Hydropower policy in the United States

Hydropower policy in the United States includes all the laws, rules, regulations, programs and agencies that govern the national hydroelectric industry. Federal policy concerning waterpower developed over considerable time before the advent of electricity, and at times, has changed considerably, as water uses, available scientific technologies and considerations developed to the present day; over this period the priority of different, pre-existing and competing uses for water, flowing water and its energy, as well as for the water itself and competing available sources of energy have changed. Increased population and commercial demands spurred this developmental growth and many of the changes since, and these affect the technology's use today.
Federal policies regarding the national water resources, within which hydropower exists, were already well-established long before modern electricity was known to exist; as such, previous uses and decisions, as well as government policies and agencies affected how hydropower was later developed. Chief among federal agencies was the involvement of the United States Army Corps of Engineers (USACE). While federal policy regarding interstate waters dates to the constitutional landmark decision under the Commerce Clause in 1824, its implementation was initially limited to development of navigation and its safety, among other demands for such internal improvements. Shortly thereafter, with the General Survey Act the USACE took the lead. By the 1850s and increasingly later, flood control was added to the demands for improvements, as well as recognizing the need to investigate and better understand the science involved. Much of these early improvements were legislated and authorized by rivers and harbors legislation and conducted by the Corps. With the advent of the progressive era before the turn of the 20th century, new, different and often competing technical demands were being made for water resource improvements, including irrigation in the western states and demand for the recently developed electric power in all states. Conservation and better utilization of natural resources in a historic relationship, first became topics of concern and consideration for policy at this time.
The hydroelectric industry has been and remains affected by the regulations and interests of various agencies and organizations. Since 1977 the Federal Energy Regulatory Commission (FERC) has been the main regulatory body for the industry. Currently FERC is responsible for licensing new project construction, as well as the re-licensing, and operations oversight of existing projects, including dam safety inspections and environmental monitoring. Environmental concerns and implications are evaluated by both federal and state Natural Resource agencies, Indian tribes, and state water quality agencies. Examples of such federal agencies include, but are not limited to, the Environmental Protection Agency (EPA), the Department of Agriculture's Forest Service, the Department of Commerce’s National Marine Fisheries Service, and the Department of the Interior. The National Hydropower Association is a hydropower trade organization which lobbies for policies which favor the industry.
Advancement of hydroelectric technology is accomplished through research and development programs, such as the Department of Energy's Hydropower Program. The use of hydroelectric technology is promoted by Renewable portfolio standards and various financial incentives. These financial incentives include: Renewable energy Production Tax Credits (PTC), loan Guarantees, Clean Renewable Energy Bond (CREB), and Qualified Energy Conservation Bonds (QECB).
Background and context.
Water is required for all life, but since ancient times, mankind has also employed this natural resource for other specifically human productive uses. Millennia ago man learned to navigate on water, learned to dam and divert it for irrigation and build aqueducts and canals to carry it where possible, and learned to convert the power of moving water to mechanical energy to perform work. They also employed basic wind and solar renewable energy for transport and heating. It took time before ancient cities learned to separate water supply from effluent and develop independent drainage for wastewater. Early on, in the United States, the federal government established policy on interstate navigation, with federal policy on flood control and irrigation developing later as outgrowths. Only since the age of electricity, a century ago, have larger scientific and policy concerns been expressed about conservation and the need to view water resources in a larger frame of natural resources generally, of public health aspects of water and its pollution. Federal planning on a broader policy basis began concurrently with the development of the country's hydropower potential. Since WWII, federal hydropower policy has become entwined within these and other broader policy concerns and it has been affected by them considerably; changes in hydropower policy have also attempted to address severe new challenges caused by the level of national energy consumption and questions of energy more globally defined, including its competing types, sources, as well as the sources and safety of competing fuels.
Upon its discovery European colonial and mercantile powers utilized America's great river systems to provide exploration by the navigation of its vast inland rivers. Over time these waterways became the transportation and trading routes which yielded the new world's vast riches, and soon became the object of rivalry between competing colonial powers. With this heritage and its independence the fledgling government wasted little time in establishing control over its borders, with trade in mind. With the country's vast unsettled western frontier, early policy and precedent was set in 1787 in the Northwest Ordinance, which established free usage of its interior waterways and connecting portages; these conditions would be included in the lands of Louisiana Purchase in 1803, which doubled the country's size, and later territorial acquisitions. The many rivers also provided the basis for advantageous settlement because water power was available to build water wheels and develop mills, generally where navigation was impeded by rapids or waterfalls and flow sufficient.
Following the court decision and passage of the General Survey Act, subsequent rivers and harbors acts were passed throughout the 19th century generally, except during financial crises and the Civil War; after the war, internal improvement spending rose considerably, particularly in the eastern states with abundant water resources.
During this time, new demands for flood control improvements began appearing, along with a new source of power from steam. By the 1830s, commercial success of steamboat navigation and transport became widespread and pushed demand for more river and canal improvements. Somewhat later, steam power was mated with wheels needing to be steered, and railroads developed to become another type of internal improvement. With much the same technical expertise as needed for earlier roads and canals, the Corps was assigned involvement; they also initiated scientific studies of rivers and their engineered improvements and structures.
As railroads expanded rapidly farther inland unchallenged, competition developed along previously existing or developed arterial routes, between older and slower navigation systems and the newer and faster railroads. One result over time was their acquisition and closing of existing canals, another result was the development of monopolistic and anti-competitive practices. Where railroads were not so directly involved, the decline in canal traffic developed alternative uses for the water power contained behind these dams and former locks. While these closed canal facilities could not be moved, their water power could be, in a fashion; in some locations the dammed water was otherwise piped through a penstock to multiple nearby locations lower downstream, to provide mechanical hydropower from increasingly more efficient water turbines.
With advancements in steam engine design, stationary units developed to supply power for mills at off-river locations, if a fuel source was available; over time fuels to produce power changed from burning biomass to burning fossil fuels, and the steam donkey could provide power in remote locations. Over this time lighting progressed from candles to whale oil or kerosene and gas if available.
Improving on earlier and less efficient water turbine designs in one historic mill town, the new Francis turbine was created in 1848, using scientific principles and testing methods producing a turbine design of 90% efficiency. More importantly, Francis's mathematical and graphical calculation methods advanced turbine design and engineering and allowed confident design of high efficiency turbines to exactly match a site's flow conditions. In the 1870s and deriving from uses in the mining industry, the high efficiency Pelton wheel impulse turbine was developed to use hydropower under very different flow and pressure conditions. Advances in dam design also progressed, with the completion of Old Aswan Dam being considered a milestone of engineering over nature. At the time of its construction, nothing of such scale had ever been attempted: it also became one of the first dams to be limited by conservation considerations.
History.
Legislation specifically regarding hydropower in the United States first appeared in 1901 with the first Federal Water Power Act, which required special permission for a hydroelectric plant to be built and operated on any stream large enough for boat traffic. It was later regulated with the establishment of the Tennessee Valley Authority following the Great Depression in the 1930s.
Federal Power Act overview.
The Federal Power Act was enacted in 1920 with the purpose of organizing and regulating hydroelectric projects at the national level. Hydropower is still a component of this Act, but additional legislation has been added since its creation. The Federal Power Act created the Federal Energy Regulatory Commission (FERC) as the licensing authority for hydroelectric power. Over time, FERC's task list grew to include conservation and protection of natural waterways and the wildlife within them. The Federal Power Act was the first major regulatory legislation for hydropower. The Act also defined what waters FERC had jurisdiction over: "Streams or other bodies of water over which Congress has jurisdiction to regulate commerce among foreign nations and among the States." (16 U.S.C. 796) This basically meant that FERC had unlimited power to oversee activities on any water on US soil.
Subsequent amendments to the Act included some wildlife provisions and more recently, stipulations that called for studies looking into the feasibility of increasing U.S. hydropower capacity using existing dams. This amendment, P.L. 102-486 (106 Stat. 3098), was approved in late 1992 and directs the Secretary of Energy to cooperate with the Secretary of the Interior and the Secretary of the Army and look for cheap ways to maximize power production at federally owned dam facilities. Money for the studies was accounted for in the DOE budget. An amendment in 1995 officially let the Secretary of the Interior and the Secretary of the Army take charge of the studies authorized in the 1992 amendment.
