TC Energy

TC Energy Corporation (formerly TransCanada Corporation) is a major North American energy company, based in Calgary, Alberta, Canada, that develops and operates energy infrastructure in Canada, the United States, and Mexico. The company operates three core businesses: Natural Gas Pipelines, Liquids Pipelines and Energy.
The Natural Gas Pipeline network includes of gas pipeline, which transports more than 25% of North American natural gas demand. The Liquids Pipelines division includes of oil pipeline, which ships 590,000 barrels of crude oil per day, which is about 20% of Western Canadian exports. The Energy division owns or has interests in 11 power generation facilities with combined capacity of 6,600 megawatts (MW). These power sources include nuclear and natural gas fired.
The company was founded in 1951 in Calgary. TC Energy is the largest shareholder in, and owns the general partner of, TC PipeLines.
History.
The company was incorporated in 1951 by a Special Act of Parliament as Trans-Canada Pipe Lines Limited. The purpose of the company was to develop the TransCanada pipeline (now known as the Canadian Mainline) to supply eastern Canadian markets with natural gas produced in the west.
In 1998, TransCanada Pipelines merged with NOVA Corporation's pipeline business, keeping the TransCanada name and becoming "the fourth largest energy services company in North America".
Seeking to expand its presence in the United States, in 2016, TransCanada acquired Columbia Pipeline Group (CPG) for US$13 billion from NiSource's Shareholders. The CPG acquisition added a pipeline network in Pennsylvania and surrounding states, where the Marcellus and Utica shale gas formations are located.
In May 2019, the company changed its name from TransCanada Corporation to TC Energy Corporation to better reflect the company's business, which includes pipelines, power generation and energy storage operations in Canada, the United States and Mexico.
Operations.
Natural gas pipelines.
TC Energy's natural gas pipelines business builds, owns and operates a network of natural gas pipelines across North America that connects gas production to interconnects and end use markets. The company transports over 25% of continental daily natural gas demand through 91,900 km (57,100 mi) of pipelines. In addition, the company owns 535 Bcf of natural gas storage facilities, making TC Energy one of the largest natural gas storage providers in North America. This segment is TC Energy's largest segment, generating approximately two-thirds of the company's EBITDA in 2017. The Natural Gas Pipelines business is split into three operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, and Mexico Natural Gas Pipelines.
The major pipeline systems include:
Projects in development include:
Coastal GasLink Pipeline Project – In June 2012 it was announced that TransCanada was selected by Shell and LNG Canada partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited (to which Petronas of Malaysia was added in 2018) to design, build, own and operate the Coastal GasLink pipeline between northeastern B.C. gas fields near Dawson Creek, British Columbia, and the LNG Canada LNG liquefaction, storage and export facility in the port of Kitimat, on the Douglas Channel.
The investment and construction decisions for the LNG Canada and Coastal GasLink Pipeline Project were officially confirmed early October 2018, for completion by 2024–2025. However, hereditary chiefs of the Wetʼsuwetʼen have denied consent to construct the pipeline on the company's preferred route through culturally and ecologically sensitive lands in their unceded territory, leading to nationwide protests.
Prince Rupert Gas Transmission project – In January 2013 it was announced that TransCanada was selected by Petronas to design, build, own, and operate the Prince Rupert Gas Transmission project, a gas pipeline that would transport natural gas from the Montney region near Fort St. John, British Columbia to a LNG terminal planned by Progress Energy Canada Ltd. in Port Edward, British Columbia on Lelu Island near Prince Rupert, British Columbia. The project faced opposition from the Gitxsan first nation due to concerns about the impact it would have on salmon in the Skeena River. On July 25, 2017, Petronas announced they were abandoning the Pacific NorthWest LNG proposal and TransCanada said they were "reviewing our options related to our proposed Prince Rupert Gas Transmission (PRGT) project".
Liquids pipelines.
Two TC Energy's Liquids pipelines connect Alberta crude oil supplies to U.S. refining markets., the Keystone Pipeline System and the Grand Rapids pipelines. The 460 km-Grand Rapids pipeline transports crude oil from the producing area northwest of Fort McMurray, Alberta, to the Edmonton/Heartland, Alberta market region. In October 2012, TransCanada formed a 50–50 CAD$3bn joint-venture with Phoenix Energy Holdings Ltd. (the Canadian subsidiary of PetroChina) to develop the 500 km Grand Rapids Pipeline.
The 4,324 km-Keystone Pipeline System transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka, Illinois, Cushing, Oklahoma, and the U.S. Gulf Coast. The Keystone System transports approximately 20% of Western Canadian crude oil to export markets. The Keystone Pipeline has had three significant leaks since it opened in 2010. It has leaked approximately 400 barrels in North Dakota in 2011 and South Dakota in 2016, and approximately 5000 barrels in South Dakota in 2017.
A third pipeline, the 1,906 km-long Keystone XL Pipeline—which is an expansion of the Keystone Pipeline System—began construction in 2020. When completed, the Keystone XL Pipeline will transport 830,000 barrels of Athabasca oil sands crude oil per day from the Hardisty, Alberta to Steele City, Nebraska.
TC Energy had first proposed the Keystone XL pipeline in 2008. The proposal faced widespread grassroots opposition with tactics including tree sits in the path of the pipeline and civil disobedience by celebrities. Critics state that by developing the oil sands, fossil fuels will be readily available and the trend toward warming of the atmosphere won't be curbed. The fate of the pipeline is therefore held up as symbolic of America's energy future. Critics have raised concerns about the risks of spillage, as the Sandhills region of Nebraska is a fragile ecosystem.
In October 2011, TransCanada was involved in up to 56 separate eminent domain actions against landowners in Texas and South Dakota who refused to give permission to the company to build the Keystone Pipeline through their land. However, on August 23, 2012, Texas Judge Bill Harris ruled that TransCanada had the right of eminent domain and could lease or purchase land from owners who refused to sign an agreement with the company for a public right of way for the pipeline. The landowners had said that the pipeline was not open to other companies, and so did not meet the criteria for eminent domain.
U.S. President Barack Obama rejected the pipeline on November 3, 2015.
Early in his tenure in 2017, President Donald Trump signed presidential memoranda to revive both Keystone XL and Dakota Access pipelines. The order would expedite the environmental review that Trump described as an "incredibly cumbersome, long, horrible permitting process".
In 2017, President Trump signed a U.S. Presidential Permit to allow TransCanada to build the Nebraska pipeline route of the Keystone XL. TransCanada secured sufficient commercial support to commence construction preparation.
This action by Trump inspired another wave of protests and rallies against the pipeline.
In March 2020, Premier Jason Kenney of Alberta, agreed to help finance the construction of TC Energy's Keystone XL oil sands pipeline in southern Alberta, Montana, South Dakota and Nebraska with a CA$7.5 billion (US$5.3 billion) financing agreement. According to "The New York Times" , despite the coronavirus pandemic, a down turn in the global economy, and "plunging oil prices", Premier Kenney said that Alberta could not afford "for Keystone XL to be delayed." With this financial agreement, the Alberta government gained a US$1.1-billion ownership stake in the 1,947-kilometre pipeline which will "575,000 barrels of oil daily". The province intends to sell its shares to TC Energy "after commercial operations begin." Alberta also gave a full guarantee on a US$4.2-billion project loan. The $USD1.1 billion equity covers construction costs from April through December 2020. TC Energy will also invest CA$.7 billion. The Alberta government are also providing a fully guaranteed CA$4.2 billion loan for the project. The premier also said that over the next twenty years, the financial benefits to Alberta through tax and royalty revenue would be approximately CA$30 billion. In response to Alberta's financial support, in March, TC Energy "approved construction of the US$8-billion project to transport up to 830,000 barrels per day of oil." According to a Canadian Press March 31, 2020 article Premier Kenney estimated that "1,400 direct and 5,400 indirect jobs" would be created in Alberta during construction. In September 2020, TC Energy announced that it would be restructuring some of its gas pipeline operations in Alberta.
In April, shortly after construction on Keystone XL began, Judge Brian M. Morris of the Federal District Court in Montana suspended the United States Army Corps of Engineers (USACE)'s program allowing permits for pipelines to cross waterways, in spite of the Clean Water Act (CWA). Judge Morris said that the USACE pipeline permits "posed a threat to endangered species" and its reauthorization in 2017, had been improper. In July 2020, the Supreme Court of the United States declined to block Judge Morris' ruling, effectively halting all construction on the XL Pipeline.
In September 2020, the Nekaneet Cree Nation in Saskatchewan, the Ermineskin Cree Nation, Montana First Nation, Louis Bull Tribe, and Saddle Lake Cree Nation in Alberta signed a memoranda of understanding (MOU) for an ownership stake in Keystone XL.
In a Canadian Press article Calgary energy reporter, Dan Healing, wrote that Keystone XL's future was "still in doubt"—if Presidential candidate Joe Biden wins the November 3, 2020 United States presidential election, he would fulfill his promise to cancel the pipeline's "vital presidential permit."
In January 2021, U.S. President Joe Biden revoked the project’s presidential permit.
Marshall County, South Dakota leak 2017.
On November 16, 2017, oil leaked from the pipeline in Marshall County, South Dakota, for 15 minutes before the flow of oil could be stopped. The company reported the amount as over 210,000 gallons. TransCanada reported it discovered the leak in Amherst, South Dakota, at 6 am on Thursday after systems detected a drop in pressure in the northern leg of the pipeline. The leak was discovered about 35 miles south of the Ludden pump station.
In April 2018, a federal investigation showed that the spill was almost twice as large as TransCanada had claimed in November, and that it was the seventh-largest onshore oil spill since 2002. The study showed that 407,000 gallons, not 210,000 gallons, had spilled. Also in April 2018, "Reuters" reviewed documents that showed that Keystone had "leaked substantially more oil, and more often, in the United States than the company indicated to regulators in risk assessments before operations began in 2010".
Energy.
TC Energy's Energy division consists of power generation and unregulated natural gas storage assets. The power business consists of approximately 7,000 megawatts (MW) of generation capacity owned or under development. These assets are located primarily in Canada and are powered by natural gas, nuclear, and wind.
Ownership.
As of February 2020, the bulk of the share capital of TC Energy is owned by 488 institutional investors, who compose 62% of the stock. The dominant shareholder is the Royal Bank of Canada, which owns a fraction over 8% of the company. The Big Five (banks) together own more than 17% of the outstanding share capital. Significant holdings accrue to the Caisse de dépôt et placement du Québec and the OMERS.
Political activities.
In 2019 TransCanada aided the drafting of anti-protest legislation in South Dakota. The legislation, which Governor Kristi Noem signed into law in March 2019, created a fund to cover the costs of policing pipeline protests, and was accompanied by another law which sought to raise revenue for the fund by creating civil penalties for advising, directing, or encouraging persons participating in rioting. In response to the law Noem was sued by the Indigenous Environmental Network, Sierra Club, and other groups, who argued the laws violate First Amendment rights by incentivizing the state to sue protesters.


