies (especially for solar PV), the feed-in tariffs are subjected to a gradual reduction once or twice a year. These reductions only apply to new production facilities that are put into operation.
Planned installations of renewable power facilities have to be registered with Swissgrid, the national network operator. As of the end of 2014, a growing waiting list for solar photovoltaic systems has accumulated as demand excess the capped capacities given by the currently available funds of the KEV remuneration.
Wind power.
Swiss wind power accounted for only 89 GWh or 0.1% of net-electricity production in 2013.
Solar power.
For many years, Switzerland's pace of deploying solar PV had been lagging significantly behind its neighboring Germany and Italy. However, installed capacity of solar PV increased by 300 MW or 69% to 737 MW in 2013 and is likely to continue its strong growth due to the recently ramped up KEV funds. In 2014, another installed 320 MW brought the country beyond the gigawatt mark and the IEA-PVPS estimates the now installed capacity sufficient to supply close to 2% of the domestic electricity demands.
Geothermal power.
An induced seismicity in Basel led the city to suspend a geothermal energy project and conduct a seismic hazard evaluation, which resulted in its cancellation in December 2009.
Global warming.
Emissions of carbon dioxide in total, per capita in 2007 were 5.6 tons CO2 compared to EU 27 average 7.9 tons CO2.
Carbon dioxide emissions.
A study published in 2009 showed that the emissions of carbon dioxide () due to the electricity consumed in Switzerland (total: 5.7 million tonnes) are seven times higher than the emissions of carbon dioxide due to the electricity produced in Switzerland (total: 0.8 million tonnes).
The study also show that the production in Switzerland (64.6 TWh) is similar to the amount of electricity consumed in the country (63.7 TWh). Overall, Switzerland exports 7.6 TWh and imports 6.8 TWh; but, in terms of emissions of carbon dioxide, Switzerland exports "clean" electricity causing emissions of 0.1 million tonnes of and imports "dirty" electricity causing emissions of 5 million tonnes of .
The electricity "produced" in Switzerland generated 14 grammes of per kilowatt hour. The electricity "consumed" in Switzerland generated 100 grammes of per kilowatt hour.
Power stations.
In Switzerland, there also exists a single-phase AC grid operated with 16.7 Hz for power supply of railway lines, see List of installations for 15 kV AC railway electrification in Germany, Austria and Switzerland.


Mercury Energy

Mercury NZ Limited is a New Zealand electricity generation and electricity retailing company. All of the company's electricity generation is renewable. It owns and operates nine hydroelectric generating stations on the Waikato River and five geothermal plants in the Taupo area.
In 2015, the company under the Mighty River Power brand generated 17% of the country's electricity. In 2017, Mercury had a 19% share of the New Zealand retail electricity market.
History.
Mercury NZ Ltd.
Mercury NZ Limited was formed in 1994 by the Auckland Energy Consumer Trust to own and run the electricity supply business previously operated by the community-owned local authority, Auckland Electric Power Board. In 1998, law changes obliged AEPB to sell the electricity retailing and generation part of the business.
Following the 1998 Auckland power crisis Mercury's electricity retailing division was sold to Mighty River Power, which was then a wholly state-owned SOE. Mighty River Power's retailing division continued the former trading name Mercury Energy. The electricity distribution business, Mercury Energy Limited, changed its name to Vector Limited and continued the distribution and transmission operation.
Mighty River Power.
Mighty River Power was established on 1 April 1999, when the 1998 reform of the electricity sector took effect. The Electricity Corporation of New Zealand (ECNZ) was broken up into three state-owned generating companies - Mighty River Power, Genesis Energy and Meridian Energy. Mighty River Power took over the ownership and operation of the eight hydroelectric power stations on the Waikato River, New Zealand's longest, and also inherited the assets of two largely decommissioned oil-fired power stations at Marsden Point, near Whangarei.
In addition, the 1998 reforms forced the separation between lines (transmission and distribution) and supply (generation and retailing). On 1 April 1999, Mercury Energy, then the major lines and supply company for Auckland, New Zealand's largest city, was split between lines and supply. Mighty River Power inherited Mercury Energy's retail base and its share in the Southdown Power Station (in conjunction with the Natural Gas Corporation). Mercury Energy then became the name of Mighty River's retail business, and the sub-transmission and distribution business of Mercury Energy was renamed Vector.
In 2000, Mighty River purchased into the Rotokawa geothermal power station, to operate and maintain the station, and own the geothermal turbines in a joint venture with the Tauhara North No.2 Trust. Also that year, Mighty River Power commissioned the Mokai geothermal power station in a joint venture with the Tuaropaki Trust.
In September 2002, Mighty River gained 100 percent ownership of the Southdown power station.
In 2004, Mighty River announce plans to refurbish the Marsden B plant to fire it on coal to increase supply security north of Auckland. Marsden B had been mothballed since it was completed in 1978 due to rising oil prices following the 1973 oil crisis and there being cheaper alternatives available. Greenpeace staged a nine-day occupation of the site in 2005, and after the Northland Regional Council granted consent, appealed to both the Environment Court and High Court, eventually overturning the consent. Mighty River appealed the High Court decision to the Court of Appeal, but in March 2007 dropped the proposal.
In 2008, Mighty River increased its generating capacity by opening the 100 MW Kawerau geothermal power station, increasing supply security to the eastern Bay of Plenty, a large timber processing area. In 2010, it opened the 140 MW Nga Awa Purua geothermal station near Taupo, complete with the largest single-shaft geothermal turbine in the world. The commissioning of Nga Awa Purua increased Mighty River's geothermal capacity to 385 MW, becoming the nation's largest geothermal electricity generator with 52.7 percent of all installed geothermal capacity.
Partial privatisation.
In December 2011, the National Government announced plans to reduce its shareholding in Mighty River Power, as well as in the three other state-owned energy companies, from 100 percent to 51 percent and to sell off the remaining 49 percent as part of its controversial "mixed-ownership model" plan. Mighty River Power was to be the first company to be partially sold in September 2012, pursuant to legislative changes and market conditions. However, threatened legal action and unfavourable market conditions saw the government delay any sale until March 2013 at the earliest.
The Government began taking registrations of interest from the public in Mighty River Power shares on 5 March 2013. More than 35,000 people tried to register in the first six hours, causing the registration website to crash for much of the day. By midnight, more than 90,000 people had registered.
In anticipation of the sale, in April 2013 State Owned Enterprises Minister Tony Ryall said director fees would be increasing from $49,000 a year to $85,000, and the chair's fees from $98,000 to $150,000, despite still being majority-owned by taxpayers.
The Financial Markets Authority approved the sale of Mighty River Power on 12 April, with the initial public offering (IPO) opening on 15 April. However, the IPO was temporarily suspended on 22 April while a supplementary disclosure was issued, after the Labour and Green parties in opposition announced plans to reform the electricity market if elected to government at the 2014 election. At the close of the IPO on 5 May, there were 113,000 shareholders, and on 8 May the opening share price was set at $2.50, raising $1.7 billion. The Government was slightly disappointed, blaming the Labour-Green policy for putting off many more potential shareholders, and with the Finance Minister indicating before the policy was announced that the price would be in the $2.70 to $2.80 range. The government retained 51.78 percent of the shareholding, with another 1.02 percent owned by other Crown interests (mainly the New Zealand Superannuation Fund).
By September, shares had slumped to $2.16, well below the float price, and in October the company announced it would be buying back up to $50 million in shares. By November 2015, the share price had exceeded the listing price, at $2.88.
The gas fired Southdown Power Station, a 170 MW combined cycle power station in south Auckland was closed in December 2015.
Name change.
The company changed its name to Mercury NZ Limited on 29 July 2016, after merging its retail and generation businesses. The company also launched a new brand logo, moving from the Roman god Mercury, to a bee. Market research showed New Zealand had a stronger connection to the bee as a symbol.
Power stations.
Mercury operates 13 power stations, all in Auckland, Waikato, and the Bay of Plenty. In total, the company has 1638 MW of generating capacity - composed of 1078 MW hydroelectric, 385 MW geothermal, and 175 MW natural gas.
Acquisition of Wind Farms from Tilt Renewables.
In 2021 Mercury partnered with Powering Australian Renewables (PowAR) to enter into a Scheme Implementation Agreement (SIA) with Tilt Renewables Limited. Under the terms of the transaction, PowAR will acquire all the shares of Tilt (including Mercury’s shares) for NZ$8.10 per share, and Mercury will acquire all of Tilt’s New Zealand operations, including its future development options.
In addition to Tilt shareholder approval, the Scheme is conditional on High Court approval, and regulatory approvals but the deal is expected to be finalized by August 2021 – the assets acquired will be:
Subsidiaries.
In addition to its generation assets, Mercury also incorporates or has major shareholdings in:


Intermountain Power Agency

The Intermountain Power Agency, located in Utah, is a power generating cooperative of 23 municipalities in Utah and 6 in California. It owns the Intermountain Power Plant near Delta, Utah, one of the largest coal-fired power plants in the United States. About 75 percent of the generated power is purchased by cities in southern California and the remainder is purchased by cities, cooperatives and Pacificorp in Utah and a cooperative in Nevada. The IPA also runs transmission lines to Mona, Utah, to Adelanto Converter Station in Adelanto, California and near Ely, Nevada.
In 2010 the IPA and the Utah Associated Municipal Power Systems filed a lawsuit against the Los Angeles Department of Water and Power for trying to prevent a third coal-fired unit at the IPP generation site due to carbon dioxide emissions concerns. The plant is scheduled to be converted to natural gas by 2025 at a cost of $500 million.
Cooperative partners.
Cooperative partners of the Intermountain Power Agency include the following:


Aboitiz Power

Aboitiz Power Corporation also known as Aboitiz Power (AP), a subsidiary of Aboitiz Equity Ventures (AEV), is a holding company engaged in power distribution, generation and retail electricity services.
Background.
Aboitiz Power Corporation was established on February 13, 1998. The company is AEV's largest subsidiary, contributing 71% of its total income in the first three months of 2019, and holds all of its assets in generation and distribution of electricity. The company's power generation unit is engaged in operations of solar, coal, oil, hydroelectric, and geothermal facilities.
On July 16, 2007, it became a publicly-listed company on the Philippine Stock Exchange with an initial public offering of 1.8 billion shares out of 7.2 billion registered common shares.
The company established the SN Aboitiz Power (SNAP), a joint venture with Norway-based company SN Power Invest AS, in 2005 with the goal of producing renewable energy. It introduced the floating solar farm, the method of putting solar panels on a body of water to lessen land use, in Tawi-tawi and Magat Dam in Isabela.
In April 2019, the Philippine Competition Commission (PCC), Energy Regulatory Commission, and the Senate Committee on Energy conducted separate probes on a series of power outages in Luzon that were said to be caused by alleged collusion among power firms as a way to increase electricity prices. Power companies denied the claim, and Aboitiz Power Corporation stated that the said outages were "bad for business" and they were open to any investigation. According to the Department of Energy, the outages were due to technical issues caused by old and new power plants, maintenance shutdown, and reduction of power rating of some facilities.
Subsidiaries.
The company's subsidiaries include Aboitiz Energy Solutions Inc., Davao Light & Power Co. Inc., Cotabato Light & Power Co., Hijos de F. Escaño, Inc., Pampanga Energy Ventures Inc., San Fernando Electric Light and Power Co., Subic Enerzone Corp., and Visayan Electric Co., Inc.


Electricity Commission (New Zealand)

The New Zealand Electricity Commission was a government authority set up in 2003 to regulate the electricity sector in New Zealand. It was succeeded by the Electricity Authority in November 2010.
The Commission was established under the Electricity Act to regulate the operation of the electricity industry and markets (both wholesale and retail) in accordance with government energy policy. The Commission was established following extremely dry hydro years in 2001 and 2003, which led to government concerns that the electricity market did not provide adequate security of electricity supply.
The first Electricity Commissioner was Roy Hemmingway, who was succeeded by David Caygill in 2007.


Gas turbine engine compressors

As the name suggests, gas turbine engine compressors provide the compression part of the gas turbine engine thermodynamic cycle. There are three basic categories of gas turbine engine compressor: axial compressor, centrifugal compressor and mixed flow compressor. A fourth, unusual, type is the free-piston gas generator, which combines the functions of compressor and combustion chamber in one unit.
Axial compressor.
Most high-compression jet engine use axial compressors for their high efficiency. In the axial compressor the air flows parallel to the axis of rotation. Axial compressor are made to be multi-staged. A stage consists of a row of rotating blades called the rotor, which are connected to the central shaft and a row of stationary or fixed blades called stator. In axial flow compressor, the air flows from stage to stage. The role of the rotor blades is the accelerate the incoming air for increasing the kinetic energy of the air.Then the fluid is decelerated across the stators and as a consequence the kinetic energy is converted into the pressure rise by the stators. Through the compressor, the flow area decreases and the blades get smaller and smaller from stage to stage and this compensates for the increase of air pressure and density, creating a constant axial velocity. In a axial compressors, there may be up to 20 stages between the air inlet and compressor outlet.
Centrifugal compressor.
The very first jet engines used centrifugal compressors and they are still used on small turbojets and turbo shaft engines.
The key component that makes a compressor centrifugal is the centrifugal impeller which contains a rotating set of blades. In a centrifugal compressor the airflow the airflow goes perpendicular to the axis of rotation. When the air passes through the rotating the rotating impeller it experiences force or word which is performed by centrifugal forces. Air is pushed toward the center and this radial movement of air results in a pressure rise and the generation of kinetic energy. Then the air passes through another key component of centrifugal compressor called diffuser section which responsibility is to convert the kinetic energy of the air into pressure rise by gradually slowing the air velocity. The diffuser is a fixed or static component that escorts the air flow after leaving the impeller. The impeller and the diffuser contributes about 65% and 35% of the total pressure produced in the centrifugal compressor restively.
Comparison between Axial and Centrifugal Compressor.
A typical, single-stage, centrifugal compressor can increase the pressure by a factor of 4. A similar single stage axial compressors can only increase the pressure by a factor of 1.2 but axial compressors have an advantage over centrifugal compressors because of their ability to have multiple stages. In the multi-staged compressors, the pressure is multiplied from row to row which can increase the pressure by a factor 40. It is much more difficult to preduce an efficient multistage centrifugal compressor because the flow has to be ducted back to the axis at each stage therefore most high-compression jet engines incorporate multi-staged axial compressors. But if only a moderate amount of compression is required a centrifugal compressor is much simpler and efficient to use.
Mixed-flow compressor.
In the future, mixed flow compressors may feature at the small end of the market, particularly in turbofans, where the relatively large diameter across the diffuser of a centrifugal compressor is a significant disadvantage.
Staged compression.
Two-stage.
At high overall pressure ratios, the compression system is usually split into two units; a low-pressure (LP) compressor mounted on one shaft followed by a high-pressure (HP) compressor mounted on the HP shaft and driven by its own (HP) turbine. On civil turbofans, the first stage of the LP compressor is often a single-stage fan. If the HP compressor pressure ratio exceeds about 4.5:1, then the unit will probably have variable geometry (i.e. variable stators) on the first few stages, to make the surge line on the compressor map more shallow, to accommodate the shallow working line.
Three-stage.
On their large civil turbofans, Rolls-Royce split the compression system into three: a fan, an intermediate-pressure (IP) compressor and an HP compressor, each unit being driven by its own turbine unit. The RB199 military turbofan also has this arrangement.
Free-piston gas generator.
A free-piston gas generator is a free-piston engine whose exhaust is used to power a gas turbine. It combines the functions of compressor and combustion chamber in one unit. These machines were quite widely used in the period 1930–1960 but then fell out of favour.