FERC’s responsibilities.
FERC is responsible for licensing, relicensing, and oversight of ongoing project operations such as dam safety inspections and environmental monitoring.
Licensing/relicensing.
As outlined on FERC's website, any hydroelectric project must apply for a license or an exemption from licensing if the project is or will be:
Licenses are valid for a 30 to 50-year period. FERC has three processes by which an applicant can file a license: integrated, traditional, and alternative.
Integrated licensing process.
The integrated licensing process is the default licensing process. The integrated licensing process was created to provide a “predictable, efficient, and timely licensing process that continues to ensure adequate resource protections.” FERC says that the process is founded in the following three principles:
FERC must give permission if an applicant wishes to use the traditional or alternative process. The regulations for the integrated licensing process are contained in 18 CFR Part 5.
Traditional licensing process.
The traditional licensing process consists of a three-stage pre-filing process through 18 CFR 4.38 for new licenses and 18 CFR 16.8 for relicenses. In the first stage, the applicant issues a notice of intent and a request to use a traditional licensing process. After FERC approves the use of a traditional licensing process, joint agency and public meetings are conducted along with site visits and written comments are accepted.
State role in Federal licensing.
As decided by the U.S. Supreme Court case S.D. Warren Co. v. Maine Board of Environmental Protection, the states have the power to impose restrictions on federal licensing or relicensing of hydropower facilities. The Court decided that a state can impose restrictions through water quality certification under Section 401 of the Clean Water Act. The terms and conditions of a federal license will incorporate the terms and conditions of the state's certification.
Exemptions from licensing.
FERC may issue two types of exemptions from licensing. While facilities that are granted these exemptions are not subject to the requirements of Part 1 of the Federal Power Act, they are still subject to any terms and conditions set by federal and state fish and wildlife agencies and FERC. The two exemptions are the small hydropower project and conduit exemptions.
Small hydroelectric power projects with capacities of 5MW or less may be exempt from federal licensing. These projects must either:
Exemptions are available for small conduit hydroelectric facilities with 15MW or less installed generating capacity (or if it's a municipal facility, 40MW or less installed generating capacity). The components of the facility have to exclude the conduit, the associated transmission lines, cannot be “an integral part of a dam”, cannot use a dam to supply its hydrostatic head, and cannot be located on Federal lands. The hydroelectric potential to generate the electricity must be supplied by a conduit. The water discharged by the facility must go into a conduit or be directly used for agricultural, municipal, or industrial consumption.
The term conduit in this context is defined as any tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity.
Dam and safety inspections.
FERC has created a plan for monitoring dam construction and operation called the Dam Safety Surveillance Monitoring Plan (DSSMP). This plan, created with the aid of dam owners, consultants, the National Hydropower Association and the Hydraulic Power Committee, outlines how an owner will monitor the safety and performance of a dam with respect to rules and regulations that govern them.
The plan includes sections on instrumentation, equipment maintenance, reading frequency and procedures, action levels, procedures should a failure occur and how reports sent to FERC must be formatted. The reports include photographs, diagrams and data taken at the dam.
Safeguarding the environment.
In regards to the environment, FERC's objective is to ensure that damage resulting from hydropower projects is minimized. They require that all applicants communicate with all relevant stakeholders before submitting applications. These stakeholders include federal and state Natural Resource agencies, Indian tribes, and state water quality agencies. FERC has developed an Initial Consultation Contact List to facilitate communication. FERC issues draft "Environmental Assessments" or draft "Environmental Impact Statements" and invites the public to comment. Electronic copies of the drafts and final versions are publicly available. In issuing licenses, FERC includes terms and conditions aimed to mitigate environmental impacts.
Environmental impact.
The construction of the large dams necessary to harness the power of water starkly change the natural shape of the environment. They can lead to soil erosion, the spread of disease, the loss of species and even, as one scientist claims, a change in the Earth's rotation due to huge amounts of water being moved to reservoirs. Also, the major amounts of concrete needed for these dams mean more CO2 being discharged into the atmosphere and promote runoff that limits the recharging ability of underground aquifers that provide potable water. Some legislation that seeks to curb the negative environmental effects of dam-building can be found below.
The Endangered Species Act.
One main hindrance in the licensing process is the Endangered Species Act (, et seq., ESA). Passed in 1973, this act sought to protect endangered species from the negative effects of anthropogenic actions. It distinguished between endangered and threatened species but applied the same protection to both. The reason it hinders the hydropower licensing and relicensing process is because it has priority over any government activity and therefore supersedes any construction project.
Section 7 of the Act requires that Federal agencies must insure that any action they condone is unlikely to affect the “existence of listed species or modify their critical habitat.” The list alluded to is also found in the Act and shows exactly which species must be considered. The Supreme Court came to the conclusion that Congress sought "to halt and reverse the trend toward species extinction, whatever the cost." The major consequences of the ESA and the Supreme Court's ruling in terms of hydropower proliferation are added costs, delays and site analyses that make dam construction much more difficult and less attractive to investors.
Because of the incredibly high construction and maintenance costs of dams and generation equipment, outside investment is key to the hydropower industry. This means that the ESA is a hindrance to the industry's growth. The protected species are largely aquatic types whose migration patterns and feeding habits might be affected by the construction and subsequent operation of a dam. In the Pacific Northwest, the Columbia River alone has seen the construction of 75 dams between 1930 and 1990. It led to the depletion of salmon populations that have since been added to the Endangered Species Act's list.
Besides getting killed during the construction and operation of dams, salmon stocks are dwindling because harvesting them becomes much easier now that the dams limit movement and increase their density in any one area. Thanks to the ESA, salmon populations have again swelled in the Columbia River and no new dams have been built since 1990.
Electric Consumers Protection Act.
The Electric Consumers' Protection Act (ECPA, 16 U.S.C. § 797, 803) was an amendment to the Federal Power Act and became law in 1986. It contained wildlife provisions, and requires that FERC "give equal consideration to non-power generating values such as the environment, recreation, fish, and wildlife, as are given to power and development objectives when making hydroelectric project licensing decisions." A major consequence of this provision was a large increase in licensing fees since major studies now had to be undertaken before any project was authorized. Another provision stated that FERC must work with fish and wildlife agencies to mitigate the environmental impacts of existing dams.
Promotion.
Research and development programs and financial incentives are used to promote hydropower. The financial incentives that exist are: Renewable Energy Production Tax Credits (PTC), loan guarantees, Clean Renewable Energy Bond (CREB), Qualified Energy Conservation Bonds (QECB)
The Department of Energy's Hydropower Program.
The U.S. DOE's Hydropower Program is a part of its Office of Wind and Hydropower Technologies. The Hydropower Program's mission is “to conduct research and development that will improve the technical, societal, and environmental benefits of hydropower and provide cost-competitive technologies that enable the development of new and incremental hydropower capacity.” The research is performed in conjunction with other federal agencies and groups involved with the industry. Progress and results are evaluated through the actions of a technical committee of experts. The three National Laboratories involved with the program include Idaho National Laboratory, Oak Ridge National Laboratory, and Pacific Northwest National Laboratory.
Tax credit from efficiency improvements or capacity additions.
Hydroelectric facilities placed into service after August 8, 2005 and before January 1, 2014 may apply for a tax credit for incremental production gains from efficiency improvements or capacity additions. This tax credit was created by Section 1301 of the U.S. Energy Policy Act of 2005, which amends Section 45 of the Internal Revenue Code of 1986. As outlined by EPAct 2005, the "incremental hydropower production for any taxable year shall be equal to the percentage of average annual hydropower production at the facility attributable to the efficiency improvements or additions of capacity" and shall be "determined by using the same water flow information used to determine an historic average annual hydropower production baseline." This percentage and baseline has to be certified by the Federal Energy Regulatory Commission.