Neptune Cable

The Neptune Cable is a 500kV and 660 MW high-voltage direct current submarine power cable between Sayreville, New Jersey and Levittown, New York on Long Island. It carries 22 percent of Long Island's electricity. It was developed by Anbaric Development Partners.


Kruger Inc.

Kruger Inc. is a Canadian corporation which manufactures publication papers, tissue, lumber and other wood products, corrugated cartons from recycled fibres, green and renewable energy, and wines and spirits. Kruger Inc. operates facilities in Québec, Ontario, British Columbia, Newfoundland and Labrador, and the United States.
History.
The origins of Kruger Inc. date back to 1904, when Joseph Kruger founded a fine paper business in Montreal. Gene H. Kruger, the founder's son, became president of the company in 1928 at the age of 25 and expanded it into the manufacture of newsprint, paperboard, and tissue products.
As chairman of the board and CEO, Joseph Kruger II, Gene's son, has overseen the company's continual expansion into specialty publication papers, North American tissue products, wines and spirits, forest and wood products, renewable energy and recycling, as well as its modernization with special emphasis on the environment.
Activities.
The company's activities are divided into two major divisions: Industrial Products (publication papers, forest products, containerboard and packaging) and Consumer Products (tissue products, wines and spirits). Kruger Inc.’s subsidiary, Kruger Energy, develops and operates hydroelectric, solar, wind power, biomass cogeneration and biogas energy projects.
Kruger has sorting and recovery centres that supply its mills with recycled paper and containerboard for the production of recycled stock and recycled paper products.
Industrial products.
Publication papers.
This Kruger business unit produces newsprint, and coated, directory and supercalendered paper.
Kruger Publication Papers comprises four paper mills, three of which are located in Québec: Trois-Rivières, Kruger-Wayagamack, Brompton (Sherbrooke), and the other in Newfoundland and Labrador: Corner Brook Pulp and Paper Limited. All four paper mills are certified under ISO 9001:2000 (Quality Management), PwC ICoCTM (Chain of Custody) and PEFC (Chain of Custody). Each has its own recycling facilities, secondary effluent treatment system, and environmental and energy conservation programs. Two paper mills also have deinking facilities and produce approximately 300,000 tonnes of deinked pulp per year, which is used to manufacture various Kruger Inc. paper and tissue products.
Containerboard and packaging.
Kruger owns KRUPACK Packaging. Its plants in LaSalle (Quebec) and Brampton (Ontario) manufacture containers for food, beverages, dairy products, meat, fruit and vegetables, flowers, chemicals, textiles and clothing. They also produce boxes for large electrical appliances, auto parts and other industrial products.
Consumer products.
Tissue products.
Kruger’s Tissue Products business unit includes four mills in Canada: Crabtree, Sherbrooke, Gatineau, New Westminster, and one in the United States: Memphis, Tennessee. Its mills have a combined annual papermaking capacity of approximately 294,000 gross air dried metric tonnes (GADMT), which represents 37% of Canada's total installed tissue manufacturing capacity, making Kruger Inc. Canada’s leading tissue products manufacturer.
Kruger Products’ Away-From-Home business leads the Canadian tissue market by providing quality products to market segments such as office buildings, healthcare, food service, manufacturing, and lodging. Designed to meet unique end-user needs, the product line includes bath and facial tissue, towels, wipes, napkins and skin care products.
Brands include Cashmere, Scotties, SpongeTowels, Purex, White Swan, and White Cloud.
Wines and spirits.
The Wines and Spirits business unit was created in September 2006, when Kruger Inc. acquired Maison des Futailles, L.P., a Québec company founded in 1922 by the S.A.Q.’s bottling plant (Société des Alcools du Québec or Québec liquor board). It has seen impressive growth over the past decade and today distributes approximately 20% of all wines marketed in Québec and continues to expand into other provinces and the United States.
Kruger Energy.
Kruger Energy specializes in renewable energy, such as hydroelectricity, wind energy, biomass cogeneration, and biogas energy.
Boreal forest destruction.
A 2007 Greenpeace report on the state of Canada's boreal forests states, "Less than 48 per cent of the total area under Kruger management in Quebec and Ontario remains intact. Kruger is involved in severe controversy on the Island of René-Lavasseur, where logging is carrying on not only in intact forest areas but also in important caribou habitat and without respect for the rights of traditional land owners, the Innu First Nation of Betsiamites...None of Kruger's forested lands is certified to the standards of the Forest Stewardship Council." Kruger achieved FSC certification in March 2011.


Mackellar County Council

The Mackellar County Council (MCC) was a state–owned enterprise of the Government of New South Wales, Australia. Established in 1951, it was an electricity and gas supplier and retailer which primarily supplied the Northern Beaches area of Sydney, New South Wales, being jointly managed and operated by Manly Municipal Council and Warringah Shire Council.
History.
The Local Government Act 1919 (NSW) had provided for the establishment of District Counties and County Councils by whole, groups of, or parts of municipalities and shires to perform nominated functions delegated by the Councils concerned, although the majority of those councils dealt with infrastructure or utility planning. In the Northern Beaches area, the idea of a County Council, specifically dealing with the control and development of electric utilities in the area shared by Manly Municipality and Warringah Shire first occurred in 1938 and again in 1943 but was postponed for consideration because of the Second World War.
Manly and Warringah Councils considered the matter at a conference held on 17 March 1950, but Warringah Shire later withdrew its support for the proposal. However, later that same year, the Electricity Commission of New South Wales began investigations into the overal feasibility of the proposal. In its report of 14 March 1951 the Commission identified advantages of creating a county council comprising the two local government areas for the purpose of developing consistent electric utilities in the region. After further discussions in 1951, the councils of Manly and Warringah resolved to establish the Mackellar County Council consisting of three elected representatives from each Council to commence on 1 September 1951. The council adopted its name, following the 11 May 1949 proclamation of the local federal parliament Division of Mackellar, in honour of politician Sir Charles Mackellar and poet Dorothea Mackellar.
The resolutions of these meetings were forwarded to the Minister for Local Government, Joseph Cahill, who consented to the establishment and Constitution of the Mackellar County Council which were proclaimed on 4 July 1951 and published in the NSW Government Gazette of 13 July 1951. The first delegates to the Mackellar County Council were elected by the Warringah Shire Council on 16 July 1951 and by the Manly Municipality on 17 July 1951. The inaugural meeting was held at the Manly Municipal Council Chamber on 15 August and commenced operations on 1 September 1951. The Council eventually moved to more permanent headquarters, with the administrative headquarters positioned between Manly Local Court and Manly Town Hall on Belgrave Street in Manly and the technical headquarters situated in offices next to the Warringah Shire Hall on Pittwater Road, Brookvale. On 14 September 1962 the Minister for Local Government and Highways, Pat Hills, opened the new headquarters building of the County Council, located on 48-52 Sydney Road, Manly.
In May 1965, the employees of the County Council registered the "Mackeller County Council Employees Credit Union Limited". The Credit Union later operated as the Manly Warringah Credit Union. Then later became the Northern Beaches Credit Union and in 2016 merged with Community First Credit Union.
In 1968 the County Council was involved in litigation involving its responsibilities under the law over the liability of adjoining properties to its developments. The Supreme Court of New South Wales ruled that under the ordinances of the Local Government Act 1919, the council had liability over damage to adjoining properties to any of its developments. The case of "Anderson v. Mackellar County Council" is now an oft-cited case of precedent in construction law in Australia.
By the late 1970s, the NSW Government resolved to restructure of electricity distribution areas in New South Wales, which included the reduction of the number of electricity councils. This was implemented on 1 January 1980, with the Mackellar, St George, and Brisbane Water county councils being amalgamated with the Sydney County Council.
Common Seal.
Soon after the Council's establishment, the councillors resolved to commission a 'Common Seal' to be the primary visual identifier for the council. The Council asked the eminent local historian and President of the Manly and Warringah District Historical Society, Percy Walter Gledhill FRAHS to draw up a heraldic design that represented the area over which the council had responsibilities. Gledhill, who had noted to the Sydney Morning Herald that "They wanted something historic, something to represent light and something from the so-called arms of Manly and Warringah. Those arms aren't registered either, you know", made the following description of his design to the council:


Guyana Power and Light

Guyana Power and Light (GPL) is a publicly owned utility company in Guyana, providing electric power in the country. Domestic voltage can be 110 or 220 depending on the area, both 50 and 60 cycle power. Services are provided from Charity to Moleson Creek, including the islands of Leguan and Wakenaam in the Essequibo River.
GPL has power stations at Sophia, Georgetown, in Onverwagt (West Berbice) as well as facilities in Bartica, Anna Regina, and Fairfield.
History.
Before the turn of the twentieth century, power was provided by private entities, particularly in Georgetown and New Amsterdam, Guyana. Mining areas of Linden and Everton (upper Berbice) received power from Alcan and Reynolds Group Holdings, mainly for their Mackenzie (Linden) and Berbice-based bauxite operations.
The International Power Company of Canada was in operation in Georgetown at the turn of the twentieth century. The Demerara Electric Company was established in 1925 when it purchased the assets of IPC. The British Guiana Electricity Company (BGEC) came into being in 1957, and in 1960 it purchased the assets of the Demerara Electric Company. After Independence in May 1966, the BGEC was nationalized and the Guyana Electricity Company (GEC) was established. By 1991, the facilities had deteriorated and the capacity of 253 megawatts of electricity and generated 647 gigawatt-hours of electricity only satisfied half the estimated demand. Blackouts were common.
Thirty three years later, the Government of Guyana divested 50 percent of its ownership and control to a UK-based consortium comprising the Electricity Supply Board International and the Commonwealth Development Corporation. The divestiture failed and the company once again became wholly owned by the state on 1 May 2003.
The failure of GPL to significantly cut back its technical and commercial losses has been deemed to be largely due to the lack of incentives for efficiency due to its ownership structure. Accordingly, its privatization was expected to generate commercial incentives to improve efficiency, while also enhancing private funding to develop the system. However the privatized venture failed to deliver the results expected and, after a few years returned to Government ownership. A future re-privatization of GPL is unlikely to occur before the regulatory and institutional framework of the sector is improved.
Generator maintenance was contracted out to Wärtsilä until 2018 when the role was handed over to Power Producers and Distribution Inc.


Sarawak Energy

Sarawak Energy is the electric utility company of the Malaysian state of Sarawak. It is one of Malaysia's three electrical companies, the other two being Tenaga Nasional, supplying the Peninsular Malaysia, and Sabah Electricity, which serves the state of Sabah and Labuan.
History.
In 1921, an Electrical Section within the Public Works Department was set up to look after the public electricity supply. In 1932, "Sarawak Electricity Supply Company" was formed by the Brooke Administration to operate public electricity supply within Sarawak.
The Sarawak Electricity Company was dissolved in 1962, under the Sarawak Electricity Supply Corporation Ordinance 1962, and later created into a Corporation, known as Sarawak Electricity Supply Corporation (SESCO) (Malay: Perbadanan Pembekalan Letrik Sarawak, and later Perbadanan Pembekalan Elektrik Sarawak or PPLS). In 1996, Sarawak Enterprise Corporation Berhad bought over 45% stake of the Corporation from the Sarawak Government.
In 2005, SESCO was privatised and known as Syarikat SESCO Berhad, and bought over by Sarawak Energy Berhad.
Sarawak began to export electricity from Sarawak to West Kalimantan, Indonesia in January 2016 through a 275kV interconnection operated by Sarawak Energy. This project is the first successful power trading project for Malaysia.
Generation capacity.
Sarawak Energy generates electricity mainly from two major types of plant; hydroelectric plants (HEP) and thermal plants. With a total installed capacity of 5,203 MW, the major towns in Sarawak are connected via a 275/132kV State Transmission Grid.
Hydroelectric power plants
Thermal power plantsAmong the thermal plants in operation are:


District of Columbia Public Service Commission

The District of Columbia Public Service Commission (formerly the District of Columbia Public Utilities Commission) is an independent quasi-judicial body and regulatory agency responsible for regulating landline telephone, electricity, and gas utility companies operating within the District of Columbia. It was established by the US Congress in 1913.
All PSC staff involved in formal cases are advisors to the Commissioners, including the Offices of the General Counsel (OGC), Technical and Regulatory Analysis (OTRA), and Consumer Services (OCS). The Office of the Commission Secretary and the Administrative Offices provides mediation services to consumers and businesses regarding complaints against utility service providers. OTRA also manages the natural gas pipeline safety program in the District.
History.
The PSC was created by act of Congress on March 4, 1913, after President William Howard Taft signed into law the District of Columbia Appropriations Act, which authorized the Public Utilities Commission (name changed to PSC in 1964) to "furnish service and facilities reasonably safe and adequate" to ensure that any charges were reasonable, just and nondiscriminatory; and it initially had jurisdiction over electric, gas, and telephone companies, including mass transit, such as street cars, buses, and public motor vehicles. In 1974, the Home Rule Act affirmed the PSC as an independent charter agency. Since 1913, 72 men and women have served as Commissioners.
Grid modernization.
Power Path DC is the PSC’s grid modernization plan to achieve a reliable, sustainable and resilient energy delivery system in the District.