Solar power in South Africa

Solar power in South Africa includes photovoltaics (PV) as well as concentrated solar power (CSP).
In 2016, South Africa had 1,329 MW of installed solar power capacity.
Installed capacity is expected to reach 8,400 MW by 2030.
In 2014 several solar farms were commissioned, including the 96 MW Jasper Solar Energy Project, one of Africa's largest photovoltaic power stations providing enough solar power for 30,000 homes.
Government Programs.
As of 1 January 2016 the South African government gave a tax incentive through the South African Revenue Service for the installation of photovoltaic solar energy generation systems. Depending on the size defined in MWp (Megawatt peak) of the photovoltaic solar system, the amended section 12 B of the Income Tax Act No. 58 of 1962 stipulates the size of the tax shield available through accelerated depreciation to the commercial tax paying entity.
Photovoltaic solar systems smaller or equal to 1 MWp can be depreciated in one year, granting the commercial tax paying entity a 28% discount on the system.
The tax shield applies even if the photovoltaic solar system is installed mid-year or if the system is not new. A repayment time of one year and ongoing electricity savings for the remainder of the system's lifetime can be achieved by financing a portion of the cost of the system.
Photovoltaic solar systems greater than 1 MWp are depreciated with the schedule 50%, 30%, and 20% in the first 3 years respectively.
Adoption and Government Conflict of Interest.
Despite this aggressive tax incentive, South African companies are slow to adopt grid-connected photovoltaic solar systems due to the lack of public dialogue from the government concerning photovoltaic solar energy.
The lack of public dialog is partially due to the conflict that arises between the government, its state-owned enterprise Eskom, the local renewable energy sector as well as international obligations such as the Kyoto Protocol and the Paris Agreement of which South Africa is a signatory. The state-owned electricity utility Eskom that provides 90% (85% from coal) of South Africa's electricity and depends on electricity sales to function. Due to alleged corruption and mismanagement of funds in the years leading up to 2017, Eskom has been forced to increase tariffs by 340% over 10 years. Despite this tariff increase Eskom is in poor financial health as of 2017. The utility has stated that the increase in renewable energy generation directly impacts its revenue stream, which makes it difficult for it to meet its debt obligations. A government bailout has not been ruled out. The utility, relying mainly on coal-fired power stations also fears that renewable energy generation will directly impact coal jobs.
Through its holding in Eskom, the South African government is dependent on Eskom's revenue stream to avoid a bailout with public funds.
Municipal Programs.
In addition to the government tax incentive for photovoltaic solar energy generation, certain municipalities have further incentives for residential and commercial customers, such as a feed-in tariff or net metering.
Operational and projected plants.
The 50 MW Touwsrivier CPV Solar Project concentrated photovoltaics (CPV) power plant was constructed in Touwsrivier, in Western Cape, South Africa in December 2014. A 75 MW solar power plant started production on September 13, 2013 in Kalkbult, in the Northern Cape (implemented by Scatec).
Two other PV plants were completed by the same company in 2014. These are located at Linde in the Northern Cape and Dreunberg in the Eastern Cape, both sun drenched regions boasting some of the best conditions for solar power in the world. Altogether, these 3 plants provide power for around 90,000 South African households.
Sonnedix and Juwi have announced that they will construct an 86 MW solar photovoltaic (PV) plant in the Northern Cape province. The Mulilo Sonnedix plant in Prieska plant will be larger than any PV plant currently on line in the African continent, and was awarded through the third round of the South Africa's Renewable Energy Independent Power Producer Programme (REIPPP). Financial close on the project is targeted for July 2014, with commissioning planned for the second half of 2016.
Iberdrola has completed the Jasper Solar Energy Project solar photovoltaic (PV) power plant, which at 96 MW is the largest in Africa, the company announced. It was carried out in a desert area with extreme temperatures and involved the installation of over 325,000 PV modules. This PV plant is located in Northern Cape province in a remote, semi-desert location. It covers a surface area equivalent to 205 football pitches.
Acciona has put the Sishen solar photovoltaic (PV) plant into service in December 2014. It has a peak capacity of 94.3 megawatts (MWp) – 74 nominal MW – and is located in Dibeng in the Northern Cape province. Its horizontal tracking structures allow the PV panels to capture more radiation by following the sun's trajectory across the sky. The plant will produce electricity equivalent to the consumption of around 100,000 South African households, or around 420,000 people (2011 South African household size = 3.6 persons).
As of January 2015 a total of 593 MW produced from PV plants were connected to the grid.
A consortium led by ACWA Power International (Saudi Arabia) has completed commissioning of a 50 MW concentrating solar power (CSP) project in South Africa's Northern Cape in Dec-2015.
The Bokpoort CSP project includes 9.3 hours of thermal energy storage, which will allow it to meet demand during peak hours between 5 and 9 PM. ACWA describes this system as the largest thermal storage system ever built for a CSP plant of its size and capacity. The South African solar power plant has set a new African record (26 April 2016) for the continuous, round the clock supply of electricity.
Two CSP plants are being built by Abengoa in the Northern Cape. Khi Solar One is a Solar Tower plant of 50 MW capacity near Upington and Kaxu Solar One is a Parabolic Trough plant of 100 MW capacity near Pofadder with storage capability for 3 hours. Xina Solar One has a total installed capacity of 100 MW, also near Pofadder.
Solar Thermal Energy.
The South African government requires renewable energy to replace 10,000 GWh of electricity by 2013. The Department of Energy estimates that 23% of this target can be met through solar water heating and Eskom is therefore actively encouraging consumers to switch to solar water heating.
Residential Solar PV.
South Africa has experienced an increase in the installation of solar PV since 1992. The low electricity tariffs offered by Eskom prior to 2010 has led to a recently rapid installation increase. The shift in installations can be seen across all segments of consumers including industrial, agricultural, commercial and residential. There are predictions that indicate that there would be a continuous decline in the cost of Solar PV well beyond 2020.
The steady decline in solar PV and battery storage costs creates for an increasingly attractive business case to support self ownership with backup intervention and storage in the absence of grid-based power.  The statistics for the absorption of solar PV presently can barely be regarded as comprehensive or official considering the fact that they are based on industry estimates.
Installation numbers remain unclear because of the absence of an official or effective Small-Scale Embedded Generation (SSEG2) registration process for low-voltage connected customers. Although the National Energy Regulator of South Africa (NERSA) confirmed that they will be initiating a formal national registration process for SSEG, chances are they may only be fully operational in the next 2 to 3 years.
However, certain municipalities have initiated their own registration processes to allow connection to their distribution grid infrastructure. "The South African Department of Energy (DoE) has recently released Schedule 2 to the Electricity Act of 2006 which revised the licensing and registration requirements for categories of generators. In accordance with these new rules, generators smaller than 1MW are exempted from having to obtain a license but need to be registered with NERSA."
An approximately 285MWP5 (DC) of small scale solar PV (rooftop and ground-mounted) was installed in South Africa as at December 2017 according to the data received from different sources. The total number of installations equates up to 139,556 units. The installation of small to medium scale solar PV leads to a market share percentage of 0.65% of the total national generation capacity of 44.134GW6. "In addition to these grid-based installations, there are 87,150 off-grid systems with a total installed capacity of 14.35MWP."
Low and middle-income households have partially participated in the growing uptake of solar PV (SSEG) systems in South Africa for reasons pertaining to affordability and access to finance. Unlike most other countries where grid-connected solar PV technologies are released to low-income households mostly on full or partial subsidization, PV implementation initiatives of such kind in South Africa are targeted generally toward households lacking electricity.
Middle-income households with average earnings of $351.52 to $703.04 per month have better purchasing power. "They generally have improved security of tenure and greater access to electricity". Middle-income households consume twice as much electricity as low-income households. Although middle-income households earn more than twice the average monthly income of low-middle households, it would yet be difficult for the majority to qualify for the loan necessary to purchase a system.
Meanwhile, a South African residential solar PV company called WiSolar is said to be "providing solar financing to homeowners in South Africa in an effort to make rooftop Solar PV systems affordable for households across the country." The Wisolar "financing allows consumers to purchase their desired solar system through a six-year payment path to ownership." In June 2020, WiSolar had installed approximately 9MW of residential solar power in South Africa, providing enough clean power for 3000 homes.
In 2014, a multinational company by the name JA Solar Holdings which is headquartered in Beijing, China began working with local construction companies in South Africa to provide small-scale rooftop Solar PV systems to the suburbs of several South African cities. These systems were installed on the roof of low-income households. With these JA Solar systems, the house dwellers were able to have access to free electricity from their roofs.


Cinergy

Cinergy Corp. ( ) was an energy company based in Cincinnati, Ohio, United States, from 1994 to 2006. Its name is a play on the words "synergy", "energy", and "Cincinnati".
History.
Cinergy was created on October 24, 1994, from the merger of the Cincinnati Gas & Electric Company (CG&E) and Kentucky subsidiary Union Light, Heat & Power (ULH&P) with Plainfield, Indiana–based PSI Energy (Public Service Indiana).
Under its various operating names, the company operated a Holiday Model Train Display that has attracted over 9 million visitors since the event's inception in 1946. The authentic display measures long and imitates an O gauge, in which a quarter-inch on the model is equivalent to one foot on a real train.
In 1996, Riverfront Stadium in Downtown Cincinnati was renamed Cinergy Field in a sponsorship deal with Cinergy. The stadium was demolished by implosion in December 2002 to make way for Great American Ballpark.
In 2005, Cinergy announced a friendly acquisition by the larger Charlotte, North Carolina-based Duke Energy. The acquisition was completed on April 3, 2006. The combined company retains the Duke Energy name. Until the acquisition, Cinergy still operated under the names of the three local utilities (e.g., Cinergy/CG&E in Cincinnati); since the acquisition, the names of the three former Cinergy utilities and Duke Power, the former Duke Energy utility subsidiary, have been phased out, although signs bearing the former logos still remain at some substations. Duke, in partnership with railway company CSX, continued to host the annual train display in Cinergy's former headquarters until 2011, when the display was donated to the Cincinnati Museum Center at Union Terminal.
Environmental record.
In May 2006, Cinergy was fingered as a key contributor to major pollution in the American Midwest, prompting the New York State government to sue the company and forcing the company to install modern pollution control equipment. The Ontario government, across the border in Canada, followed suit at the request of New York Attorney General Eliot Spitzer.
Researchers at the University of Massachusetts Amherst have identified Cinergy as the 49th-largest corporate producer of air pollution in the United States, with roughly 29 million pounds of toxic chemicals released annually into the air. Major pollutants indicated by the study include sulfuric acid, hydrochloric acid, chromium compounds, and manganese compounds.


TTI, Inc.