The determination of incremental hydropower production shall not be based on any operational changes at a facility not directly associated with the efficiency improvements or additions of capacity. In Section 1301, “efficiency improvements” and “additions of capacity” are not defined. (It merely excludes “operational changes…not directly associated with the efficiency improvements or additions of capacity”). Therefore, FERC interprets “efficiency improvements” as upgrades to generators or turbines that result in increased power generation. They interpret “additions of capacity” to be “any increase in generating capacity other than an addition resulting from an efficiency improvement or an addition resulting from an operational change.
To acquire certification from FERC, a request must be submitted that includes (taken directly from the outline in):
A. Historic Average Annual Hydropower Production (baseline):
B. Percentage of Average Annual Hydropower Production Attributable to Efficiency Improvements or Additions of Capacity
Loan guarantees.
The Energy Policy Act and the Recovery Act have created loan programs to support hydropower production and development of other clean energy. In both acts, the loan repayment is required over a period no greater than 30 years or 90% of the projected useful life of the asset being financed.
The innovative Loan Guarantee Program was created by the EPAct Title XVII to “support the deployment of the deployment of innovative, clean energy technologies that reduce, avoid or sequester carbon dioxide & other air emissions.” The Federal government has authorized up to $42.5 billion in loan guarantees.
The Recovery Act allocated $6 billion to offset loan guarantee charges that are paid to the DOE as a risk premium for the guarantee. There is a September 30, 2011 commencement deadline for construction of temporary additions and projects under the loan program in the Recovery Act.
Clean Renewable Energy Bonds.
Clean Renewable Energy Bonds (CREB) are federal loans authorized by the Energy Policy Act of 2005 for the purpose of financing renewable energy projects [DSIRE]. CREBs are not limited to hydropower, and are qualified for use with all technologies listed in the federal renewable energy production tax credit. These interest free federal loans can be issued by electric cooperatives, government entities, and certain lenders. The bondholder receives tax credits as a way of compensating for no interest payments. The current maximum allowable issuance of Clean Renewable Energy Bonds is $2.4 billion.
Qualified Energy Conservation Bonds.
Qualified Energy Conservation Bonds (QECB) are applied to a broader spectrum of projects than Clean Renewable Energy Bonds. These loans are available for building efficiency, renewable energy production, research and development applications, mass transit and public energy efficiency campaigns in addition to the projects that are eligible for CREBs. Unlike CREBs however, QECBs are not subject to U.S. Department of Treasury applications and approvals. The bonds are issued to states based on that state's percentage of the U.S. population. The state then distributes the QECBs among its municipalities and counties with populations of 100,000 or greater.
RPS overview for various states.
Renewable Portfolio Standards are state policies that establish a minimum required percentage of renewable power for electricity generation. There are currently 24 states with RPS policies in place, all of which include hydroelectric power as an eligible technology. The established percentages are targets for full requirement set for a certain year, ranging from 2013 (Vermont and New York) to 2030 (California). Out of the states with RPS policies, Pennsylvania has the lowest required percentage of renewable generation (8%) and Maine has the highest (40%).
National Hydropower Association policy priorities.
The National Hydropower Association (NHA) currently has five policy priorities on their agenda. The first is a more efficient regulatory process. They say that an expediting 2-year licensing process for minimal impact projects would allow hydro to be on an “equal footing” with other renewable technologies. The second is a tax credit parity. Hydropower currently receives half of the rate per kWh under the Production Tax Credit, and the NHA thinks that it should be increased such that it is equal with other renewable technologies. The third priority calls for incentivizing renewable electricity production and manufacturing (manufacturing tax credits, Clean and Renewable Energy Bonds, Production and Investment Tax Credits should be extended). They also want a federal clean and renewable energy standard which promotes development. The last priority calls for continued investment in research and development for both conventional and non-conventional hydropower projects.
Failed legislation.
Energy and Water Integration Act of 2009.
The Energy and Water Integration Act of 2009, sponsored by Senator Jeff Bingaman (D-NM), sought to make the Secretary of Energy cooperate with the National Academy of Sciences to conduct an analysis of how energy development affected water resources in the United States. The bill was introduced too late in the 111th Congressional session and thus never reached the floor.
The Hydropower Improvement Act of 2010.
The Hydropower Improvement Act of 2010, sponsored by Senators Maria Cantwell and Patty Murray (both D-WA), sought to increase generating capacity from hydropower by 75,000 MW and also create jobs in the energy sector. It gave FERC permission to expedite the licensing and authorization process for new projects and also to conduct research into increasing hydropower capacity. The bill called for the establishment of a grants program for increased hydropower production and a plan for research, development, and demonstration to achieve the same end.
The legislation was introduced too late during the 111th Congressional session and thus never reached the floor. It has since been resurrected as The Hydropower Improvement Act of 2011, this time sponsored by Senator Lisa Murkowski (R-AK).
The Hydropower Renewable Energy Development Act.
The Hydropower Renewable Energy Development Act, sponsored by Senator Lisa Murkowski (R-AK), sought to catalyze investment in hydropower by broadening its definition so more types of it qualify for Production Tax Credits and other types of government funding. The bill also tried to redefine hydropower as a renewable energy source in the eyes of the federal government. This would have made hydropower projects eligible for more tax credits that are currently only available for traditional renewable energy sources like solar and wind. The Hydropower Renewable Energy Development Act was introduced too late during the 111th Congressional session and thus never reached the floor.
The Hydropower Improvement Act of 2011.
The Hydropower Improvement Act of 2011 is a resurrection of its 2010 counterpart never reached the floor because the 111th Congressional session terminated. According to its sponsor Senator Lisa Murkowski (R-AK), the bill seeks to "substantially increase the capacity and generation of renewable hydropower resources in the US." It could not have been introduced at a better time considering the waning interest in nuclear power brought about by the Japanese tsunami and subsequent nuclear reactor meltdowns.
Bonneville Unit Clean Hydropower Facilitation Act.
The Bonneville Unit Clean Hydropower Act, sponsored by Senator Orrin Hatch (R-UT), seeks to promote hydropower development in the Diamond Fork System of the Central Utah Project. As of March 7, 2011, this bill has been introduced to Congress, read twice, and referred to the Committee on Energy and Natural Resources.
Small-Scale Hydropower Enhancement Act of 2011.
The Small-Scale Hydropower Enhancement Act of 2011, sponsored by Representative Adrian Smith (R-NE), seeks to promote the installation of small-scale hydropower projects (<1.5 MW) by exempting them from some of the stricter Federal Power Act licensing terms. These exemptions make the construction process faster and much less expensive. Currently, this bill has been referred to the Subcommittee on Energy and Power.
Current proposed legislation.
The Hydropower Regulatory Efficiency Act of 2013.
The Hydropower Regulatory Efficiency Act of 2013 (H.R. 267) is a bill that was introduced into the United States House of Representatives of the 113th United States Congress on January 15, 2013. It passed the House on February 13, 2013 by a vote of 422-0. The act was intended to change some of the regulations in the United States surrounding hydropower by making it easier for smaller hydropower stations to be created. According to the bill's proponents, current regulations are unwieldy and represent a significant hurdle to creating more hydropower plants. H.R. 267 would alter those regulations to make it easier for smaller plants to get approval quickly. The legislation also requires the Federal Energy Regulatory Commission (FERC) to study how to further improve the regulatory process. H.R. 267 would amend the Public Utility Regulatory Policies Act of 1978 (PURPA) and the Federal Power Act. Currently, hydropower projects the produce 5,000 kilowatts or less of power can avoid having to get certain licenses. H.R. 267 would raise that amount to 10,000 kilowatts, facilitating the speed at which smaller hydropower projects could be built. The existing rules mean that it takes about five years for hydropower projects to get approval, according to hydropower industry sources.
See also.
Hydraulic power network


FS Class E.472


Solar power in Chile

In 2018 Chile produced about 7% of its electricity from solar power. As of year end, it had 2137 MW of solar PV capacity. In July 2020 installed solar capacity had risen to 3104 MW, with another 2801 MW under construction.