Electricity sector in Bolivia

The electricity sector in Bolivia is dominated by the state-owned ENDE Corporation (Empresa Nacional de Electricidad), although the private Bolivian Power Company ("Compañia Boliviana de Energía Eléctrica"; COBEE) is also a major producer of electricity. ENDE had been unbundled into generation, transmission and distribution and privatized in the 1990s, but most of the sector was re-nationalized in 2010 (generation) and 2012 (transmission and distribution).
The supply is dominated by thermal generation (65%), while hydropower (35%) has a smaller share in its generation mix compared to other South American countries. (Latin America and the Caribbean, or LAC, average hydropower capacity is 51%.) In 2014, national electricity supply of 1580.35 MW comfortably exceeded the 1298.2 MW maximum demand. Like in other countries, Bolivia's electricity sector consists of a National Interconnected System (SIN) and off-grid systems (known as the "Aislado").
The national government's priorities for the electricity sector include providing universal access to electricity and producing surplus energy for export. The electricity coverage in rural areas is among the lowest in Latin America and improving it represents a major challenge in the future. The government envisions a major expansion of electricity generation capacity to over 8,000 MW over the decade from 2015 to 2025, primarily to export surplus generating capacity.
Electricity supply and demand.
Installed capacity.
In Bolivia, the National Interconnected System (SIN) connects major population centers and represents 83% of the installed capacity. The SIN provides electricity to the largest cities and operates in the Departments of Cochabamba, Santa Cruz, Oruro, Potosí and Chuquisaca. Its grid extends over 1,200 miles and covers the central and southern parts of the country. The population in the northern and western parts of the country remains largely unconnected to the national grid, either served by the off-grid system (the "Aislado") or having no access to electricity at all. The off-grid system consists of numerous self producers and independent power plants in rural or isolated areas.
Total installed capacity in 2006 was 1.43 GW, of which 60% was thermal production, which primarily burns natural gas, and 40% hydroelectric. The contribution of other renewables is almost negligible. Total electricity production in the same year amounted to 5.29 TWh. This figure does not include electricity produced in rural areas from biomass facilities, which are unorganized, decentralized, and difficult to quantify.
Bolivia's electricity export and import activities are fairly limited. Imports from Brazil amount to less than 0.01 TWh per year and have so far been devoted to supply the city of Puerto Suarez, in the Department of Santa Cruz.
Demand.
Electric power consumption per capita in 2006 was 588 kWh (a 19% increase since 1996). By sector, residential consumption represents 40% of the total, followed by industrial consumption with 28%.
Demand and supply projection.
According to the demand projections prepared by the "Superintendencia de Electricidad" (SE), the generation capacity reserve will be insufficient by 2009 as it will fall below the recommended 10% if no new capacity is developed.
Access to electricity.
In 2005, total access to electricity in Bolivia was 67%, one of the lowest in Latin America. Urban access was 87%, while rural access remained as low as 30%.
Interruption frequency and duration.
Service quality as measured by interruptions was much better than the LAC average in 2005. In the period November 2004 – October 2005 there were a total of 141 transmission interruptions (up from 86 in the previous period), with a total duration of 4,274 minutes. 57% of the interruptions were due to weather conditions and, while 17% derived from facility operations. In 2005, the average duration of interruptions per subscriber was 5 hours (highest since 1998 although far below the 14 hours average for LAC), while the average number of interruptions per subscriber per year was 7 (highest since 1995 but also below the 13 average for LAC).
Distribution and transmission losses.
During the 1990s and up to 2005, distribution losses have always been close to 10%, which is below the 13.6% average for the region.
Responsibilities in the electricity sector.
Policy and regulation.
The Viceministry of Electricity and Alternative Energy, within the Ministry of Petroleum and Energy, is in charge of establishing policies and designing the regulation for the electricity sector. The "Superintendencia de Electricidad " (SE) is responsible for applying the regulation.
The companies that belong to the National Interconnected System (SIN) must be vertically unbundled. However, the companies in the off-grid system (the "Aislado") are allowed to perform more than one of the activities defined in the electricity industry (i.e. generation, transmission, distribution).
Generation.
Currently, there are eight generation companies in the interconnected system, all of them privately owned. The three largest companies alone represent 70% of the total generation. The largest company serving the SIN is the " Compañia Boliviana de Energía Eléctrica" (COBEE), which serves the region surrounding La Paz. The other two are "Empresa Eléctrica Guarachi" (EGSA) and "Empresa Eléctrica Corani" (CORANI).
Transmission.
Currently, there are three transmission companies which operate the high-voltage Interconnecting Trunk System (STI), the backbone of the SIN. ENDE Corporation, ISA Bolivia, which was created in 2005, and San Cristobal TESA. The state-owned ENDE incorporates "Transportadora de Electricidad" (TDE), which was owned by Spain's Red Electrica de España (REE). As of 2013, its transmission network extended 2,850 km, representing 79% of the national total. ISA Bolivia, which runs 587 km, or 16%, of the transmission network in Bolivia, is a subsidiary of Interconexión Eléctrica S.A. (ISA), a corporation controlled by the government of Colombia. San Cristobal TESA has 172 km of transmission lines, or 5%. The number of companies is limited due to the existence of institutional entry barriers in this sector.
Distribution.
In Bolivia, the six existing distribution companies enjoy a geographic monopoly in their concession areas. The largest company is Electropaz, majority-owned by Spain's Iberdrola; followed by "Empresa de Luz y Fuerza Eléctrica Cochabamba" (ELFEC), which was owned by the American PPL Global until 2007. The third place is occupied by the Rural Electrification Cooperative (CRE), which operates in the Department of Santa Cruz.
In some cases, especially in the high plateau, cooperatives and community organizations access the distribution companies’ network and sell electricity to small rural communities. Sometimes, those are organized enterprises that provide the service to middle-size towns, but in most cases, they are small organizations that serve family communities. This situation faces a legal vacuum since the consumers benefiting from these scheme, who do not consume the minimum power established legally established, cannot be considered as regulated ones. In addition, these consumers are localized outside the distribution companies’ concession areas, so they cannot receive the companies’ service. In practice, the distribution companies are reselling electricity to the mentioned organizations outside the legal framework. Accurate information on the number of organizations that operate in rural areas does not exist. However, there are approximately three in La Paz, twenty in Oruro and three in Potosi.
Operators in the off-grid system.
The departments of Beni, Pando and Tarija and the eastern region of Santa Cruz are not integrated in the SIN. As a result, there are vertically integrated operators that provide the service. The most important operators are:
Renewable energy resources.
Renewable energy resources other than hydropower are barely exploited in Bolivia, and their contribution to electricity generation is insignificant. However, the potential of decentralized electricity systems (i.e. solar photovoltaics or PV, wind, etc.) for disperse populations was recognized by the government in the Rural Electrification Plan (PLABER). This component established that the service to households, schools and health facilities in areas of low population density would rely on locally available renewable energy sources.
Hydropower.
Bolivia has a considerable hydro potential, its technically feasible potential being assessed at 126 TWh/yr, of which 50 TWh/yr is considered to be economically exploitable. Only a small proportion of the total potential has been harnessed so far.
The share of hydropower capacity in Bolivia is 40%, which is below the 51% average for the region. Installed hydroelectric capacity in 2016 was 494 MW, distributed amongst some 21 facilities. The largest plant is the 93 MW Saint Isabel, operated by Corani.
Bolivia is working with Brazil on a huge joint project to exploit the hydro-electric potential of the Rio Madeira complex in the Amazon region. Within this project are the 800 MW Cachuela Esperanza plant sited entirely in Bolivia and the Guajara-Mirim plant (3000 MW) to be located on the border between the two countries.
Solar.
The World Bank is financing a rural infrastructure project in Bolivia which, among others, plans to install 17,000 solar home systems by 2009. Another project funded by the Global Partnership on Out-based Aid which is administered by the World Bank intends to scale up the installations by an additional 7000 in the next three years. (see External Assistance below)
In the mid-2010s, ENDE began building and operating large-scale solar power plants including the following:
History of the electricity sector.
Early history.
The National Interconnected System (SIN) was created in 1965 and continued its expansion during the ‘70s and ‘80s.
Unbundling and privatization.
Until 1994, the vertically integrated public utility, ENDE ("Empresa Nacional de Electricidad") dominated the sector. In 1994, Bolivia initiated an infrastructure reform program that included the privatization of the major state owned enterprises. The Electricity Law 1994/1604 mandated the privatization of the electricity system and the unbundling of generation, transmission and distribution activities. The law aimed to increase efficiency in the sector, promote competition and encourage investment.
As a result of privatization, three generation companies were created: Corani, Guaracachi and Valle Hermoso. Each of them received a part of ENDE's generation activities (the law limited the market share of each to 35%). Initially, these firms were granted exclusive rights, but by 1999 entry was liberalized and some other small companies entered the market. In regards to transmission, network operation was transferred from ENDE to "Transportadora de Electricidad", a private company, which acquired exclusive rights. Finally, several distribution firms were created after the reform. All those firms operate under tariff regulation and are subject to tariff controls. CRE (Cooperative for Rural Electrification), a pre-existing distribution cooperative, maintained its position as an independent regional monopoly. CESSA ("Compañía Eléctrica de Sucre S.A.") and SEPSA ("Servicios Eléctricos Potosí S.A. "), two pre-existing municipal distribution firms also maintained their monopolies while ELFEC ("Empresa Luz y Fuerza Eléctrica Cochabamba"), which was a municipal company previously to privatization, started to operate as a private firm. Lastly, the private COBEE ("Compañía Boliviana de Energía Eléctrica"), which operated both in generation and distribution, gave rise, after its divestiture, to Electropaz (in La Paz) and ELFEO ("Empresa Luz y Fuerza Eléctrica Oruro") (in Oruro).
All these reforms, together with the introduction of a load dispatch coordination office, shaped a wholesale electricity market that seeks to simulate competitive conditions.
Rural electrification efforts.
In 2002, the government established Bolivia's Rural Electrification Plan (PLABER) with the objective of contributing to the socio-economic development of rural areas through access to electricity and its efficient and productive uses. The short-term goal of the program was to make 200,000 new connections within five years (increasing electricity access in rural areas from 23% to 45%). It had been estimated that, by the end of the program, PLABER would have reached its goals by 70% of the initial objective. However, the model established by this program did not have significative effects in increasing coverage, expanding infrastructure and improving service quality in rural and isolated areas.
A new Rural Electrification Decree was approved in 2005 (Supreme Decree No. 28567). This new decree aims at increasing rural access through the extension and densification of electric networks, development of renewable energy and a change in the energy mix (substitution of diesel by natural gas, biomass and other renewable energies) and an increase in distribution capacity. The Rural Electrification Decree and its associated regulatory framework encourages stakeholders in the energy sector to establish partnerships with other government agencies to implement the rural electrification plan. An agreement between the Ministry of Public Works, Services and Housing and the Ministry of Education will allow for the installation of solar PV systems in rural areas in conjunction with the literacy program, “I can” ("Yo, sí puedo"). Under the pilot phase, 500 solar panels are expected to be installed.
Recent developments.
In 2006, under President Evo Morales, a new Law for Universal Access to Electricity ("Ley de Acceso Universal") was proposed. Under the framework of this Law, the program called ‘Electricity for a Decent Living” has been designed to improve both rural and urban electrification. The short-term goal (2006–2010) of the program is to increase rural electrification to 53% (connection of 210,000 new households) and urban electrification to 97% (connection of 460,000 new households). The medium-term goal (2010–2015) is to achieve universal access in urban areas and a 70% access in rural ones. In the final stages, rural access would have increased to 87% by 2020 and universal coverage would be reached by 2025. The Law also mandates de creation of a Common Fund for Universal Access to Public Electricity Service (FOCO) and creates a co-financing mechanism of the National Government with Prefectures, municipalities and the private sector. However, the Law has not been approved yet, although it is expected that the Law and the mechanisms it creates will be approved soon.
Tariffs, cost recovery and subsidies.
Tariffs.
Electricity tariffs in Bolivia are far lower than average tariffs in Latin America. The average residential tariff in 2006 was US$0.0614 per kWh (compared to US$0.115 per kWh weighted averagein LAC), while the average tariff for the industry was US$0.044 per kWh (compared to US$0.107 per kWh weighted average in LAC).
Electricity prices charged by the distribution companies to their regulated clients include energy costs (including generation and transmission costs) and all the distribution costs, including a specific return on investment. However, as it was mentioned before, some distribution companies resell electricity to communal organizations or rural enterprises. The price and conditions of those transactions are not regulated, which causes an important legal void in the sector.
Subsidies.
In March 2006, the Bolivian government approved "Tarifa Dignidad" (“Dignity Tariff”) by Supreme Decree 28653. This tariff grants a 25% discount in their electricity bills to those consumers whose monthly consumption is below 70 kWh in the urban areas and 30 kWh in the rural ones. This subsidy, which will be covered for four years by the electricity companies that operate in Bolivia, will benefit about 480,000 households.
Investment and financing.
In the years following the privatization of 1994, investment grew considerably due to the obligations imposed on the privatized companies. Public investment remained constant, mainly directed to rural electrification, while private investment was mainly devoted to generation.
In the period 1995-2004, total investment in transmission represented only a modest 2% (US$14 million) of the total investment in the electricity sector. Generation and distribution received 58% and 40% of total investment respectively. For the year 2004 in particular, total public investment in the electricity sector was around $US 20million which was matched by another $US20 million from private sources. Those two figures add up to less than 0.5% of Bolivia's GDP in 2004.
Distribution companies acquire investment commitments for each tariff period. For the period 2003-2005, total investment by the main distribution companies was US$39.7 million. This was divided as follows:
Summary of private participation in the electricity sector.
The Electricity Law 1994/1604 mandated the privatization of the electricity system and the unbundling of generation, transmission and distribution activities, which had all been in the hands of ENDE ("Empresa Nacional de Electricidad") the vertically integrated public utility.
Three of the eight generation companies in the interconnected system represent 70% of total generation, with COBEE ("Compañía Boliviana de Energía Eléctrica") being the most important. Transmission in the National Interconnected System is in the hands of just two companies as entry in this sector is institutionally restricted. As for distribution, the six existing companies enjoy a geographic monopoly in their concession areas. The largest company is Electropaz, which is majority-owned by Spain's Iberdrola.
In May 2010 president Evo Morales nationalized 80% of Bolivian generation by capacity, in his Government's attempt to regain ownership of public service companies. Corani, Guarachi, and Valle Hermoso, where expropriated from their former British and French owners. In the same fashion, in May 2012 the transmission company Transmisora de Electricidad S.A., from Spanish capitals, was similarly expropriated.
(*) 53% of the transmission network is operated by ISA Bolivia, a subsidiary of ISA Colombia, which is controlled by the Colombian government.
Electricity and the environment.
Responsibility for the environment.
The Viceministry of Land Planning and Environment, within the Planning and Development Ministry, holds the environmental responsibilities in Bolivia.
Greenhouse gas emissions.
OLADE (Organización Latinoamericana de Energía) estimated that CO2 emissions from electricity production in 2003 were 1.73 million tons of CO2, which represents 22 percent of total emissions for the energy sector.
CDM projects in electricity.
Currently, there are just two CDM-registered projects in Bolivia, one of them in the electricity sector. That is the Rio Taquesi Hydroelectric Power Project, in the province of Sud Yungas, with an effective capacity of 89.5 megawatts and estimated emission reductions of 141,691 metric tonnes CO2e per annum
External assistance.
External assistance to the electricity sector in Bolivia is heavily focused on rural electrification with no funding for large-scale generation, which has been fully privatized.
World Bank.
Currently, the World Bank is involved in two projects in the energy sector in Bolivia:
IDB.
The Inter-American Development Bank provides technical assistance through three projects in the energy sector in Bolivia:
CAF.
In 2005 and 2007, the "Corporación Andina de Fomento" (CAF) assigned US$32 million and US$15 million respectively to the increase of electricity services coverage through the construction of two transmission lines. The first one is the 115 kV Caranavi (La Paz)-Trinidad (Beni) line, which has 374 km. The second one is the 230 kV Carrasco and Santibáñez line, with 225 km.
Others.
The German Agency for International Cooperation (GIZ) and the Viceministry of Electricity and Alternative Energy recently signed an agreement to execute a Project for Network Densification in rural areas. Distribution cooperatives will also play an important role in this project, which is part of the program “Electricity to live with dignity”. To facilitate the access to electricity, the Viceministry and GIZ will provide a US$20 subsidy per household to enable their connection to the existing network.
The German development bank KfW is also financing a 5 million Euro project to improve rural access to electricity in 2005-8. The project involves the construction of six micro-hydroelectric plants and the completion of studies for another eleven.