TTI, Inc., is a distributor of electronic components that include capacitors, resistors, connectors, switches, relays, circuit protection, electromagnetics, discrete semiconductors, sensors, RF modules, and antennas.
The company was founded by Paul Andrews in 1971. A former buyer for General Dynamics, the global aerospace and defense company, Andrews developed an approach to electronic component distribution with emphasis on available-to-sell inventory, supply chain programs, and the industry’s first, formal Total Quality Management program.
Andrews served as Chief Executive Officer until his passing in February 2021. Subsequently, 40-year employee and Chief Operating Officer Mike Morton was promoted to the position of CEO.
Originally named Tex-Tronics, Inc., Andrews changed the name to TTI, Inc., in 1973 to avoid a legal dispute involving another company with a similar name.
Founded to serve aerospace and defense equipment manufacturers, the company’s customers now include manufacturers in the transportation, industrial, medical, and communications sectors.
TTI, Inc., and its wholly owned subsidiaries, also known as the TTI Family of Companies, Mouser Electronics, Sager Electronics and TTI Semiconductor Group employ over 7,000 people at more than 100 locations throughout North America, Europe and Asia.
TTI's global headquarters is located in Fort Worth, Texas, and maintains over 2,000,000 square feet of dedicated warehouse space globally, 1.2 million square feet of which is located in the Americas.
European headquarters is located near Munich, Germany; nearly 600,000 square feet of distribution capacity is maintained in Europe.
Asia headquarters is located in Singapore, with distribution centers in Hong Kong and China, totaling over 270,000 square feet of distribution capacity.
TTI has seven proximity warehouses located in Mexico: Tijuana, Hermosillo, Chihuahua, Juarez, Acuna, Reynosa, and Guadalajara, with a combined distribution capacity over 100,000 square feet.
TTI is a wholly owned, indirect subsidiary of Berkshire Hathaway Inc.
Relevant chronology.
TTI, Inc., entered the European market in 1992 with its first office in Munich, Germany. Since that time the company’s European reach has spread to over 40 countries. In 2008, TTI acquired the Mateleco Group, a large connector distributor in France, becoming the primary distributor in both passives and connectors in France.
TTI opened its first office in Asia in Singapore in 2000. Reach has since expanded to include three warehouses and 16 offices in 11 countries.
In 2000, TTI acquired Mouser Electronics, a broad-line catalog distributor based in Mansfield, Texas. Mouser is now a worldwide, authorized distributor of semiconductors and electronic components for over 700 industry manufacturers. The company focuses in the rapid introduction of new products and technologies for design engineers and buyers.
In December 2006, Paul Andrews agreed to sell majority ownership of TTI to Warren Buffett controlled Berkshire Hathaway. The acquisition was completed on March 30, 2007.
In 2012, Sager Electronics, a New England–based distributor with roots dating back to the 1800s, joined the TTI and Berkshire Hathaway family. Today Sager specializes in power products and services a North American customer base via headquarters in Middleborough, MA, and a national network of field account representatives and engineers, and a "Power Solutions Center" in Carrollton, TX.
TTI Israel was formally established in 2013 through the combined acquisitions of Net-Aye Components (acquired in 2010) and Ray-Q (acquired in 2013).
In 2015, Sager Electronics announced the formation of Sager Power Systems, a focused group within Sager specializing in power products and the design of power supplies.
Semiconductor distributor Symmetry Electronics was added to the TTI Family of Companies in 2017. Symmetry is a technical distributor of wireless, cellular, Bluetooth, embedded and video semiconductor technology.
In 2018, TTI acquired South Korean CHANGNAM, a specialty distributor of semiconductors principally focused on automotive, consumer electronics, industrial and wireless end markets, and RFMW Ltd., a RF and Microwave component distributor headquartered in Silicon Valley, California. Subsequently the company announced the formation of the new subsidiary, TTI Semiconductor Group.
Also in 2018, the company acquired Compona AG of Switzerland and Compona’s German subsidiary Cosy Electronics GmbH. Both Compona and Cosy are distributors of interconnect products and provide services such as in-house assembly of specific connector ranges and support on custom cable harnesses.
July 2019 Sager Electronics completed the acquisition of Technical Power Systems (TPS), a specialist in the production of custom battery assemblies, headquartered in Lisle, Illinois.
January 2020 TTI Semiconductor Group acquired Connected Development, a leading contract design firm specializing in wireless technology, headquartered in Cary, North Carolina.
Subsidiaries.
Subsidiaries include:
Acquisitions.
North America
Europe
Asia


Nigerian Bulk Electricity PLC

The Nigerian Bulk Electricity Trading (NBET) Plc. is the manager and administrator of the electricity pool (‘The Pool’) in the Nigerian electricity supply industry (NESI). It was incorporated on the 29th day of July 2010 and is 100% owned by the Federal Government of Nigeria.
In line with the “Roadmap to Power Sector Reform” of August 2010, and, in fulfillment of the requirements of EPSRA, the Nigerian Bulk Electricity Trading PLC, (NBET) aka the Bulk Trader, was incorporated on July 29, 2010 as the SPV for carrying out, under license from NERC, the bulk purchase and resale function contemplated by the EPSRA. As such NBET has been set up “engage in the purchase and resale of electric power and ancillary services from independent power producers and from the successor generation companies”
Background.
Nigerian’s deficient power sector supply has been a challenge that the past three presidential administrations have steadfastly sought to address. In 2001, the federal Government, in a bid to address the deficiency in power sector supply, adopted the National Electric power policy for the reform of the sector. Following suit, the Electric Power Sector Reform Act (EPSRA), was passed into law in March 2005. A key thrust of the sector from public to private sector. In furtherance of this goal, the Act saw the creation of the Power Holding Company of Nigeria (PHCN) which assumed the assets, Liabilities and employees of the erstwhile Nigeria Electricity Power Authority (NEPA); the subsequent unbundling of PHCN into 18 successor companies, the establishment of the Rural Electrification Agency (REA) and the provision for the establishment of two special purpose vehicles (SPVs) to undertake electric power trading and management of extant liabilities respectively
History.
NBET) was incorporated on July 29, 2010, in line with the "Roadmap to Power Sector Reform" and, in fulfillment of the requirements of Electric Power Sector Reform Act (EPSRA), 2005 for a "trading licensee holding a bulk purchase and resale license" to "engage in the purchase and resale of electrical power and ancillary services from independent power producers and from the successor generation companies".
On August 23, 2011, the President, Dr. Goodluck Ebele Jonathan, GCFR, inaugurated a nine-person Board of Directors that included Mr. Rumundaka Wonodi as its pioneer Managing Director and Chief Executive Officer (2011 - 2016).
NBET's power purchase agreements (PPAs) with independent power producers are backed by credit enhancement instruments offered by the FGN.
Objectives.
To put in place an effective transaction environment which minimizes risk and allocates it fairly to the parties best able to manage it
To implement a procurement process that is transparent and will result in the economic procurement of needed power
To have all existing and new power capacity under contract by 2016, although the commercial operation date when this capacity comes on line may be latter
To ensure efficient settlement in the short term until this function is subsumed under the Market Operator
To become sustaining as soon as practical thereby minimizing the cost to the FGN
To be ready to novate contracts and wind up as soon as the suppliers are ready to take on their own procurement
To enter into contracts that are well structured and managed in a manner that precludes recourse to any credit guarantee instrument
Services.
NBET purchases electricity from the Generating Companies through Power Purchase Agreements (PPAs) and sells to the Distribution Companies through Vesting Contracts. The Generating Companies include the privatized PHCN successor companies, the Niger Delta Power Holding Companies (NIPPs), the already existing Independent Power Producers (IPPs) and the new IPPs.
Our Top Priorities includes:
• Management and administration of the financial flows for the physical supplies on the network.
• Operation of a competitive market that encourages efficient value discovery for commodity and capacity.
• Promotion of a contracts-based market that allocates risks efficiently to parties responsible for them.
• Formulation and advisory on policies for efficient system settlement and least possible cost incentives for maintaining the transportation network within its acceptable energy, frequency responses and voltage tolerances.


ATCO Electric

ATCO Electric is an electric utility company. Based in Edmonton, Alberta, ATCO Electric transmits and distributes electricity to two thirds of Alberta, namely in north and east-central Alberta, as well as communities in Yukon and the Northwest Territories.
ATCO Electric is owned by Canadian Utilities, which is in turn controlled by ATCO, and its main subsidiaries are:


Nova Energy


Eraring Energy

Eraring Energy was an electricity generation company in Australia that was owned by the Government of New South Wales, and had a portfolio of generating sites using thermal coal, wind, and hydroelectric power. It was sold to Origin Energy in 2013.
Eraring Energy was established in 2000 under the and the .
Generation portfolio.
Eraring Energy owned and operated the following power stations to generate electricity for sale under contract:
Energy Reform Project.
Subsequent to the NSW Government releasing its Energy Reform Transaction Strategy in September 2009, a Direction was issued to Eraring Energy on 14 December 2010 by the Special Minister of State, to the Board to enter into a GenTrader Transaction Implementation Deed.
On 27 February 2011, Eraring Energy entered into Generation Trading Agreements (GTA) with Origin Energy as part of the New South Wales Government's energy reform process with changes to the business as follows:
On 25 February 2011 a Direction was issued by the Special Minister of State to transfer Eraring Energy’s shares in Rocky Point Holdings (responsible for the development of the Cobbora coal mine) to the Cobbora Holding Company Pty Limited, a separate NSW statutory corporation.
Under the agreements, Origin Energy has the right to trade the output of Eraring Power Station and Shoalhaven Scheme Power Stations and receive market revenue from these assets. In return, Eraring Energy receives a combination of fixed and variable monthly payments. In the event certain plant availability targets are not met, availability liquidated damages may be payable by Eraring Energy to Origin Energy.
Eraring Energy continues to operate the renewable assets of Hume Power Station, Burrinjuck Power Station, Brown Mountain Power Station, Keepit Power Station, Crookwell Wind Farm, and Blayney Wind Farm.
Asbestos liabilities.
Eraring Energy manages the liability for asbestos related illnesses arising from exposure to asbestos at former Electricity Commission of New South Wales and Pacific Power sites. These sites include de-commissioned power stations such as Bunnerong, Ultimo, White Bay, Pyrmont and Wangi Wangi. These liabilities are managed by Eraring Energy on behalf of the NSW Government.