Northern Chile has the highest solar incidence in the world. In October 2015 Chile's Ministry of Energy announced its "Roadmap to 2050: A Sustainable and Inclusive Strategy", which plans for 19% of the country's electricity to be from solar energy, 23% wind power, and 29% hydroelectric power.
Solar thermal power in Chile.
In 2013 the Atacama 1 solar complex was proposed as a 110 MW solar thermal electric plant (the first in Latin America) and a 100 MW photovoltaic plant. The solar thermal plant will include 17.5 hours of thermal storage. These technologies complement each other to supply clean and stable energy 24 hours a day. The complex is located in the commune of María Elena, Segunda Región. Construction of the solar thermal electric plant commenced in 2014 and the plant was scheduled to begin operating in the second quarter of 2017, but got delayed significantly. Construction of the photovoltaic plant commenced in January 2015 and the plant began operating in June 2016 with 160 MW of panels, the largest solar plant in Chile at the time. By the end of 2020 the project was fully erected under the name Cerro Dominador Solar Thermal Plant and is expected to fully operate in 2021.
Because of its good solar resource several international companies have bid record low prices for solar thermal power plants in Chile, including the Copiapó Solar Project bid at $63/MWh by SolarReserve in 2017. If realized this would have been the lowest ever price for a CSP project in the world. Several CSP projects are under development in Chile, but in the absence of technology specific support policies Cerro Dominador is the only one under construction, yet.
Significant photovoltaics projects.
In June 2014, the 100-megawatt (MW) Amanecer Solar CAP, a photovoltaic power plant located near Copiapó in the Atacama Desert was inaugurated. It was developed by the company with the same name, Amanecer Solar CAP, and was the largest in Latin America at the time. It is capable of generating 270 gigawatt-hours (GWh) of electricity per year.
The 70 MW photovoltaic Salvador Solar Park went online in November 2014, followed by an official inauguration ceremony on 23 January 2015. It was expected to produce 200 GWh of electricity per year. The plant is located approximately 5 kilometres south of El Salvador, in the Atacama region. It is one of the first in the world to supply competitively priced solar energy to the open market without government subsidy.
The 60 MW photovoltaic Lalackama I plant went online in 2014 and is expected to produce 160 GWh of electricity per year. The nearby 18 MW Lalackama II plant went online in May 2015 and is capable of generating approximately 50 GWh per year. Both plants feature photovoltaic inverters designed and manufactured by Elettronica Santerno, an Italian company.
The 141 MW photovoltaic Luz Del Norte (Light of the North) plant, located 58 kilometres northeast of the city of Copiapó in the Atacama region, began construction in October 2014 and is scheduled for completion in December 2015. It uses more than 1.7 million cadmium telluride modules. The first two blocks of this project (approximately half of the project's total capacity) was connected to Chile's central power grid in October 2015. The plant supplies ancillary grid services.
The 79 MW Pampa Norte PV solar plant began operating in April 2016 at a site 32 kilometres southwest of Taltal in Chile's Antofagasta Region. It uses approximately 258,000 polycrystalline silicon photovoltaic modules and is capable of generating more than 200 GWh per year. The plant was developed by Enel Green Power and features photovoltaic inverters designed and manufactured by Elettronica Santerno.
The 97 MW Carrera Pinto photovoltaic plant began is located 60 kilometres from the city of Copiapó in the Atacama Region. The first 20 MW of the plant was connected to the grid in early January 2016, with the remaining 77 MW connected in August 2016. The plant is capable of generating over 260 GWh per year.
The 246 MW El Romero single-axis tracking solar photovoltaic plant began operating in November 2016 at Vallenar in the Atacama region, with a 493 GWh annual average output. It was the largest solar farm in Latin America when it opened. It uses 776,000 polycrystalline silicon photovoltaic modules. The solar irradiance has been measured at 853 W/m2.
In 2016, SolarPack won an electricity auction by bidding $29.1/MWh; a record low price. In March 2020 PV Magazine reported that Solarpack had begun providing power on 2 March 2020, to the Chilean grid from its 123 MW Granja project, 10 months ahead of the contracted date of 1 January 2021. With that, Solarpack raised its total operating capacity in Chile at the time to 181 MW.
In October 2017, within the framework of the Renewable Energy Solutions Program, the Deutsche Energie Agentur GmbH (dena RES programme) at the Tierra Atacama Hotel, a photovoltaic system with 155.88 kWp in combination with a battery storage system was put into operation. The off-grid solar system was built by the German EPC (Engineering, procurement, and construction) service provider Kraftwerk Renewable Power Solutions. Qinous's battery system with 335 kWh lithium-ion battery storage and 180 kW inverter power enables the diesel generators to be switched off completely during the day because the battery system can take over the power supply instead of the diesel generators. The annual diesel requirement can thus be reduced by up to 60%. As early as 2013, the hotel was named the most sustainable tourism company in Chile following the commissioning of the first small PV diesel hybrid plant.


Skagerrak (power transmission system)

Skagerrak is the name of a 1,700 MW high-voltage direct current (HVDC) transmission facility between Tjele (Denmark) and Kristiansand (Norway). It is owned and operated by Statnett in Norway, and Energinet in Denmark. The lines connect the hydroelectric-based Norwegian grid and the wind and thermal power-based Danish grid. In operation it enables more renewable energy in the energy mix, and more efficient use of electricity.
Technical features.
The Skagerrak 1–3 scheme consists of a overhead line and a underwater cable. It has a capacity of 1,050 megawatts (MW). Both land parts in Denmark and in Norway uses overhead lines from the cable landing point to the converter stations. The overhead lines in Denmark are set to be renovated in 2016 for increased lifespan. The towers were originally constructed for four poles, but were rebuilt for three conductors (three poles) when Skagerrak 3 was established. Near Aggersund HVDC Skagerrak crossed Aggersund strait overhead on towers with a span, but were later converted to underground cables. The pylons of this span were the tallest electricity pylons of an HVDC line in Europe.
For such a long submarine cable, an AC transmission scheme would not be feasible since too much of the cable's capacity would be consumed by the capacitance of the cable itself, and the power systems in Norway and Jutland are not synchronous.
The transmission has a loss rate of 4%.
The waste heat of the transformers is enough to supply district heating economically for 1,000 homes in nearby towns, but taxes prevent that project. The adjacent Apple Datacenter (supplied in part by the Skagerrak cables via Tjele) was expected to work around the tax issue when supplying district heat to Viborg.
Skagerrak 1 and 2.
Skagerrak went in service in 1977 as a bipolar HVDC scheme. This facility was built with thyristor valves. When installed this underwater cable was the world's longest and deepest underwater HVDC power cable. The cable, manufactured by Alcatel, is laid in a maximum water depth of .
Both cables have a capacity of 250 MW at 250 kV.
Skagerrak 3.
In 1993 the scheme was extended by HVDC Skagerrak 3. Skagerrak 3 is a monopolar line for a voltage of 350 kV with a capacity of 440 MW at 350 kV. In installing Skagerrak 3, the old poles Skagerrak 1 and Skagerrak 2 were converted to monopolar HVDC schemes, which run with opposite polarity to Skagerrak 3.
Skagerrak 4.
In November 2009, Statnett and Energinet.dk signed the agreement to construct Skagerrak 4. The capacity of Skagerrak 4 is approximately 700 MW. It had been in a test phase since 1 October 2014 and became operational at the end of 2014, when strong winds created negative prices despite the new connection. It was officially inaugurated by Frederik, Crown Prince of Denmark and Haakon, Crown Prince of Norway on 12 March 2015. As for the existing Skagerrak 1-3, the grid connection points are Kristiansand and Tjele. Differently from Skagerrak 1–3, for Skagerrak 4 a cable solution is chosen for the complete route length. The 300 million DKK Prysmian land cable on the Danish side is approximately , while the subsea cable and the Norwegian land cable is to be made by Nexans for 638 million DKK. Converter stations were built by ABB, as for Skagerrak 1–3. The combined budget is 2.8-3.2 billion DKK.