Gas turbine modular helium reactor

The Gas Turbine Modular Helium Reactor (GT-MHR) is a nuclear fission power reactor design that was under development by a group of Russian enterprises (OKBM Afrikantov, Kurchatov Institute, VNIINM and others), an American group headed by General Atomics, French Framatome and Japanese Fuji Electric. It is a helium cooled, graphite moderated reactor and uses TRISO fuel compacts in a prismatic core design.
Construction.
The core consists of a graphite cylinder with a radius of 4 m and a height of 10 m which includes 1 m axial reflectors at top and bottom. The cylinder allocates three or four concentric rings, each of 36 hexagonal blocks with an interstitial gap of 0.2 cm. Each hexagonal block contains 108 helium coolant channels and 216 fuel pins. Each fuel pin contains a random lattice of TRISO particles dispersed into a graphite matrix. The reactor exhibits a thermal spectrum with a peak located at about 0.2 eV. The TRISO fuel concept allows the reactor to be inherently safe. The reactor and containment structure are located below grade and in contact with the ground, which serves as a passive safety measure to conduct heat away from the reactor in the event of a coolant failure.
Advantages.
The Gas Turbine Modular Helium Reactor utilizes the Brayton cycle turbine arrangement, which gives it an efficiency of up to 48% – higher than any other reactor, as of 1995. Commercial light water reactors (LWRs) generally use the Rankine cycle, which is what coal-fired power plants use. Commercial LWRs average 32% efficiency, again as of 1995.
Energy Multiplier Module (EM2).
In 2010 General Atomics conceptualized a new reactor that utilizes the power conversion features of the GT-MHR, the Energy Multiplier Module (EM2). The EM2 uses fast neutrons and is a gas-cooled fast reactor, enabling it to reduce nuclear waste considerably by transmutation.


Andrew Blakers

Professor Andrew Blakers is Director of the Australian National University "Centre for Sustainable Energy Systems", which employs 60 staff. He is responsible for several innovations in solar energy photovoltaic technology, including "Sliver cells". Blakers has secured many research grants and won several awards.
Sliver cell.
Sliver Cell photovoltaic technology uses just one tenth of the costly silicon used in conventional solar panels while matching power, performance, and efficiency. Blakers invented the technology with colleague Dr Klaus Weber and developed it with funding from energy supplier Origin Energy and the Australian Research Council.
Honours.
Blakers and Klaus Weber won the Australian Institute of Physics' Walsh Medal for their solar research work.
He was 2012 state finalist for the Australian of the year award, in the Australian Capital Territory.


Genex Power

Genex Power () is an Australian electricity generation company. It owns the Kidston Solar Project which has been generating up to 50 MW of electricity since 2017. It is developing the associated Kidston Pumped Hydro storage using the abandoned Kidston Gold Mine.
Genex Power later proposes to expand the solar farm and add a wind farm in the same area.


Deriaz turbine

The Deriaz turbine, presented by engineer Paul Deriaz, was the first diagonal hydraulic pump-turbine to be designed. In contrast to most hydraulic machines, the flow in a Deriaz turbine does not follow a full axial nor radial direction but is a diagonal mixture of the two. Deriaz turbines, like Kaplan turbines, can also have adjustable runner blades to reach highest efficiencies at variable discharge (double regulation). Deriaz turbines are installed at the Sir Adam Beck Pump Generating Station at Niagara Falls.
The combined use of adjustable runner blades with moving guide vanes allows Deriaz pump-turbine to reach high performance under a large range of working conditions. This makes the Deriaz pump-turbine an extremely suitable turbomachine solution for high variable load. Recent investigation supported by experimental data and computational fluid dynamics (CFD) simulations, shows clearly how a downsized prototype preserves versatility over a wide range of partial load for pumping and generating modes.
As the adjustment of runner blades is mechanically complex, Deriaz turbines with fixed blades have been developed. The adjustment to variable discharge is realized by variable runner speed based on modern inverter technology.