Electricity sector in Colombia

The electricity sector in Colombia is dominated by large hydropower generation (65%) and thermal generation (35%). Despite the country's large potential in new renewable energy technologies (mainly wind, solar and biomass), this potential has been barely tapped. A 2001 law designed to promote alternative energies lacks certain key provisions to achieve this objective, such as feed-in tariffs, and has had little impact so far. Large hydropower and thermal plants dominate the current expansion plans. The construction of a transmission line with Panama, which will link Colombia with Central America, is underway.
An interesting characteristic of the Colombian electricity sector (as well as of its water sector) is a system of cross-subsidies from users living in areas considered as being relatively affluent, and from users consuming higher amounts of electricity, to those living in areas considered as being poor and to those who use less electricity.
The electricity sector has been unbundled into generation, transmission, distribution and commercialization since sector reforms carried out in 1994. About half the generation capacity is privately owned. Private participation in electricity distribution is much lower
Electricity supply and demand.
Supply.
Installed capacity.
Electricity supply in Colombia relies on the National Interconnected System (SIN) and several isolated local systems in the Non-Interconnected Zones (ZNI). SIN encompasses one third of the territory, giving coverage to 96 percent of the population. The ZNI, which covers the remaining two thirds of the national territory, only serves 4 percent of the population.
Thirty-two large hydroelectric plants and thirty thermal power stations feed electricity into the SIN. On the other hand, the ZNI is mostly served by small diesel generators, many of which are not in good working condition. At June 2015, installed net effective capacity was 15.5 Gigawatt (GW), with the following share by source:
The share of thermal participation in generation has increased since the mid-1990s. This has happened in response to the 1992/1993 crisis caused by El Niño-Southern Oscillation associated droughts and the high reliance of power generation on hydroelectric installations that lacked multi-year storage capacity. As a result of the new policies adopted by the country, the dominance of hydropower in the generation portfolio has been reduced from 80 percent in the early 1990s to less than 65 percent today. The expansion path involved adding 1,500 MW of new capacity, equally distributed between hydro and thermal sources, by 2011. This will entail investments of US$258 million per year.
Production.
Total electricity production in 2005 was 50.4 Terawatt-hour (TWh). Hydroelectric plants generated 81.2 percent, thermal plants 18.6 percent and the Jepírachi wind plant 0.1 percent of the total.
Demand.
In 2005, total electricity consumption was 48.8 TWh, which corresponds to an average energy consumption per capita of 828 kW·h per year. Consumption per sector is divided as follows:
Demand is growing by approximately 4 percent annually.
Imports and exports.
Colombia is a net power exporter. In 2005 the country exported 1.76 TWh of electricity to Ecuador (3.5% of total production). It imported only very small volumes of electricity from Venezuela and Ecuador (0.02 TWh each). According to the Ministry of Mines and Energy, exports are estimated to increase at 5 percent annually.
The Puebla Panama Plan includes a project of electric interconnection between Colombia and Panama that will allow the integration of Colombia with Central America. This project, carried out by Interconexión Eléctrica S.A. (ISA) in Colombia and Empresa de Transmisión Eléctrica S.A. (ETESA) in Panama, entails the construction of a transmission line with 300 MW capacity (3% of installed capacity) from Colombia to Panama and 200 MW capacity in the reverse way. The line is expected to become operational in 2010.
Access to electricity.
In 2005
, the interconnected electricity system served 87 percent of the population, a percentage that is below the 95 percent average for Latin America and the Caribbean. In Colombia, electricity coverage is 93 percent in urban areas and 55 percent in rural areas. About 2.3 million people do not have access to electricity yet.
As in other countries, the zones outside the interconnected system pose especially challenging conditions for electrification, as well major inadequacies in service provision. This system, whose installed capacity is almost exclusively diesel-based, suffers from major diseconomies of scale as 80 percent of capacity is in plants below the 100 kW threshold.
Service quality.
Interruption frequency and duration.
Service quality in Colombia, as measured by service interruptions, is much lower than the average for Latin America and the Caribbean. In 2005, the average number of interruptions per subscriber was 185.7, far above the regional average of 13 interruptions. The duration of interruptions per subscriber was 66 hours, also far above the regional average of 14 hours.
Distribution and transmission losses.
Losses in transmission and leaks are still a concern, even if the total amount has decreased in the last years. Distribution losses in 2005 were 16 percent, compared to 13.6% average in Latin America and the Caribbean (LAC).
Responsibilities.
Policy and regulation.
Colombia has had a liberalized energy market since 1995. The sector is characterized by an unbundled generation, transmission, distribution, and commercialization framework.
The structure of the Colombian energy market is based on Laws 142 (Public Services Law) and 143 (Electricity Law) of 1994. The Ministry of Mines and Energy is the leading institution in Colombia's energy sector. Within the Ministry, the Unit for Mining and Energy Planning (UPME) is responsible for the study of future energy requirements and supply situations, as well as for drawing up the National Energy Plan and Expansion Plan.
The Regulatory Commission for Gas and Energy (CREG) is in charge of regulating the market for the efficient supply of energy. It defines tariff structures for consumers and guarantees free network access, transmission charges, and standards for the wholesale market, guaranteeing the quality and reliability of the service and economic efficiency. Among others, CREG is responsible for providing regulations that ensure the rights of consumers, the inclusion of environmental and socially sustainable principles, improved coverage, and financial sustainability for participating entities.
The provision of public services (water, electricity, and telecommunications) to final users is supervised by the independent Superintendency for Residential Public Services, or SSPD.
Generation.
Colombia has 66 registered electricity producers. Private companies own 60 percent of the installed generation capacity and account for 43 percent (measured in number of consumers) to 49 percent (measured in kWh sales) of energy supplied to the interconnected grid.
Just three companies - the public companies Empresas Públicas de Medellín (EPM) and ISAGEN, as well as the private EMGESA - control altogether 52 percent of total generation capacity.
Transmission.
Transmission in the National Interconnected System is carried out by seven different public companies, four of which work exclusively in transmission (ISA, EEB, TRANSELCA and DISTASA). The remaining three (EEPPM, ESSA and EPSA) are integrated companies that carry out all the activities in the electricity chain (i.e. generation, transmission and distribution). The largest company is Interconexión Eléctrica S.A. (ISA), which belongs to the government.
Distribution and commercialization.
Currently, there are 28 pure commercializing companies; 22 distribution and commercialization ones; 8 ones that integrate generation, distribution and commercialization; and 3 fully integrated ones. The three largest players in commercialization are Unión Fenosa (with Electrocosta and Electrocaribe), Endesa (in Bogotá) and Empresas Públicas de Medellín (EPM).
Renewable energy resources.
Colombia has 28.1 MW installed capacity of renewable energy (excluding large hydro), consisting mainly of wind power. The country has significant small hydro, wind, and solar resources that remain largely unexploited. According to a study by the World Bank's Energy Sector Management Assistance Program (ESMAP), exploitation of the country's significant wind potential alone could cover more than the country's current total energy needs.
History.
Early history.
The first historical landmark in the establishment of electric supply dates back from 1928, when Law 113 declared the exploitation of hydroelectric power of public interest. The system worked in a centralized manner, in which vertically integrated state companies maintained a monopoly in their corresponding regions. A public company, ISA, exchanged electricity among the different regional systems.
During the 1980s, the sector suffered a crisis, similar to most countries in Latin America. The crisis was the result of subsidized tariffs, political influence in the state companies, and the delays and cost overruns of large generation projects.
1994 reforms.
At the beginning of the 1990s the government took steps to modernize the electricity sector, opening it to private participation. The restructuring was carried out through Laws 142 (Law of Public Services) and 143 (Electricity Law) of 1994, which defined the regulatory framework for the development of a competitive market. The new scheme, designed by the CREG, was implemented from July 1995 onwards.