The technology used was VSC, capable of black start. Although thyristor-based converters have a loss of only 0.7%, the IGBTs of VSC get close with a loss of 0.8 to 1%. Skagerrak 1 and 2 previously used Skagerrak 3 as a return cable, but 1 and 2 were again coupled so that Skagerrak 4 can use number 3 for returns. The cable also supplies 110 MW of reserve power. Some of the 24 fiber pairs may be rented for business by telecommunications companies.


Solar power in Thailand

Solar power in Thailand is targeted to reach 6,000 MW by 2036.
In 2013 installed photovoltaic capacity nearly doubled and reached 704 MW by the end of the year.
At the end of 2015, with a total capacity of 2,500-2,800 MW, Thailand has more solar power capacity than all the rest of Southeast Asia combined.
Thailand has great solar potential, especially the southern and northern parts of the northeastern region of Udon Thani Province and certain areas in the central region. Around 14.3% of the country has a daily solar exposure of around 19–20 MJ/m2/day, while another 50% of the country gains around 18–19 MJ/m2/day. In terms of solar potential, Thailand lags behind the US, but is ahead of Japan.
The 84 MW Lopburi Solar Farm was completed in May 2013. German solar energy company Conergy signed a contract with Thailand's Siam Solar Energy to construct three solar plants of 10.5 MW each in addition to existing two solar plants that have been under construction since autumn 2012.
Power purchase scheme.
In January 2015, Thailand's Energy Regulatory Commission (ERC) announced a new regulation for the purchase of electricity from ground-mounted solar projects, replacing the "adder" scheme with the "feed-in-tariff" (FiT) scheme. The regulation aims to revive the investment in renewable energy projects in Thailand after a quiet period in the renewable energy sector in 2014. There are over one hundred projects, with a total capacity of 1,000 MW, whose applications have not yet been accepted under the adder scheme and therefore are eligible for the feed-in-tariff scheme.


High-voltage direct current

A high-voltage, direct current (HVDC) electric power transmission system (also called a power superhighway or an electrical superhighway) uses direct current (DC) for the bulk transmission of electrical power, in contrast with the more common alternating current (AC) systems.
Most HVDC links use voltages between 100 kV and 800 kV. A 1,100 kV link in China was completed in 2019 over a distance of 3,300 km with a power of 12 GW. With this dimension, intercontinental connections become possible which could help to deal with the fluctuations of wind power and photovoltaics.
HVDC allows power transmission between AC transmission systems that are not synchronized. Since the power flow through an HVDC link can be controlled independently of the phase angle between source and load, it can stabilize a network against disturbances due to rapid changes in power. HVDC also allows transfer of power between grid systems running at different frequencies, such as 50 Hz and 60 Hz. This improves the stability and economy of each grid, by allowing exchange of power between incompatible networks.
The modern form of HVDC transmission uses technology developed extensively in the 1930s in Sweden (ASEA) and in Germany. Early commercial installations included one in the Soviet Union in 1951 between Moscow and Kashira, and a 100 kV, 20 MW system between Gotland and mainland Sweden in 1954. Before the Chinese project of 2019, the longest HVDC link in the world was the Rio Madeira link in Brazil, which consists of two bipoles of ±600 kV, 3150 MW each, connecting Porto Velho in the state of Rondônia to the São Paulo area with a length of more than .
High voltage transmission.
High voltage is used for electric power transmission to reduce the energy lost in the resistance of the wires. For a given quantity of power transmitted, doubling the voltage will deliver the same power at only half the current. Since the power lost as heat in the wires is directly proportional to the square of the current, doubling the voltage reduces the line losses by a factor of 4. While power lost in transmission can also be reduced by increasing the conductor size, larger conductors are heavier and more expensive.
High voltage cannot readily be used for lighting or motors, so transmission-level voltages must be reduced for end-use equipment. Transformers are used to change the voltage levels in alternating current (AC) transmission circuits. Transformers made voltage changes practical, and AC generators were more efficient than those using DC. These advantages led to early low voltage DC transmission systems being supplanted by AC systems around the turn of the 20th century.
Practical conversion of power between AC and DC became possible with the development of power electronics devices such as mercury-arc valves and, starting in the 1970s, semiconductor devices as thyristors, integrated gate-commutated thyristors (IGCTs), MOS-controlled thyristors (MCTs) and insulated-gate bipolar transistors (IGBT).
History.
Electromechanical (Thury) systems.
The first long-distance transmission of electric power was demonstrated using direct current in 1882 at Miesbach-Munich Power Transmission, but only 1.5 kW was transmitted. An early method of HVDC transmission was developed by the Swiss engineer René Thury and his method was put into practice by 1889 in Italy by the "Acquedotto De Ferrari-Galliera" company. This system used series-connected motor-generator sets to increase the voltage. Each set was insulated from electrical ground and driven by insulated shafts from a . The transmission line was operated in a 'constant current' mode, with up to 5,000 volts across each machine, some machines having double commutators to reduce the voltage on each commutator. This system transmitted 630 kW at 14 kV DC over a distance of 120 km. The Moutiers–Lyon system transmitted 8,600 kW of hydroelectric power a distance of 200 km, including 10 km of underground cable. This system used eight series-connected generators with dual commutators for a total voltage of 150 kV between the positive and negative poles, and operated from c.1906 until 1936. Fifteen Thury systems were in operation by 1913. Other Thury systems operating at up to 100 kV DC worked into the 1930s, but the rotating machinery required high maintenance and had high energy loss. Various other electromechanical devices were tested during the first half of the 20th century with little commercial success.
One technique attempted for conversion of direct current from a high transmission voltage to lower utilization voltage was to charge series-connected batteries, then reconnect the batteries in parallel to serve distribution loads. While at least two commercial installations were tried around the turn of the 20th century, the technique was not generally useful owing to the limited capacity of batteries, difficulties in switching between series and parallel connections, and the inherent energy inefficiency of a battery charge/discharge cycle. (A modern battery storage power station includes transformers and inverters to change energy from alternating current to direct current forms at appropriate voltages.)
Mercury arc valves.
First proposed in 1914, the grid controlled mercury-arc valve became available for power transmission during the period 1920 to 1940. Starting in 1932, General Electric tested mercury-vapor valves and a 12 kV DC transmission line, which also served to convert 40 Hz generation to serve 60 Hz loads, at Mechanicville, New York. In 1941, a 60 MW, ±200 kV, 115 km buried cable link was designed for the city of Berlin using mercury arc valves (Elbe-Project), but owing to the collapse of the German government in 1945 the project was never completed. The nominal justification for the project was that, during wartime, a buried cable would be less conspicuous as a bombing target. The equipment was moved to the Soviet Union and was put into service there as the Moscow–Kashira HVDC system. The Moscow–Kashira system and the 1954 connection by Uno Lamm's group at ASEA between the mainland of Sweden and the island of Gotland marked the beginning of the modern era of HVDC transmission.
Mercury arc valves require an external circuit to force the current to zero and thus turn off the valve. In HVDC applications, the AC power system itself provides the means of "commutating" the current to another valve in the converter. Consequently, converters built with mercury arc valves are known as line-commutated converters (LCC). LCCs require rotating synchronous machines in the AC systems to which they are connected, making power transmission into a passive load impossible.
Mercury arc valves were common in systems designed up to 1972, the last mercury arc HVDC system (the Nelson River Bipole 1 system in Manitoba, Canada) having been put into service in stages between 1972 and 1977. Since then, all mercury arc systems have been either shut down or converted to use solid state devices. The last HVDC system to use mercury arc valves was the Inter-Island HVDC link between the North and South Islands of New Zealand, which used them on one of its two poles. The mercury arc valves were decommissioned on 1 August 2012, ahead of commissioning of replacement thyristor converters.
Thyristor valves.
Since 1977, new HVDC systems have used only solid-state devices, in most cases thyristors. Like mercury arc valves, thyristors require connection to an external AC circuit in HVDC applications to turn them on and off. HVDC using thyristors is also known as Line-Commutated Converter (LCC) HVDC.