Edwin Lyman

Edwin Lyman is Senior Global Security Scientist with the Union of Concerned Scientists (UCS). He specialises in nuclear proliferation, nuclear terrorism, and nuclear power safety. He has published many articles in journals and magazines, written many reports, and has been cited in many news stories. Before joining UCS in 2003, Lyman was president of the Nuclear Control Institute. He has a doctoral degree in physics from Cornell University.
Opinion on post 9/11 regulation.
According to Lyman, despite the events of September 11, the U.S. Nuclear Regulatory Commission (NRC) has voted to delay implementation of safety and security upgrades in ways that will weaken protection of nuclear power plants. Lyman says that these new moves illustrate an "ominous trend".


Northwest Power Generation Company

North-West Power Generation Company Limited (NWPGCL) is a state owned power and electric company in Bangladesh and is located in UTC Building (Level 3 & 4), 8 Panthapath, Kawranbazar, Dhaka, Bangladesh. It is an enterprise of the Bangladesh Power Development Board (BPDB).
History.
North-West Power Generation Company Limited (NWPGCL) was established on 28 August 2007 as a Public Limited Company under the Bangladesh Power Development Board. Bangladesh-China Power Company (Pvt.) Ltd (BCPCL) a joint venture between China National Machinery Import and Export Corporation (CMC) and North-West Power Generation Company Limited (NWPGCL) built a 1,320MW power plant in Patuakhali District near Payra Seaport. Bangladesh-China Power Company (Pvt.) Ltd (BCPCL) was formed in 2014. NWPGCL has four power plants in Sirajganj, Bheramara, Kustia, Bagerhat and Khulna. Northwest Power Generation Company Limited has joint ventures with Siemens to build a 4 billion dollar power plant. It has joint venture with Sembcorp Utilities of Singapore to build a 414-megawatt power plant in Sirajganj. It also has joint collaboration with the Japanese Marubeni.


Sierra Pacific Power Company


Hsin Tao Power Corporation

The Hsin Tao Power Corporation () is an independent power producer company in Taiwan. It involves with the power sales business scheme for 25 years with Taipower.


Entergy New Orleans

Entergy New Orleans, formerly New Orleans Public Service Incorporated (NOPSI), is an electric and natural gas utility and former mass transit provider that was based in New Orleans, Louisiana.
The various streetcar lines of New Orleans were consolidated under NOPSI's control in 1922. Throughout the 1950s and 1960s, NOPSI converted all the original streetcar lines in New Orleans, except for the St. Charles Streetcar Line, to bus service.
It was headquartered in a building built in 1929, which later became the NOPSI New Orleans hotel.
In 1983, control of the system's mass transit was transferred to a public agency, the New Orleans Regional Transit Authority. NOPSI became Entergy New Orleans, a subsidiary of Entergy, in April of 1996.


Hindustan Power

Hindustan Powerprojects Private Ltd. (HPPPL), formerly known as Moser Baer Projects Pvt Ltd, is an electrical power developer in India, started by Ratul Puri. It operates in power generation, power trading, EPC, and development and renewables across thermal, solar, hydro and mining vertical markets. The company holds assets of around ₹ 14,500 crore to date, and is the fastest growing integrated power company in India.
The company is headquartered in New Delhi, India. HPPPL plans to commission new power projects by the year 2020 in thermal, hydro and solar sectors. The company is at an advanced stage of commissioning over 5000 MW by 2017 of combined power assets at an estimated investment of INR 32,000 crores (US$5.15 bn).
Ratul Puri is the company Chairman. Awadh Bihari Giri is the CEO of the Hydro division; Birendra Kumar Sinha, President, Coal; Lajpat Shrivastav is the CEO of Thermal; Rajya Wardhan Ghei is the CEO of India Solar Business; Arun Kanchan is the CEO of New Business, and Dr. Harish Ahuja is the President for Strategy and Corporate Affairs.
Hindustan Powerprojects (HPPPL) recently announced to plan its Unit IPO. The company backed by Blackstone Group LP (BX), plans to sell shares in its solar unit as it prepares to double investment in photovoltaic projects to $50 billion by 2016. The unit has a pipeline of projects that will require $45 billion of investment within the next two years.
Divisions and operations.
Hindustan Cleanenergy (Solar business) was incorporated in September 2008 to undertake development of solar projects in India and abroad to deliver clean energy. It is India's largest solar power development company, with solar projects under development across multiple states in India and strategic international markets like Germany, Italy, Japan, United States and United Kingdom. The solar arm of HPPPL was responsible for India's first 5 MW solar farm along with Asia's first 30 MW farm. Hindustan Cleanenergy is the largest solar farm developer in India with an installed capacity of ~ 350 MW generating carbon savings of approximately 500000 tonnes per year. The international solar business has an installed solar capacity of over 120 MW across locations like Germany, Italy, UK and US. The company is working towards launching the country's first 1 GW solar plant by the end of 2016 by launching IPO in end 2014 or early 2015.
Hindustan Electricpower (Hydro business) undertakes development of hydropower projects towards building a low carbon economy and meeting the need for environmental management. Currently, the company is exploring options of setting up hydropower projects in North, North-east India and Nepal. On-going projects include undertakings on Chenab River and its tributaries Lahaul and Spiti in Himachal Pradesh with a combined generation capacity of about 560 MW, along with two projects in Sikkim aggregating to 65 MW.
Hindustan Thermalprojects (Thermal business) division of HPPPL was incorporated in 2008 with the aim of foraying into infrastructure and thermal power. Operations include coal or gas based generation, transmission and distribution. The company aims to build a thermal generation portfolio of 5000-6000 MW by 2020. Current projects include three ventures in Madhya Pradesh and Chhattisgarh, with a combined generation capacity of around 5000 MW. The company's 2520 MW thermal power project at Anuppur, Madhya Pradesh is slated for commission in 2014. Hindustan Thermalprojects, the thermal business of Hindustan Powerprojects (HPPPL) won the National Safety Council (NSCI) award towards implementing effective occupational safety and health practices in its Anuppur unit in Madhya Pradesh. This is the second time in row for this plant.
Natural Resources (Mining business) began its operations in 2008 for building coal assets in India and abroad to support the company's coal-based thermal segment and become a prominent coal supplier to contribute to HPPPL's organic growth. It also provides consultancy services to the mineral industry in form of planning, operation optimization and value addition. The division's first mining project resulted in form of a joint venture with Chhattisgarh Mineral Development Corporation Limited, a Government of Chhattisgarh undertaking, as a partner for development of a commercial coal block.