Law 697 of 2001.
Colombia has an ambitious reform agenda in the power sector. The country seeks to encourage foreign investment, with an emphasis on hydrocarbons and power capacity expansion; simplify modalities for small-scale energy projects; and renew interest in non-conventional renewable energy technologies with a regulatory framework to facilitate a gradual change in the energy mix.
In 2001, Law 697, which promotes the efficient and rational use of energy and alternative energies, was promulgated. This law was regulated by Decree 3683, issued in 2003. The law and the decree contemplate important aspects such as the stimulus to education and research in renewable energy sources (RES). Nevertheless, the program created under this law lacks fundamental aspects to impulse the development of RES significantly, such as a regulatory support system to encourage investment, the definition of policies to promote renewable energy, or quantitative targets for the share of renewable energy.
Limitations such as the ones above present an important legal vacuum for renewable energy in Colombia. While there have been a few initiatives concerning efficient and rational use of energy (design of the Colombian program of normalization, accreditation, certification and labeling of final use of energy equipment, and promotion of carburant mixture for vehicle use and massive use of natural gas), there have been no recent initiatives related to new renewable energy technologies.
Tariffs and subsidies.
Tariffs.
The electricity market in Colombia has regulated and non-regulated segments. The regulated market, which is directly contracted and supplied by distribution companies, applies to industrial, commercial, and residential users with power demands under 0.5MW. In this market, the tariff structure is established by the regulatory agency CREG. In the non-regulated market, consumers with power demands of 0.5 MW and above can negotiate freely and contract their supply in the wholesale market (i.e., spot and contracts markets) directly or through commercial entities, distributors, or producers.
In 2005, the average residential tariff was US$0.0979 per kWh, slightly below the LAC weighted average of US$0.115. The average industrial tariff was US$0.0975 per kWh, slightly below the LAC weighted average of US$0.107.
Subsidies and cross-subsidies.
By law all urban areas in Colombia are classified in one of six socio-economic strata, which are used to determine the level of tariffs for electricity, water and other services. According to that system, consumers living in areas considered as poor - and consumers using low amounts of electricity - receive electricity and natural gas at subsidized tariffs. These cross-subsidies are almost entirely (approximately 98 percent) financed by consumers living in areas considered as being relatively affluent and who use more electricity. The cross-subsidies cover about 25 percent of the electricity and gas bill of low-income consumers. A special fund that covers the remaining amount not covered by consumers provided US$21.8 million in 2005. On average, 7.5 million people a month benefited from this fund. In addition, the fund provided subsidies of COP$ 17,159 million (US$7.4 million) to 1,808,061 natural gas users.
Subsidies are also given to provide diesel for power production in non-grid-connected zones. While diesel in the interior of the country can cost in the order of US$0.8/gal, in remote areas it can cost in the order of US$4.5/gal because of high transport costs.
The subsidy stratification system in Colombia has proven fairly ineffective at channeling subsidies towards the poor. Although the scheme is broad in its coverage and excludes no more than 2 percent of the poor for services with broad coverage such as electricity, water and sanitation, there are also high leakage rates. Some 50-60 percent of subsidy beneficiaries are from the top half of the income distribution and, moreover, only 30-35 percent of subsidy resources are captured by the poor. Nevertheless, the performance of this subsidy scheme varies depending on the service considered, being water the sector with the poorest performance and telephony the one with the best behavior.
Investment and financing.
Investment.
A 2004 report by the World Bank estimated the following power sector investment needs for Colombia up to 2010:
(1) Power Purchase Agreement
In summary, the overall investment needs in the electricity generation, transmission and distribution sector total US$767 million per year. About 60 percent of that relates to maintenance obligations and payment of Power Purchase Agreement (PPA) guarantees, and the remaining 40 percent to new investment in generation and transmission. These investment needs are completely related to the SIN and do not take into account the needs associated with the ZNI.
Financing of rural electrification.
There are three different funds and programs that support rural electrification in Colombia, each established at a different time with different purposes, and all administered by the Ministry of Mines and Energy. At the end of 2006, the Ministry of Mines and Energy had approved a total of US$23.3 million rural electrification funds from these three funds and programs directed to benefit 14,965 families.
The Fund for the Electrification of Non-interconnected Zones (FANZI), was established in 2000 to assist isolated regions in the zones outside the interconnected system. It contemplated both the expansion of existing networks and the establishment of stand-alone solutions.
In 2003, a special fund known as Rural Electrification Fund (FAER), of similar characteristics to the FAZNI, was established to subsidize investment in rural areas of the interconnected system. The fund was designed to collect a surcharge of US$0.40 per MWh of electricity sold to the wholesale market, which would yield approximately US$18 million per year. Projects are presented to the FAER by the local government authorities. In order to be eligible, they must form part of the local development plan and the investment plan of the corresponding distribution utility and must also pass through the national project screening and evaluation system.
Electrification projects also receive support from the Program for Network Normalization (PRONE) that draws its resources from the National Development Plan funds.
The Institute for the Investigation and Application of Energy Solutions (IPSE) supports the Ministry of Mines and Energy in its efforts to promote rural electrification.
Summary of private sector participation.
Colombia has had a liberalized energy market since 1995. The sector is characterized by an unbundled generation, transmission, distribution, and commercialization framework.
With 66 registered electricity producers, private companies own 60 percent of the installed generation capacity and account for 43 percent (measured in number of consumers) to 49 percent (measured in kWh sales) of energy supplied to the interconnected grid. Transmission is carried out by seven different public companies, while distribution and commercialization are in the hands of over 60 companies, both public and private.
Electricity and the environment.
Responsibility for the environment.
The Ministry of the Environment, Housing and Territorial Development holds the environmental responsibilities in Colombia and leads the country's commitment towards sustainable development. Within the Ministry, the Climate Change Mitigation Group addresses all the issues related with climate change.
Greenhouse gas emissions.
Because of Colombia's abundant hydroelectric potential, greenhouse gas emissions are very low per capita (1.3 te) and per unit of GDP (0.2 te).
The Latin American Energy Organization (OLADE) estimated that emissions from electricity production in 2003 were 6.5 million tons of . Currently 30 percent of emissions in Colombia come from the power sector, but these could increase if thermal generation gains a larger part of the energy mix.
Clean Development Mechanism projects in electricity.
As of August 2007, there are three registered Clean Development Mechanism (CDM) projects in the electricity sector in Colombia, with overall estimated emission reductions of 107,465 te per year.
The Jepírachi project, in the Uribia region, is Colombia's first and only wind farm. This 19.5 MW project is expected to displace an estimated 430,000 t until 2019. The Jepírachi project is now in its fourth year of operation. It generated about 144 GWh and displaced about 48,500 te from February 2004 to August 2006.
The other two registered projects are the Santa Ana Hydroelectric Plant, in the Bogotá's suburb Usaquén, with estimated emission reductions of 20,642 te per year; and the La Vuelta and La Herradura Hydroelectric Project, in the Antioquia Department, with estimated emission reductions of 69,795 te per year.
External assistance.
Inter-American Development Bank.
The Inter-American Development Bank has currently one energy project under implementation in Colombia, the Porce III Hydroelectric Power Plant, owned by Empresas Públicas de Medellín and approved in October 2005. This is a US$900 million project, of which the IDB is contributing US$200 million.
In addition, the IDB is supporting the Colombia-Panama electric interconnection project through US$1.5 million financing for the feasibility studies phase.
References.
ESMAP, 2007. "Review of Policy Framework for Increased Reliance on Renewable Energy in Colombia." In press
Ministry of Mines and Energy & UPME, 2006. "Plan de Expansión de Referencia: Generación, Transmisión. 2006-2020."