Development of thyristor valves for HVDC began in the late 1960s. The first complete HVDC scheme based on thyristor was the Eel River scheme in Canada, which was built by General Electric and went into service in 1972.
On March 15, 1979, a 1920 MW thyristor based direct current connection between Cabora Bassa and Johannesburg (1,410 km) was energized. The conversion equipment was built in 1974 by Allgemeine Elektricitäts-Gesellschaft AG (AEG), and Brown, Boveri & Cie (BBC) and Siemens were partners in the project. Service interruptions of several years were a result of a civil war in Mozambique. The transmission voltage of ±533 kV was the highest in the world at the time.
Capacitor-commutated converters (CCC).
Line-commutated converters have some limitations in their use for HVDC systems. This results from requiring the AC circuit to turn off the thyristor current and the need for a short period of 'reverse' voltage to effect the turn-off (turn-off time). An attempt to address these limitations is the "capacitor-commutated converter" ("CCC") which has been used in a small number of HVDC systems. The CCC differs from a conventional HVDC system in that it has series capacitors inserted into the AC line connections, either on the primary or secondary side of the converter transformer. The series capacitors partially offset the "commutating inductance" of the converter and help to reduce fault currents. This also allows a smaller "extinction angle" to be used with a converter/inverter, reducing the need for reactive power support.
However, CCC has remained only a niche application because of the advent of voltage-source converters (VSC) which completely eliminate the need for an extinction (turn-off) time.
Voltage-source converters (VSC).
Widely used in motor drives since the 1980s, voltage-source converters started to appear in HVDC in 1997 with the experimental Hellsjön–Grängesberg project in Sweden. By the end of 2011, this technology had captured a significant proportion of the HVDC market.
The development of higher rated insulated-gate bipolar transistors (IGBTs), gate turn-off thyristors (GTOs) and integrated gate-commutated thyristors (IGCTs), has made smaller HVDC systems economical. The manufacturer ABB Group calls this concept "HVDC Light", while Siemens calls a similar concept "HVDC PLUS" ("Power Link Universal System") and Alstom call their product based upon this technology "HVDC MaxSine". They have extended the use of HVDC down to blocks as small as a few tens of megawatts and overhead lines as short as a few dozen kilometers. There are several different variants of VSC technology: most installations built until 2012 use pulse-width modulation in a circuit that is effectively an ultrahigh-voltage motor drive. Current installations, including HVDC PLUS and HVDC MaxSine, are based on variants of a converter called a "Modular Multilevel Converter" (MMC).
Multilevel converters have the advantage that they allow harmonic filtering equipment to be reduced or eliminated altogether. By way of comparison, AC harmonic filters of typical line-commutated converter stations cover nearly half of the converter station area.
With time, voltage-source converter systems will probably replace all installed simple thyristor-based systems, including the highest DC power transmission applications.
Comparison with AC.
Advantages.
A long-distance, point-to-point HVDC transmission scheme generally has lower overall investment cost and lower losses than an equivalent AC transmission scheme. HVDC conversion equipment at the terminal stations is costly, but the total DC transmission-line costs over long distances are lower than for an AC line of the same distance. HVDC requires less conductor per unit distance than an AC line, as there is no need to support three phases and there is no skin effect.
Depending on voltage level and construction details, HVDC transmission losses are quoted at 3.5% per 1,000 km, about 50% less than AC (6.5%) lines at the same voltage. This is because direct current transfers only active power and thus causes lower losses than alternating current, which transfers both active and reactive power.
HVDC transmission may also be selected for other technical benefits. HVDC can transfer power between separate AC networks. HVDC powerflow between separate AC systems can be automatically controlled to support either network during transient conditions, but without the risk that a major power-system collapse in one network will lead to a collapse in the second. HVDC improves on system controllability, with at least one HVDC link embedded in an AC grid—in the deregulated environment, the controllability feature is particularly useful where control of energy trading is needed.
The combined economic and technical benefits of HVDC transmission can make it a suitable choice for connecting electricity sources that are located far away from the main users.
Specific applications where HVDC transmission technology provides benefits include:
Cable systems.
Long undersea or underground high-voltage cables have a high electrical capacitance compared with overhead transmission lines, since the live conductors within the cable are surrounded by a relatively thin layer of insulation (the dielectric), and a metal sheath. The geometry is that of a long coaxial capacitor. The total capacitance increases with the length of the cable. This capacitance is in a parallel circuit with the load. Where alternating current is used for cable transmission, additional current must flow in the cable to charge this cable capacitance. This extra current flow causes added energy loss via dissipation of heat in the conductors of the cable, raising its temperature. Additional energy losses also occur as a result of dielectric losses in the cable insulation.
However, if direct current is used, the cable capacitance is charged only when the cable is first energized or if the voltage level changes; there is no additional current required. For a sufficiently long AC cable, the entire current-carrying ability of the conductor would be needed to supply the charging current alone. This cable capacitance issue limits the length and power-carrying ability of AC power cables. DC powered cables are limited only by their temperature rise and Ohm's law. Although some leakage current flows "through" the dielectric insulator, this is small compared to the cable's rated current.
Overhead line systems.
The capacitive effect of long underground or undersea cables in AC transmission applications also applies to AC overhead lines, although to a much lesser extent. Nevertheless, for a long AC overhead transmission line, the current flowing just to charge the line capacitance can be significant, and this reduces the capability of the line to carry useful current to the load at the remote end. Another factor that reduces the useful current-carrying ability of AC lines is the skin effect, which causes a nonuniform distribution of current over the cross-sectional area of the conductor. Transmission line conductors operating with direct current suffer from neither constraint. Therefore, for the same conductor losses (or heating effect), a given conductor can carry more power to the load when operating with HVDC than AC.
Finally, depending upon the environmental conditions and the performance of overhead line insulation operating with HVDC, it may be possible for a given transmission line to operate with a constant HVDC voltage that is approximately the same as the peak AC voltage for which it is designed and insulated. The power delivered in an AC system is defined by the root mean square (RMS) of an AC voltage, but RMS is only about 71% of the peak voltage. Therefore, if the HVDC line can operate continuously with an HVDC voltage that is the same as the peak voltage of the AC equivalent line, then for a given current (where HVDC current is the same as the RMS current in the AC line), the power transmission capability when operating with HVDC is approximately 40% higher than the capability when operating with AC.
Asynchronous connections.
Because HVDC allows power transmission between unsynchronized AC distribution systems, it can help increase system stability, by preventing cascading failures from propagating from one part of a wider power transmission grid to another. Changes in load that would cause portions of an AC network to become unsynchronized and to separate, would not similarly affect a DC link, and the power flow through the DC link would tend to stabilize the AC network. The magnitude and direction of power flow through a DC link can be directly controlled, and changed as needed to support the AC networks at either end of the DC link. This has caused many power system operators to contemplate wider use of HVDC technology for its stability benefits alone.
Disadvantages.
The disadvantages of HVDC are in conversion, switching, control, availability, and maintenance.
HVDC is less reliable and has lower availability than alternating current (AC) systems, mainly due to the extra conversion equipment. Single-pole systems have availability of about 98.5%, with about a third of the downtime unscheduled due to faults. Fault-tolerant bipole systems provide high availability for 50% of the link capacity, but availability of the full capacity is about 97% to 98%.
The required converter stations are expensive and have limited overload capacity. At smaller transmission distances, the losses in the converter stations may be bigger than in an AC transmission line for the same distance. The cost of the converters may not be offset by reductions in line construction cost and lower line loss.
Operating an HVDC scheme requires many spare parts to be kept, often exclusively for one system, as HVDC systems are less standardized than AC systems and technology changes more quickly.
In contrast to AC systems, realizing multi-terminal systems is complex (especially with line commutated converters), as is expanding existing schemes to multi-terminal systems. Controlling power flow in a multi-terminal DC system requires good communication between all the terminals; power flow must be actively regulated by the converter control system instead of relying on the inherent impedance and phase angle properties of an AC transmission line. Multi-terminal systems are rare. As of 2012 only two are in service: the Hydro Québec – New England transmission between Radisson, Sandy Pond, and Nicolet and the Sardinia–mainland Italy link which was modified in 1989 to also provide power to the island of Corsica.