Solar power in China

China is the world's largest market for both photovoltaics and solar thermal energy.
Since 2013 China has been the world's leading installer of solar photovoltaics (PV).
In 2015, China became the world's largest producer of photovoltaic power, narrowly surpassing Germany.
In 2017 China was the first country to pass 100 GW of cumulative installed PV capacity. By the end of 2020, China had more than 250 GW of installed solar capacity. As of May 2018, China held the record for largest operational solar project in its 1.5GW project at Tengger.
In late 2020, China turned on its largest solar farm with a capacity of 2.2 GW in Qinghai province. The contribution to the total electric energy production remains modest as the average capacity factor of solar power plants is relatively low at 17% on average.
Of the 6,412 TWh electricity produced in China in 2017, 118.2 TWh was generated by solar power, equivalent to 1.84% of total electricity production.
In 2019, China generated 234 TWh of electricity from solar power. At the 2020 Climate Ambition Summit, China announced that its goal is to reach 1,200 GW of combined solar and wind capacity by 2030.
Solar water heating is also extensively implemented, with a total installed capacity of 290 GWth at the end of 2014, representing about 70% of world's total installed solar thermal capacity.
History.
According to plans unveiled by the National Development and Reform Commission in 2007, China's installed solar capacity was to grow to 1,800 MW by 2020.
However already in 2009, Wang Zhongying, a Commission official, mentioned at a solar energy conference in Shanghai that the plan might be exceeded several-fold, with the installed capacity possibly reaching as much as 10 GW by 2020.
In 2010 a new feed-in tariff was introduced.
Projects completed before 30 September 2012 received 1.15 yuan ($0.18) per kWh.
Since then, solar power deployment vastly exceeded initial government plans.
The 200 MW Huanghe Hydropower Golmud Solar Park was completed in 2011, the world's largest solar farm at the time.
There were many other solar farms in Golmud, totaling 570 MW at the end of 2011, with another 500 MW expected in 2012.
The Qinghai province, which contains Golmud, was leading China in solar installations.
The Chinese PV production system faced severe external shocks since 2010. A sharp recession in the global demand due to institutional alterations in the German market in 2010, followed by anti-dumping duties and anti-subsidy countervailing duties on Chinese PV products enforced in both USA and EU. Chinese PV manufacturers, which were already running at full capacity, faced a difficult situation in 2011 and 2012 with huge financial losses that led to the bankruptcy of some important companies, such as SunTech Power in 2013 which defaulted on $541 million of convertible bonds. To rescue the huge PV industry with its large labor market and assets, a comprehensive set of policies was introduced by the Chinese government mainly to stimulate the domestic market. Accordingly, the annual installed capacity in China experienced notable growth since 2011. This growth was mainly due to the construction of several PV power plants around the country.
In May 2011, the National People's Congress (NPC) revised the solar target again, setting 5 GW as an official minimum PV target for 2015, with a longer-term target of 20–30 GW by 2020.
According to a 2012 forecast by the European Photovoltaic Industry Association, the total installed capacity was predicted to reach between 47 GW and 66 GW by 2017.
In May 2014, the National Development and Reform Commission announced that the solar capacity target had been increased, to 70 GW by 2017.
In October 2014 China planned to install 100 GW of solar power—along with 200 GW of wind, 350 GW of hydro and 58 GW of nuclear power by 2020.
Market research firm NPD Group forecast that China would have over 100 GW of PV capacity by 2018.
In October 2015, China's National Energy Administration (NEA) set an ambitious 23.1 GW target for 2015, upgrading its previous target of 17.8 GW from March 2015, which was already more than the global PV capacity installed in 2010.
At that time, China planned to install 150 GW of solar power by 2020, an increase of 50 GW compared to the 2020-target announced in October 2014.
The goal set by the Chinese authorities of 105 GW solar capacity for the year 2020 was passed in July 2017.
China installed 43 GW of solar power in the first nine months of 2017, already above the 34.5 GW target for the whole year.
This caused the Chinese Government to more than double the original target to 213 GW for 2020.
CCB International Securities Ltd. raised its forecast for China's solar power capacity to 55 gigawatts from 40 gigawatts for 2018. Of the 7482 TWh of electricity produced in 2019, China's solar power generated 234 TWh or 3.1%, which is higher compared to the corresponding share of 1.2% in the United States.
Solar resources.
A July 2019 report found that local air pollution (black carbon and sulfur dioxide) has decreased the available solar energy that can be harnessed today by up to 15% compared to the 1960s.
Solar photovoltaics.
Solar PV by province.
A large part of the solar power capacity installed in China is in the form of large PV power plants in the west of the country, an area much less populated than the eastern part but with better solar resources and available land.
Solar PV by type.
In 2018 23,300 MW of utility scale power plant installations were added bring the cumulative total in this sector to 123,730 MW of power. Distributed installations rose by almost as much during 2018 at 20,960 MW bringing the cumulative total in the sector to 51,250 MW by year end 2018. Off-grid solar was the smallest component in 2018 with just 360 MW cumulatively installed.
Manufacturers.
China has been the world's largest manufacturer of solar panels since 2008 and, since 2011, has produced the majority of global photovoltaics on an annualized basis.
Industry projections estimated that, by the end of 2017, China would have enough manufacturing capacity to produce 51 GW of PV modules per year, an amount over twice as large as 2010's global production of 24 GW.
The industry is dominated by several major manufacturers.
They include CHINT Group Corporation, JA Solar Holdings, Jinniu Energy, Suntech Power, Yingli, China Sunergy and Hanwha SolarOne.
Large debt challenges several manufacturers.
Concentrated solar power.
China has large potential for concentrated solar power (CSP), especially in the south-western part of the country.
The highest daily mean values of direct normal radiation are found in the Qinghai-Tibet Plateau and Sichuan Basin, at 9 kWh/m2.
Most of northern and western China has daily average direct normal radiation over 5 kWh/m2, considered the limit for economical use of CSP.
Practical limitations for deployment of CSP include mountainous terrain and distance from energy load centers, mostly concentrated in the east.
The 12th five-year plan, for 2011 to 2015, called for the installation of 1,000 MW by 2015, and 3,000 MW of CSP plants by 2020.
However, at the end of 2014, only 14 MW of CSP was operational in the country.
Plants planned or under construction:
Solar water heating.
China is the leading country for solar water heating capacity in the world, with 290 GWth in operation at the end of 2014, accounting for about 70% of the total world capacity. In terms of capacity per unit of population, China comes 7th in the world with 213 kWth per 1,000 people. Most of the installed capacity (92%) was evacuated tube water heaters.
Controversy.
China is a large producer of polysilicon, for use in first generation solar cells around the world. A byproduct of the process is poisonous silicon tetrachloride, which is normally processed and recycled at a higher cost in the developed world, but often dumped by Chinese green startups, With proper recycling the polysilicon would cost $84,500 per tonne, but the Chinese companies are making it at $21,000 to $56,000 a ton.
Zhejiang Jinko Solar Co., Ltd., founded in 2006 as a subsidiary of Hong Kong-invested JinkoSolar Holding Co, Ltd (NYSE Stock Code: JKS), produces solar panel photovoltaic cells and wafers. It employs more than 10,000 professionals in two factories in east China and has offshore offices and warehouse in the United States and Europe, according to the company website (www.jinkosolar.com). On Thursday, 15 September 2011, more than 500 people from Hongxiao Village protested over the large-scale death of fish in a nearby river. Angry protesters stormed the factory compound, overturned eight company vehicles, and destroyed the offices before police came to disperse the crowd. Protests continued on the two following nights with reports of scuffle, officials said. Chen Hongming, a deputy head of Haining's environmental protection bureau, said the factory's waste disposal had failed the pollution tests since April. The environmental watchdog has warned the factory but it had not effectively controlled the pollution, Chen added.
The Chinese government subsidies for solar energy (PV) have been described as "unsustainable" (although reduced in 2017) and are sometimes paid late to generating companies. Much of the solar power generating capacity has been built in the relatively less populated west of China whereas the major electricity consumption areas (such as Shanghai and Beijing) are in the east causing difficulties and expense in transferring the energy between regions with curtailment rates of 30% or more reported in 2017.


Solar power in Belgium

Solar power in Belgium reached an installed capacity of 4,254 MW of power generating 3,563 GWh of electricity in 2018. In 2015 PV solar power accounted for around 4% of Belgium's total electricity demand, the 4th highest penetration figure in the world, although the country is some way behind the leaders Germany, Italy and Greece at between 7% and 8% of electricity demand.
Installed capacity grew at an outstanding pace from 2008 until 2012, but its growth has since slowed to a steady pace. Almost all of solar power in Belgium is grid connected.
Timeline.
2016
Solar PV per capita grew to 302.8 Watts, remaining the third highest in the EU.
2015
In 2015 Solar PV per capita amounted to 287 Watts, the third highest in the world after Germany and Italy, providing around 4% of Belgium's total electricity demand.
2014
In the afternoon of 20 March 2014, a new record of peak electricity generation had been achieved. According to the power supplier Eneco Energie, more than two gigawatt of electric power, corresponding to two full-sized nuclear power plants, were generated by solar PV and supplied more than 20 percent of the overall electricity consumption at the time.
2013
In 2013, Belgium's "watt per capita" distribution, the total installed photovoltaic capacity per inhabitant, amounted to 267 watts. This was the third highest per-capita figure in the European Union—and therefore also in the world at that time—just behind Germany (447 watts) and Italy (295 watts). In terms of the overall installed capacity of 2,983 MW, Belgium ranked tenth and belonged to the Top 10 leading photovoltaic countries in the world.
2011
At the end of 2011 the bulk of photovoltaic capacity was installed in the Flemish Region (88%), the remaining 12% was found mostly in Wallonia. The smaller Brussels-Capital Region had an installed capacity of 7 MWp. .
2009
In December 2009, there were 35,500 solar power installations in the Flemish region, 17,000 in Wallonia and 7,000 in the Brussels Capital Region. The number of installations in the Flemish region in particular was expanding rapidly at that time due to a favourable support measure expiring at the end of the year.
2007
Installed capacity of solar power increased drastically after 2007. During 2009 the amount of solar installations quadrupled from 16,000 to 65,000. Residential and small installations had a combined power of about 220 MWp.
Solar PV market by segment.
Nearly 63% of solar power installed in Belgium in 2017 was for small systems of less than 10 kW, mostly residential rooftop Solar PV. Larger systems over 250 kW accounted for almost 20% of the total.
Residential Solar PV Capacity.
According to a report on behalf of the European Commission in 2015 Belgium Flanders had an estimated 1,301 MW (666 MW) of residential solar PV capacity with 336,000 (232,000) residential solar PV prosumers in the country representing 7.1% (3.7%) of households. The average size of residential solar PV systems is estimated to be 3.87 kW moving to 2030. The technical potential for residential solar PV in Belgium Flanders is estimated at 7,327 MW and Belgium Wallonia at 3,753 MW . The payback time for residential Solar PV in Belgium Flanders was 14.7 years whilst in Belgium Wallonia it was 6.9 years as of 2015. Some of the advantages of small scale residential Solar include eliminating the need for extra land, keeping cost saving advantages in local communities and empowering households to become prosumers of renewable electricity and thus raising awareness of wasteful consumption habits and environmental issues through direct experience.
Flanders.
As of July 2012 there are 42,644 photovoltaic installations in the Flemish region that receive green certificates.
Subsidies.
Towards 2011, it became clear that Flemish subsidies for solar panels had a significant impact on the cost of electricity of households without a photovoltaic installation. An added cost of up to 148 EUR is charged annually. Flemish minister for Energy Freya van den Bossche admitted that subsidies were too high, especially for large-scale installations. The guaranteed minimum price for electricity produced was reduced. For small photovoltaic installations(less than 1 MW) it was reduced from 330 EUR per MWh to 250 EUR per MWh by January 2012 with the goal of reaching renewable energy targets at a reasonable cost. This resulted in a rally which caused the number of installations to almost double from 20,514 to 37,355 in 2011. The minimum price will be lowered further to 93 EUR per MWh from 2013 onwards.
Notable installations.
A solar park of 100MW is set to be built near the town of Lommel, in the Flemish province of Limburg. Construction will start in September 2018 and will be completed mid-2019. It will produce 83 GWh per year equivalent of the consumption of 24000 households.
In 2011 a above ground "tunnel", built to avoid having to fell trees for a new high-speed railroad, was covered with solar panels.
In December 2009, Katoen Natie announced that they will install 800,000 m² of solar panels in various places, including Antwerp. It is expected that the installed solar power in the Flemish Region will be increased by 25%, when finished. That will be the largest installation in Europe. The installation produces about 35 GWh yearly. The total cost will be 166 million euros.
In October 2009, the city of Antwerp announced that they want to install 2,500 m² of solar panels on roofs of public buildings, that will generate 265 MWh per annum.
In 2009, the city of Leuven installed 1,810 solar panels on public buildings.