Linus (fusion experiment)

The Linus program was an experimental fusion power project developed by the United States Naval Research Laboratory (NRL) starting in 1971. The goal of the project was to produce a controlled fusion reaction by compressing plasma inside a metal liner. The basic concept is today known as magnetized target fusion.
The reactor design was based on the mechanical compression of a molten metal liner. A chamber would be filled with molten metal and rotated along one axis, creating a cylindrical cavity in the center. A suitable fusion fuel, heated to relatively low temperatures to form it into a plasma, is injected into the center of the cavity. The metal is then rapidly collapsed, and due to the conservation of magnetic flux within the metal, the plasma is confined within the resulting collapsing shell and is itself collapsed. The adiabatic process would raise the temperature and density of the trapped plasma to fusion conditions.
The use of a liquid metal liner has many advantages over previous experiments that imploded cylindrical solid metal liners to achieve high-energy-density fusion. The liquid metal liner provided the benefits of recovering the heat energy of the reaction, absorbing neutrons, transferring kinetic energy, and replacing the plasma-facing wall during each cycle. Added benefits of a liquid liner include greatly simplified servicing of the reactor, reducing radioactivity, protecting the permanent sections of the reactor from neutron damage, and reducing the danger from flying debris.
The concept was revived in the 2000s as the basis for the General Fusion design, currently being built in Canada.
Conceptual design.
In the Linus concept, the reactor chamber consists of a drum filled with a liquid metal liner, typically molten lead-lithium. The drum is spun, creating centrifugal force which causes the liquid to be forced onto the inside wall of the container. There is only enough liquid metal to fill perhaps 20% of the total volume, so a large open area in the middle forms during rotation. For operation, a system, typically consisting of pistons, is used to drive additional liquid metal into the drum. This causes the entire liner to be forced inward. In experimental systems, this provided about ten-to-one compression. The extra metal is then removed again by releasing the pistons, causing the compression to reverse and the metal reach the original position at the outside of the drum.
To create fusion, a fusion-fuel plasma is injected into the cavity before the piston stroke. Because the metal is magnetic, the plasma in the center is forced inward as well. This compression causes the plasma temperature to increase through the adiabatic process, raising it to fusion-relevant temperatures and pressures, around 100 million K and . At these temperatures and pressures, the rate of fusion, according to the fusion triple product, is very rapid and completes before the mechanical compression reverses. The energy released by these reactions, in the case of the typical deuterium-tritium (D-T) fuel, is mostly in the form of high-energy neutrons about 14.1 MeV. These are captured in the liquid metal, raising its temperature. Some of the neutrons will interact with the lithium in the liner, undergoing a nuclear reaction that produces new tritium. The energy is then extracted using a steam generator as is the case in any heat driven power plant, while the tritium is extracted through a variety of chemical processes.
A key advantage of the Linus concept is that the compression cycle is reversible, in contrast to other concepts that use thin solid metal shells that can only be used once. This allows the system to run continually, limited generally by the ability to clear out the results of the last reaction and generate and inject new fuel plasma, on the scale of a few seconds. Additionally, systems using non-rotating shells are subject to the Rayleigh-Taylor instability and have proven extremely difficult to stabilize. The rotation of the liquid in Linus suppresses these instabilities. Finally, the metal protects the rest of the reactor from the neutron flux, which is a major problem in other designs.
History.
The Linus effort ultimately traces its history to a discussion between Ramy Shanny of NRL and E.P. Velikhov of the Kurchatov Institute.
The basic idea of super-high magnetic fields as a path to fusion had been considered as early as the 1950s by Andrei Sakharov, who proposed imploding metal liners to produce the required field. The concept was not picked up until the 1960s, when Velikhov began small-scale experiments. It was realized that the cost of the metal liners would likely be higher than the value of the electricity they would produce, the "kopek problem", and they considered the idea of using a liquid metal liner instead.
Shanny asked about how such a system would be stabilized against Rayleigh-Taylor issues. Velikhov misunderstood the question, thinking he was asking how it would be stabilized against gravity within the drum. He replied that they would spin it. When Shanny considered this answer he found that it did indeed stabilize against Rayleigh-Taylor, and the Linus program was born.
Suzy I.
To gain experience with the concept, NRL initially built liner imploders. The first experimental device was Suzy, constructed in 1971 under the direction of D.C. dePackh. The system used solid metal liners, like the Soviet experiments and many later devices. The liner was driven inward through the theta pinch process, using a capacitor bank.
Suzy II.
A.E. Robson and P.J. Turchi joined the program in 1972, and dePackh departed NRL. Robson and Turchi continued the development of the concept with Suzy II, a similar system to what then became Suzy I, but much larger and equipped with a more powerful capacitor bank power supply. Suzy II compressed liners from an initial diameter of to a final diameter of about , giving an overall compression ratio of 28:1 was achieved. Pressures greater than were achieved during the implosions.
With the success of the basic Suzy II experiments, attention turned to the liquid liner. This was built on Suzy II using a plastic liner inside a steel drum, filled with sodium-potassium alloy (NaK) at its eutectic mixture (22% Na, 78% K) which is a liquid at room temperature. By firing the implosion bank at different powers the relationship between implosion speed and rotation speed could be tested, and demonstrated the expected result that as long as the rotational speed is high enough, as the liner compressed and its rotational speed increased due to conservation of angular momentum, the centripedal force kept the apparent gravity vector pointed outward. This stabilizes against R-T instabilities because it is the lighter fluid in the center falling outward, a naturally stable condition.
Suzy II was successful in producing a stable inward compression of the liner, but unfortunately, the reverse was not true. As the liner began to expand again when the compression current was turned off, you once again had a heavy fluid moving into a lighter one, and the R-T instabilities re-appeared. This caused the liner to break up into droplets, which, due to their high mass and velocity, impacted the container randomly with the entire embodied energy. In a production machine this would be on the order of 100 MJ, the equivalent of about of TNT.
Piston implosion experiments.
The solution to the liner breakup during expansion is to fill the void with additional liner material. This precludes the use of electromagnetic drivers as in Suzy, and attention turned to using a mechanical piston driving material from a reservoir into the main chamber. The piston was driven by compressed gas.
Several experimental machines followed. The first, the "water model", consisted of a drum of water with pistons positioned radially around it. The entire system, including the pistons, spun. This verified the basic approach, but was problematic as the piston timing proved difficult to control the required accuracy. This problem was addressed by a new piston layout with the pistons arranged annularly that could be fired by a single source. This proved to solve the problems and plans began to build larger devices.
Linus-0.
With the success of the piston models, plans began to build a larger machine similar to the size and energy as the Suzy II machine. This led to the Linus-0 design, which consisted of a diameter steel rotor surrounded by a gas cylinder that was pressurized to using a series of small high-explosive DATB () charges, also known as the polymer-bonded explosive PBXN, chosen for its high melting point, low particulate matter, and compatibly low cost. The charges were loaded into a series of ports on one end of the device and fired just prior to the experimental run to pressurize the system. The inner rotor was spun to 2100 RPM using a 454 cubic inch Chevrolet V8 engine.
Linus-0 proved to be slow to build due to the only machine shop large enough to make the rotor being busy with other tasks, and the device was not completed until 1978, shortly before the program closed down. Nevertheless, the system was used with water and proved to be able to make repeatable shots in the short time it was operational. During data collection, Linus-0 was fired as often as three times daily.
Helius.
The delays in the construction of Linus-0 led to the construction of a half-scale version, Helius. It was designed to use liquid sodium and potassium in the liner chamber. In practice, the use of water was sufficient for the hydrodynamic studies. In the experiment, the liquid sodium-potassium liners were imploded using high-pressure Helium () to drive mechanical pistons.
Project fate.
The initial proposals for the Linus designs was based on a cylindrical collapse of the liner a continuous plasma inside. This arrangement meant there was nothing to confine the plasma from being squirted out the ends of the imploding cylinder of metal. This was not necessarily a problem; both the liner and the plasma would move at the speed of sound, but because the speed of sound in the metal is much higher than in the plasma, most of the plasma would not have time to move before it had already completed the reaction. There was some concern about bad curvature at the ends of the cylinder, which can lead to the interchange instability that operates much faster than the speed of sound, but the magnitude, or even it if was present at all, was not explored.
The disadvantage of this approach was that some plasma did escape, and that amount increased as the speed of the implosion decreased. In order to get a reasonable reaction rate, driver energies on the order of 75 to 100 MJ were required. While this was not impossible to achieve, it still represented a significant capital cost to build such a storage system, and the resulting high-energy and high-speed implosion represented an engineering challenge.
Linus was being developed while another fusion concept was first emerging, the field-reversed configuration, or FRC. This is essentially a smoke ring of plasma that is naturally stable for a time. Using an FRC inside the machine would provide natural confinement at the ends of the cylinder, preventing the plasma from escaping. This would significantly reduce the required implosion energy, and thus lower the size and cost of the machine as a whole.
At the time, FRCs were very new technology. But as they appeared to represent a significant advance in the state of the art, potentially making a successful fusion system even without the implosion, NRLs interest quickly changed to the underlying physics of the FRC. Experiments on Linus-0 and Helius were relatively brief due in part to delays incurred in the design, fabrication, and assembly phases. Time wasn't allocated to recover from delays or unexpected challenges, and the machines were eventually disassembled and placed in storage.
The Linus project encountered several engineering problems which limited its performance and thus its attractiveness as an approach to commercial fusion power. These issues included performance of the plasma preparation and injection method, the ability to achieve reversible compression–expansion cycles, problems with magnetic flux diffusion into the liner material, and the ability to remove the vaporized liner material from the cavity between cycles (within a duration of about ) which was not accomplished. Shortcomings also occurred with the design of the inner mechanism which pumped the liquid-metal liner.
Another major problem encountered involved hydrodynamic instabilities in the liquid liner. If the liquid was imprecisely compressed, the plasma boundaries could undergo Rayleigh–Taylor instability (RT). This condition could quench the fusion reaction by reducing compression efficiency, and by injecting liner material (vaporized lead and lithium) contaminants into the plasma. Both effects reduce the efficiency of fusion reactions. Strong instability could even cause damage to a reactor. Synchronizing the timing of the compression system was not possible with the technology of the time, and the proposed design was canceled.


Companhia de Electricidade de Macau

Companhia de Electricidade de Macau – CEM, S.A. known simply as CEM or is a private public utility company with a sole concession to transmit, distribute, sell high, medium and low voltage of electricity in Macau. Besides, CEM owns an installed generation capacity of 408 MW.
History.
From 1906 to 1972, the electricity supply service was managed by the "Macao Electric Lighting Company Ltd." (now Melco International Development), which had its headquarters in British Hong Kong. In 1972, due to non-fulfilment of its concession contract with the former Portuguese administration, the company was replaced by CEM.
CEM was restructured with the former Portuguese administration's support in 1982. In 1985, CEM signed the 25-year concession contract. It has since scored achievements in the areas of cost-effectiveness and technology.
In November 2010, the Government of Macau and CEM signed the Power Supply Contract Extension for 15 years. The new contract terms came into effect on 1 December 2010.
In 2014, Nam Kwong (Group) Company Limited purchased a 90% stake in Sino–French Energy Development Co. from Sino-French Holdings (Hong Kong) Ltd and became CEM’s biggest shareholder.
In 2016, the Macau Power Station with a history of over 110 years was officially decommissioned.
Logo.
The CEM logo is a symbol of the company's close ties with customers, Macau and its employees, represented by three dynamic and vibrant curved lines that are well-designed to accentuate a harmonious, interdependent and collaborative relationship. The logo is simple and vivid, with yellow representing energy and vitality, and orange representing prosperity.
Transmission and distribution.
The Macau electricity transmission network comprises 25 primary substations, 8 customer high-voltage switching stations and 953 kilometres of 66 kV, 110 kV and 220 kV high-voltage cables. The Macau electricity network is connected to China Southern Power Grid via two 110 kV cables and two 220 kV cables. The two 110 kV cables are connected to Gongbei Substation and Nanping Substation, while the two 220 kV cables are connected to Zhuhai Substations and Qinyun Substation.
The 11kV medium-voltage electricity transmission network comprises 41 customer switching stations and 1,502 customer substations (11 kV/400 V) connected by cables with a total length of 2,294 kilometres. The low-voltage transmission network is made up of 906 kilometres of cable, while the street lighting network comprises 571 kilometres of cable and about 11,105 streetlights. The power network of CEM consists almost entirely of underground cables.
Performance.
According to CEM's annual report, in 2018, the Average Service Availability Index (ASAI) was 99.9998%, while the Customer Average Interruption Duration Index was 6.56 minutes, achieving the goal of less than 20 minutes.
CEM adopted international management standards to ensure the compliance of sustainable development in the company. So far, CEM has been certified with the following international standards:
Generation.
The actual capacity of CEM’s generation consists of two power stations located on the Coloane Island, namely Coloane Power Station A (CCA) and Coloane Power Station B (CCB). The types of generation technology deployed are the low speed diesel generator (CCA) and the combined cycle gas turbine (CCB).
Shareholders.
Shares of CEM are currently owned by Nam Kwong Development (H.K.) Limited (42%), Energy Asia Consultancy (21%), Polytech Industrial (11%), Asiainvest - Investments (10%), Government of Macau (8%), China Power International Holding (6%) and other investors (2%).
Before 1987, the largest shareholder of CEM was the Government of Macau. But ever since that, the government had been reducing its share until the current 8%.
The former largest shareholder of CEM, Sino-French Energy Development, was majority owned by listed companies NWS Holdings and Suez Environnement via an intermediate holding company Sino-French Holdings (Hong Kong) Limited.
In 2014 Sino-French Holdings sold 90% stake in Sino French Energy Development to Chinese state-owned enterprise (via its HK subsidiary Nam Kwong Development (H.K.) Limited); the remaining 10% stake of Sino-French Energy Development was owned by Hong Kong-Macau billionaire Stanley Ho. Sino-French Energy Development was merged with its direct parent company Nam Kwong Development in 2019.
Chinese Central government also owned another shareholder of CEM, China Power International Holding. That company was owned by State Power Investment Corporation (ex-China Power Investment Corporation).