High-voltage DC circuit breaker.
HVDC circuit breakers are difficult to build because of arcing: under AC the voltage inverts, and in doing so crosses zero volts, dozens of times a second. An AC arc will "self-extinguish" at one of these zero-crossing points, because there cannot be an arc where there is no potential difference. DC will never cross zero volts and never self-extinguish, so arc distance and duration is far greater with DC than the same voltage AC. This means some mechanism must be included in the circuit breaker to force current to zero and extinguish the arc, otherwise arcing and contact wear would be too great to allow reliable switching.
In November 2012, ABB announced development of the world's first ultrafast HVDC circuit breaker. Mechanical circuit breakers are too slow for use in HVDC grids, although they have been used for years in other applications. Conversely, semiconductor breakers are fast enough but have a high resistance when conducting, wasting energy and generating heat in normal operation. The ABB breaker combines semiconductor and mechanical breakers to produce a "hybrid breaker" with both a fast break time and a low resistance in normal operation.
The hybrid breaker is based on a conventional semiconductor breaker (the "main breaker"), with the characteristic rapid break time, full voltage and current tolerance but also the characteristic resistance when conducting. This main breaker is placed in parallel with a "load commutator": a small semiconductor breaker (the "load commutation switch") in series with a fast mechanical switch (the "ultra fast disconnector"). While neither element of the load commutator can break the full voltage of the line, the load commutator can safely carry the normal operating current with lower resistive losses than the main breaker. Finally, there is a slow mechanical switch to fully disconnect the line. It can't be opened when the line is energised, but will fully disconnect the line with no current leakage and no heat generation. In normal operation, all switches are closed (on), and most current flows through the low-resistance load commutator instead of the higher resistance main breaker.
When disconnection is required, the first step is disconnecting the load commutator: the low-voltage semiconductor breaker opens, and this diverts almost all of the current through the main breaker. The main breaker is still conducting, so the load commutator does not see the whole voltage of the line, only the voltage drop caused by the high-voltage main breaker not being a perfect conductor. Because the load commutation switch is open, the ultra-fast disconnector is not exposed to high current, and can open without being damaged by arcing. The mechanical switch being opened, the load commutator is now fully disconnected: no heat is being generated in the semiconductor switch, and even the full line voltage cannot pass through it. All current is now passing through the main breaker.
Now the main breaker opens, breaking the current. This drops the current to near-zero, but increases the voltage across the main breaker and load commutator to nearly the entire line voltage. Had the load commutation switch not been mechanically disconnected earlier, this voltage would damage it. Because the main breaker is a semiconductor breaker, it cuts off almost all the current, but not all of it, so to perform the final isolation, a slow mechanical switch disconnects the line. Because almost all the current is being blocked by the main breaker, it can be opened without damage.
Costs.
Generally, providers of HVDC systems, such as Alstom, Siemens and ABB, do not specify cost details of particular projects. It may be considered a commercial matter between the provider and the client.
Costs vary widely depending on the specifics of the project (such as power rating, circuit length, overhead vs. cabled route, land costs, and AC network improvements required at either terminal). A detailed comparison of DC vs. AC transmission costs may be required in situations where there is no clear technical advantage to DC, and economical reasoning alone drives the selection.
However, some practitioners have provided some information:
An April 2010 announcement for a 2,000 MW, 64 km line between Spain and France is estimated at €700 million. This includes the cost of a tunnel through the Pyrenees.
Conversion process.
Converter.
At the heart of an HVDC converter station, the equipment which performs the conversion between AC and DC is referred to as the "converter". Almost all HVDC converters are inherently capable of converting from AC to DC ("rectification") and from DC to AC ("inversion"), although in many HVDC systems, the system as a whole is optimized for power flow in only one direction. Irrespective of how the converter itself is designed, the station that is operating (at a given time) with power flow from AC to DC is referred to as the "rectifier" and the station that is operating with power flow from DC to AC is referred to as the "inverter".
Early HVDC systems used electromechanical conversion (the Thury system) but all HVDC systems built since the 1940s have used electronic (static) converters. Electronic converters for HVDC are divided into two main categories:
Line-commutated converters.
Most of the HVDC systems in operation today are based on line-commutated converters.
The basic LCC configuration uses a three-phase bridge rectifier or "six-pulse bridge", containing six electronic switches, each connecting one of the three phases to one of the two DC rails. A complete switching element is usually referred to as a "valve", irrespective of its construction. However, with a phase change only every 60°, considerable harmonic distortion is produced at both the DC and AC terminals when this arrangement is used.
An enhancement of this arrangement uses 12 valves in a "twelve-pulse bridge". The AC is split into two separate three phase supplies before transformation. One of the sets of supplies is then configured to have a star (wye) secondary, the other a delta secondary, establishing a 30° phase difference between the two sets of three phases. With twelve valves connecting each of the two sets of three phases to the two DC rails, there is a phase change every 30°, and harmonics are considerably reduced. For this reason the twelve-pulse system has become standard on most line-commutated converter HVDC systems built since the 1970s.
With line commutated converters, the converter has only one degree of freedom – the "firing angle", which represents the time delay between the voltage across a valve becoming positive (at which point the valve would start to conduct if it were made from diodes) and the thyristors being turned on. The DC output voltage of the converter steadily becomes less positive as the firing angle is increased: firing angles of up to 90° correspond to rectification and result in positive DC voltages, while firing angles above 90° correspond to inversion and result in negative DC voltages. The practical upper limit for the firing angle is about 150–160° because above this, the valve would have insufficient "turnoff time".
Early LCC systems used mercury-arc valves, which were rugged but required high maintenance. Because of this, many mercury-arc HVDC systems were built with bypass switchgear across each six-pulse bridge so that the HVDC scheme could be operated in six-pulse mode for short periods of maintenance. The last mercury arc system was shut down in 2012.
The thyristor valve was first used in HVDC systems in 1972. The thyristor is a solid-state semiconductor device similar to the diode, but with an extra control terminal that is used to switch the device on at a particular instant during the AC cycle. Because the voltages in HVDC systems, up to 800 kV in some cases, far exceed the breakdown voltages of the thyristors used, HVDC thyristor valves are built using large numbers of thyristors in series. Additional passive components such as grading capacitors and resistors need to be connected in parallel with each thyristor in order to ensure that the voltage across the valve is evenly shared between the thyristors. The thyristor plus its grading circuits and other auxiliary equipment is known as a "thyristor level".
Each thyristor valve will typically contain tens or hundreds of thyristor levels, each operating at a different (high) potential with respect to earth. The command information to turn on the thyristors therefore cannot simply be sent using a wire connection – it needs to be isolated. The isolation method can be magnetic but is usually optical. Two optical methods are used: indirect and direct optical triggering. In the indirect optical triggering method, low-voltage control electronics send light pulses along optical fibres to the "high-side" control electronics, which derives its power from the voltage across each thyristor. The alternative direct optical triggering method dispenses with most of the high-side electronics, instead using light pulses from the control electronics to switch light-triggered thyristors (LTTs), although a small monitoring electronics unit may still be required for protection of the valve.
In a line-commutated converter, the DC current (usually) cannot change direction; it flows through a large inductance and can be considered almost constant. On the AC side, the converter behaves approximately as a current source, injecting both grid-frequency and harmonic currents into the AC network. For this reason, a line commutated converter for HVDC is also considered as a "current-source inverter".
Voltage-sourced converters.
Because thyristors can only be turned on (not off) by control action, the control system has only one degree of freedom – when to turn on the thyristor. This is an important limitation in some circumstances.
With some other types of semiconductor device such as the insulated-gate bipolar transistor (IGBT), both turn-on and turn-off can be controlled, giving a second degree of freedom. As a result, they can be used to make "self-commutated converters". In such converters, the polarity of DC voltage is usually fixed and the DC voltage, being smoothed by a large capacitance, can be considered constant. For this reason, an HVDC converter using IGBTs is usually referred to as a "voltage sourced converter". The additional controllability gives many advantages, notably the ability to switch the IGBTs on and off many times per cycle in order to improve the harmonic performance. Being self-commutated, the converter no longer relies on synchronous machines in the AC system for its operation. A voltage sourced converter can therefore feed power to an AC network consisting only of passive loads, something which is impossible with LCC HVDC.