Operating reserve

In electricity networks, the operating reserve is the generating capacity available to the system operator within a short interval of time to meet demand in case a generator goes down or there is another disruption to the supply. Most power systems are designed so that, under normal conditions, the operating reserve is always at least the capacity of the largest supplier plus a fraction of the peak load.
Types of operating reserve.
The operating reserve is made up of the spinning reserve as well as the non-spinning or supplemental reserve:
Generators that intend to provide either spinning and non-spinning reserve should be able to reach their promised capacity within roughly ten minutes. Most power system guidelines require a significant fraction of their operating reserve to come from spinning reserve. This is because the spinning reserve is slightly more reliable (it doesn't suffer from start-up issues) and can respond immediately whereas with non-spinning reserve generators there is a delay as the generator starts-up offline.
Centrally controlled air conditioners and thermostats that are used in large residential areas can be used as a fast and considerable operating reserve. Advantages of this technology are under studies.
Operating reserve is a crucial concept for ensuring that the day-ahead planning of generators' schedule can withstand the uncertainty due to unforeseen variations in the load profile or equipment (generators, transformers, transmission links) faults.
The California Independent System Operator has an operating reserve at 6% of the metered load. Included in that is a spinning reserve at 3% of the metered load.
Other types of reserve.
In addition, there are two other kinds of reserve power that are often discussed in combination with the operating reserve: the frequency-response reserve and the replacement reserve.


Central Illinois Public Service Company

The Central Illinois Public Service Company was an electric streetcar holding company and power utility first organized in 1902. Under its later quarter billion dollar holding company, CIPSCO Inc. (formerly ), it merged in 1997 with the larger neighboring Union Electric Company of Missouri (formerly ) to form Ameren Corporation () based in St. Louis, Missouri. Now a subsidiary, AmerenCIPS is headquartered in Springfield, Illinois.
History.
In 1902, in Mattoon, Illinois, the core of the company was born as the Mattoon City Railway Streetcar company, the first of the company's many later interurban electric railways.
In 1910, the Mattoon City Railway was reorganized as the Central Illinois Public Service Company.
In 1912, the CIPS Company became a subsidiary of Samuel Insull's Middle West Utilities Company. The utilities company then acquired 60 utility properties. In 1913, it built the 6,000-kilowatt Kincaid, Illinois, Power Station, the first large-generating power station.
In 1921, the CIPS Company headquarters moved from Mattoon to downtown Springfield, Illinois, where it acquired the Farmers Bank Building and Annex, and renamed it the Public Service Building.
In 1922, the CIPS Company gas and electric plants in Beardstown, Illinois, were flooded by the Illinois River and tributaries.
In 1923, CIPS merged with the Middle West Power Company, and acquired the Grand Tower, Illinois, Power Station in southwestern Illinois on the Mississippi River. The merger brought the company's holdings to seven generating stations, 15 ice plants, and two interurban railways.
In 1931, the CIPS Company tore down its general office building headquarters in downtown Springfield, and on the same site built a new 15-story skyscraper, as the new Public Service Building. It was later renamed the Illinois Building.
In 1932, the Middle West Utilities Company was reorganized as the Middle West Corporation, and CIPS Company was no longer under control of Samuel Insull. Middle West Corporation retained control of CIPS Company.
In 1933, CIPS Company ended electric railway operations with the abandonment of the Chicago and Joliet Electric Railway and the Southern Illinois Railway and Power Company.
In 1940, construction began on the second 25,000-kilowatt unit at the Hutsonville Power Station.
In 1948, CIPS Company gained independence from the Middle West Corp., and began to trade on the New York Stock Exchange under the symbol CIP, paying a dividend to stockholders. At that time, CIPS also sold its three remaining ice plants, because the new inexpensive electric refrigerators put an end to the "ice box" and the CIPS ice trucks which had been commonplace throughout central and southern Illinois.
In November 1949, a winter ice storm hit central Illinois, bringing down both CIPS primary and high-voltage transmission lines.
In 1952, the CIPS Company's Meredosia, Illinois, Power Station became a key contributor to the new Midwest Power Pool system, in conjunction with power provided by CIPS's future Ameren mate, the neighboring Union Electric Company, and also with another later Ameren subsidiary, Illinois Power Company.
By the early 1990s, Central Illinois Public Service Company, an electric and natural gas utility, was reorganized as a subsidiary under its new holding company, CIPSCO Inc., which in turn continued to publicly trade on the stock exchange under the utility's old ticker symbol, CIP.
In 1993, CIPSCO battled a 500-year flood in metropolitan St. Louis from the swollen Missouri and Mississippi Rivers.
In 1995, shareholders of both CIPSCO Inc. and another utility twice its size, the S&P 500-listed Union Electric Company, approved the merger of the two companies. The merger was completed on December 31, 1997, when they became Ameren Corporation. At the time of the merger, CIPSCO had assets of about US$210 million, but still carried nearly half of US$1 billion in long-term debt, which it had accumulated by the 1980s.
CIPSCO became one of Ameren's operating companies, doing business as AmerenCIPS. Ameren is now a holding company for several other power companies and energy companies as well. The CIPSCO name disappeared in 2010, when Ameren merged AmerenCIPS and its two other Illinois operating companies--Illinois Power (AmerenIP) and Central Illinois Light Company (AmerenCILCO) to form Ameren Illinois.
Criticisms.
2007 marked the end of a freeze on energy prices in Illinois. AmerenCIPS, along with subsidiaries AmerenIP and AmerenCILCO, have been criticized for not making proper preparations for the hikes in energy prices which were passed on to customers. According to Ameren, customers could expect to see their electricity bills increase by 22% to 55%. However, the media report that some bills are increasing much more, up to 300%.


Wind generation potential in the United States

The wind generation potential in the United States far exceeds demand. There are only two states with no commercially significant wind power potential, Mississippi and Florida. Florida has the potential to install 900 MW at 25% capacity factor -high turbines, and Mississippi the potential to install 30,000 MW at 25% capacity factor -high turbines. For commercial operation, a capacity factor of at least 35% is preferred. There are no locations in either state that would achieve 30% capacity factor. In contrast, North Dakota, the windiest state, has the capacity to install 200,000 MW at 50% capacity factor -high turbines. Texas, although not as windy, is larger, and has the capacity to install 250,000 MW at 50% capacity factor, and 1,757,355.6 MW of at least 35% capacity factor, capable of generating 6,696,500 GWh/year, more than all of the electricity generated in the United States in 2010.
By the end of 2011, the United States had installed 46,919 MW of wind power, and generated 94,652 GWh of electricity from wind power in 2010.
The annual production of a wind turbine is a product of the capacity rating, the capacity factor, and the number of hours in a year. A 200 MW wind farm at 35% capacity factor will generate approximately 613.2 GWh/year.
In addition to the megawatt wind farms, community scale single wind turbines of from 250 kW to 750 kW are typically 50 meters high, and residential or farm wind turbines are typically high. To address these markets, maps are available showing wind potential at and .
The United States generated 4,125,060 GWh of electricity in 2010.
N/A = Not Available
NA = Not Applicable (no shoreline)
The United States has trailed other countries in the development of off-shore wind farms, and it is possible that the first off-shore wind farm in the United States will be installed in either New England or New Jersey in 2013. Other locations that could be the first are Virginia, Maryland, and Texas.