Alpiq

Alpiq is a leading energy company in Switzerland and the largest energy service provider with focus on European markets. The company operates mainly in Switzerland, but it also has power stations in Italy, France, Norway, Hungary and the Czech Republic and building new ones in Germany, Italy, France, Bulgaria and the Czech Republic. The group was established in 2009 in Neuchâtel, Switzerland after the merger of two Swiss energy companies Aare-Tessin Ltd. for Electricity (Atel) and Energie Ouest Suisse (EOS).
History.
Alpiq was founded in 2009 as a result of the merger of Swiss energy companies Atel and EOS. Atel (Aare-Tessin Ltd. for Electricity) was founded in 1894 and was active in Europe in the production, trading and sale of electricity. EOS (Energie Ouest Suisse) was founded in 1919 by several electricity companies based in Western Switzerland. The company was specialised in producing electric power from hydroelectric sources and owned many stations in the country. It also had a energy distribution network in the same area.
Group companies.
The Alpiq Group comprises the following companies:
Activity.
Alpiq is specialised in the production, distribution and trading of electric power. The company owns around 6,322 MW in hydroelectric, thermal, wind and solar power stations. Alpiq has stakes in 2,963 MW of hydroelectric power stations, 3,250 MW of thermal power stations and 109 MW in small hydroelectric power stations, wind farms and solar power stations.
Hydroelectric power stations.
The company partially or fully owns around 2,963 MW of hydroelectric power station in Switzerland and Italy. The largest hydroelectric power station fully owned by Alpiq is the Lucendro hydroelectric power station located in Switzerland that has an installed capacity of 60 MW. The company also owns a 60% stake in the Grande Dixence SA, company that manages the Grande Dixence Dam.
Thermal power stations.
The company partially or fully owns around 3,250 MW of thermal power stations in Switzerland, Germany, Hungary, Italy, Spain and the Czech Republic. The largest thermal power station fully owned by Alpiq is the Plana del Vent thermal power station located in Spain that has an installed capacity of 800 MW.
Other power stations.
Alpiq partially or fully owns around 109 MW of small hydropower stations, wind farms and solar power stations in Switzerland, Italy, Norway and Bulgaria. The company owns stakes in 11 small hydropower stations in Switzerland, Italy and Norway with a combined electric power generation capacity of 20.63 MW and an annual power generation of 72.17 GWh. The company owns stakes in five wind farms located in Switzerland and Italy with a combined electric power generation capacity of 178 MW and an annual power generation of 346 GWh. Alpiq is also involved in the construction of another two wind farms in Italy and Bulgaria with a combined capacity of 90 MW.
The company is also involved in the construction of the Narbone Serre solar park located near Agrigento in Sicily, Italy. The power station will use thin-film solar cells. The solar cells will have a combined capacity of 14 MW. The first section of the solar farm will go operational in 2010, generating 6.5 MW. The second section rated at 7.5 MW is still at the approvals phase.
Electricity trading.
Alpiq has trading branches in 16 countries in Europe and is active on all major European energy exchanges. The company focuses on origination and sales activities in the B2B customer segment for electricity and natural gas. Alpiq has a pan-European presence with regional roots and know-how and has an experienced team in the optimization and marketing of renewable energies and flexible production units. With the 24/7 intraday team, Alpiq customers have access to the intraday, spot and forward markets around the clock in Europe. This service opens up attractive revenue potentials, supports the risk management and the active management of energy positions.
In 2008 the company bought two leading Romanian electricity trading companies Buzmann Industries and Ehol Distribution, both companies based in Bucharest. In 2010 Alpiq became the largest open market electric power trader in Romania surpassing Alro Slatina and having a 16% market share.


Ghana Grid Company

Ghana Grid Company is an electricity transmission company in Ghana. GRIDCo was incorporated on December 15, 2006 as a private limited liability company and started operations in 2008 following the transfer of the core staff and power transmission assets from Volta River Authority with a mandate to ensure "the provision of transparent, non-discriminatory and open access to the transmission grid for all the participants in the power market particularly, power generators and bulk consumers and thus bring about efficiency in power deliver."


Electric turbo-compound

An electric turbo-compound (ETC) system is defined where a turbine coupled to a generator (turbogenerator) is located in the exhaust gas flow of a reciprocating engine to harvest waste heat energy and convert it into electrical power.
An example of an ETC system is where a turbogenerator is located downstream of a turbocharger turbine of an internal combustion engine (ICE). The power generated from the ETC system can be used to feed into an electrical grid or provide power to local electrical loads such as engine auxiliaries.
ETC systems are commercially available for stationary power gensets and at an advanced stage of development for automotive applications to improve the fuel efficiency of gas and diesel engines by recovering waste energy from the exhaust gases.
The ETC system is typically located downstream of the turbocharger of an ICE. The exhaust gases expand first through the turbocharger turbine and then through the ETC turbine, which drives a high-speed alternator generating DC or AC power. In gensets, this extra power is added to the power output from the primary generator, increasing the system efficiency. For automotive application the ETC would become the primary generator used to power the vehicle’s auxiliary systems.


Jyotigram Yojana

Jyotigram Yojana () is an initiative of the Government of Gujarat, India, to ensure that a 24-hour, three-phase quality power supply is available to rural areas of the state and supply power to farmers residing in scattered farmhouses through feeder lines with specially designed transformers. The scheme was announced in 2006 by the President of India, A. P. J. Abdul Kalam. In 2011 it was announced by the Government of India that it would accept Gujarat's Jyotigram project as a flagship scheme for its Twelfth five-year plan.
Background.
In 1988, in a attempt to enhance the efficiency of rural electrification in the State of Gujarat, the state government implemented a "flat tariff system" which charges a fixed tariff corresponding to the horsepower of the submersible pumps used by the farmers. As this tariff system did not increase the tariff in timely intervals and the farmers installed more tube wells, the demand for electricity from farmers increased significantly. This also led to taking advantage of groundwater resources. Power distribution companies were in a severe financial stress by catering to the substantial increase in demand for a three-phase power supply. Much of the losses were attributed to the farm subsidies relating to electricity. Despite the opposition from the farmers, the government began to regulate the supply of electricity to rural areas for 12–14 hours a day before 2001. Owing to the politics in the state of giving free power to the farmers, the quality and the timing of the power supply in the state deteriorated. To overcome this crisis, the government called for suggestions on power sector reforms in the state. Many institutions, including the International Water Management Institute (IWMI), made recommendations to the Government of Gujarat. In September 2003, the government accepted IWMI's recommendations and launched Jyotigram Yojana as a pilot project in eight districts of the state.
Scheme highlights.
The purpose of the scheme was to provide uninterrupted, good quality, scheduled, and subsidized power supply to the irrigating farmers for eight hours, separated by uninterrupted, unsubsidized, 24-hours supply to villagers for daily life usage. This objective was achieved by separating the feeder lines, with dedicated lines assigned to supply full-voltage power supply to both irrigating farmers and household users. The regulator was allowed to raise the tariff every year. By doing this, Gujarat became the first state in India to undertake the radical reform of separating the feeder lines between agricultural and consumer usage. This huge task was achieved by carrying out the replacement and complete rewiring of high and low tension cables, transformers, new electricity poles, etc. By 2006, the scheme reached almost 95 percent of the 18,000 villages in the state.
The scheme was recognized by the UPA-II government during the time, and was accepted as a flagship scheme for the Twelfth five-year plan, which envisaged bringing in "faster, sustainable, and more inclusive growth". Inspired by the achievements of this scheme, states like Punjab, Karnataka, Madhya Pradesh, Andhra Pradesh, and Maharashtra have shown interest in implementing a similar policy.
Stockholm International Water Institute commended the scheme, saying Jyotigram Yojana had "radically improved the quality of village life, spurred non-farm economic enterprises, and halved the power subsidy in agriculture".
Impact.
Jyotigram Yojana caused most of the political parties to change their electoral posture of giving free farm electricity in various states in the country. Research conducted and published by Deutsche Bank found that Gujarat managed to reduce the Aggregated Technical and Commercial losses (AT&C) from 35 percent in 2004 to 23.7 percent in 2007, then further reduced to 19 percent in 2014, whereas the country average was 26 percent. This made Gujarat a power surplus state, leading to additional revenue to the state. Industrial power consumption increased at 42 percent, though the tariff was charged at 20 percent higher, resulting in increasing the revenues for power distribution companies.
This policy also had an effect on the health sector. A 2019 research study showed that after the implementation of Jyotigram Yojana, access to reliable electricity in the state increased. The scheme also increased the overall operational capacity of health facilities in the state. There was also a significant increase in the availability and functionality of various health services, which were easily available to the public through the usage of television and the easy working of various medical equipment.


MC3 connector

MC3 connectors are a mostly obsolete type of single contact connector commonly used for connecting solar panels. MC3 are named for the original manufacturer Multi-Contact (now part of Stäubli Electrical Connectors) with a 3 mm² contact assembly pin. They are typically rated at 20 A and 600 V maximum (UL), although the rating of the connector and cable as a whole may vary.
Physical properties.
The MC3 connectors incorporate a flexible watertight seal and are supplied as 'male' and 'female' types to minimise the chance of wrong connections. For proper application usage, they are connected with UV resistant, correct diameter cable. The connector pairs hold together by friction and suction, only.
Obsolescence.
MC3 connectors have been largely superseded by MC4 connectors due to support being withdrawn by the National Electrical Code for solar applications. The MC3 connector does not incorporate a positive locking mechanism and can become disconnected while the solar panels are producing electricity causing dangerous arcing.