HVDC systems based on voltage sourced converters normally use the six-pulse connection because the converter produces much less harmonic distortion than a comparable LCC and the twelve-pulse connection is unnecessary.
Most of the VSC HVDC systems built until 2012 were based on the "two level converter", which can be thought of as a six pulse bridge in which the thyristors have been replaced by IGBTs with inverse-parallel diodes, and the DC smoothing reactors have been replaced by DC smoothing capacitors. Such converters derive their name from the discrete, two voltage levels at the AC output of each phase that correspond to the electrical potentials of the positive and negative DC terminals. Pulse-width modulation (PWM) is usually used to improve the harmonic distortion of the converter.
Some HVDC systems have been built with "three level converters", but today most new VSC HVDC systems are being built with some form of "multilevel converter", most commonly the "modular multilevel converter" (MMC), in which each valve consists of a number of independent converter submodules, each containing its own storage capacitor. The IGBTs in each submodule either bypass the capacitor or connect it into the circuit, allowing the valve to synthesize a stepped voltage with very low levels of harmonic distortion.
Converter transformers.
At the AC side of each converter, a bank of transformers, often three physically separated single-phase transformers, isolate the station from the AC supply, to provide a local earth, and to ensure the correct eventual DC voltage. The output of these transformers is then connected to the converter.
Converter transformers for LCC HVDC schemes are quite specialized because of the high levels of harmonic currents which flow through them, and because the secondary winding insulation experiences a permanent DC voltage, which affects the design of the insulating structure (valve side requires more solid insulation) inside the tank. In LCC systems, the transformers also need to provide the 30° phase shift needed for harmonic cancellation.
Converter transformers for VSC HVDC systems are usually simpler and more conventional in design than those for LCC HVDC systems.
Reactive power.
A major drawback of HVDC systems using line-commutated converters is that the converters inherently consume reactive power. The AC current flowing into the converter from the AC system lags behind the AC voltage so that, irrespective of the direction of active power flow, the converter always absorbs reactive power, behaving in the same way as a shunt reactor. The reactive power absorbed is at least 0.5 Mvar/MW under ideal conditions and can be higher than this when the converter is operating at higher than usual firing or extinction angle, or reduced DC voltage.
Although at HVDC converter stations connected directly to power stations some of the reactive power may be provided by the generators themselves, in most cases the reactive power consumed by the converter must be provided by banks of shunt capacitors connected at the AC terminals of the converter. The shunt capacitors are usually connected directly to the grid voltage but in some cases may be connected to a lower voltage via a tertiary winding on the converter transformer.
Since the reactive power consumed depends on the active power being transmitted, the shunt capacitors usually need to be subdivided into a number of switchable banks (typically four per converter) in order to prevent a surplus of reactive power being generated at low transmitted power.
The shunt capacitors are almost always provided with tuning reactors and, where necessary, damping resistors so that they can perform a dual role as harmonic filters.
Voltage-source converters, on the other hand, can either produce or consume reactive power on demand, with the result that usually no separate shunt capacitors are needed (other than those required purely for filtering).
Harmonics and filtering.
All power electronic converters generate some degree of harmonic distortion on the AC and DC systems to which they are connected, and HVDC converters are no exception.
With the recently developed modular multilevel converter (MMC), levels of harmonic distortion may be practically negligible, but with line-commutated converters and simpler types of voltage-source converters, considerable harmonic distortion may be produced on both the AC and DC sides of the converter. As a result, harmonic filters are nearly always required at the AC terminals of such converters, and in HVDC transmission schemes using overhead lines, may also be required on the DC side.
Filters for line-commutated converters.
The basic building-block of a line-commutated HVDC converter is the "six-pulse bridge". This arrangement produces very high levels of harmonic distortion by acting as a current source injecting harmonic currents of order 6n±1 into the AC system and generating harmonic voltages of order 6n superimposed on the DC voltage.
It is very costly to provide harmonic filters capable of suppressing such harmonics, so a variant known as the "twelve-pulse bridge" (consisting of two six-pulse bridges in series with a 30° phase shift between them) is nearly always used. With the twelve-pulse arrangement, harmonics are still produced but only at orders 12n±1 on the AC side and 12n on the DC side. The task of suppressing such harmonics is still challenging, but manageable.
Line-commutated converters for HVDC are usually provided with combinations of harmonic filters designed to deal with the 11th and 13th harmonics on the AC side, and 12th harmonic on the DC side. Sometimes, high-pass filters may be provided to deal with 23rd, 25th, 35th, 37th... on the AC side and 24th, 36th... on the DC side. Sometimes, the AC filters may also need to provide damping at lower-order, "noncharacteristic" harmonics such as 3rd or 5th harmonics.
The task of designing AC harmonic filters for HVDC converter stations is complex and computationally intensive, since in addition to ensuring that the converter does not produce an unacceptable level of voltage distortion on the AC system, it must be ensured that the harmonic filters do not resonate with some component elsewhere in the AC system. A detailed knowledge of the "harmonic impedance" of the AC system, at a wide range of frequencies, is needed in order to design the AC filters.
DC filters are required only for HVDC transmission systems involving overhead lines. Voltage distortion is not a problem in its own right, since consumers do not connect directly to the DC terminals of the system, so the main design criterion for the DC filters is to ensure that the harmonic currents flowing in the DC lines do not induce interference in nearby open-wire telephone lines. With the rise in digital mobile telecommunication systems, which are much less susceptible to interference, DC filters are becoming less important for HVDC systems.
Filters for voltage-sourced converters.
Some types of voltage-sourced converters may produce such low levels of harmonic distortion that no filters are required at all. However, converter types such as the "two-level" converter, used with pulse-width modulation (PWM), still require some filtering, albeit less than on line-commutated converter systems.
With such converters, the harmonic spectrum is generally shifted to higher frequencies than with line-commutated converters. This usually allows the filter equipment to be smaller. The dominant harmonic frequencies are sidebands of the PWM frequency and multiples thereof. In HVDC applications, the PWM frequency is typically around 1 to 2 kHz.
Configurations.
Monopole.
In a monopole configuration one of the terminals of the rectifier is connected to earth ground. The other terminal, at high voltage relative to ground, is connected to a transmission line. The earthed terminal may be connected to the corresponding connection at the inverting station by means of a second conductor.
If no metallic return conductor is installed, current flows in the earth (or water) between two electrodes. This arrangement is a type of single-wire earth return system.
The electrodes are usually located some tens of kilometers from the stations and are connected to the stations via a medium-voltage electrode line. The design of the electrodes themselves depends on whether they are located on land, on the shore or at sea. For the monopolar configuration with earth return, the earth current flow is unidirectional, which means that the design of one of the electrodes (the cathode) can be relatively simple, although the design of anode electrode is quite complex.
For long-distance transmission, earth return can be considerably cheaper than alternatives using a dedicated neutral conductor, but it can lead to problems such as:
These effects can be eliminated with installation of a metallic return conductor between the two ends of the monopolar transmission line. Since one terminal of the converters is connected to earth, the return conductor need not be insulated for the full transmission voltage which makes it less costly than the high-voltage conductor. The decision of whether or not to use a metallic return conductor is based upon economic, technical and environmental factors.
Modern monopolar systems for pure overhead lines carry typically 1.5 GW. If underground or underwater cables are used, the typical value is 600 MW.
Most monopolar systems are designed for future bipolar expansion. Transmission line towers may be designed to carry two conductors, even if only one is used initially for the monopole transmission system. The second conductor is either unused, used as electrode line or connected in parallel with the other (as in case of Baltic Cable).
Symmetrical monopole.
An alternative is to use two high-voltage conductors, operating at about half of the DC voltage, with only a single converter at each end. In this arrangement, known as the "symmetrical monopole", the converters are earthed only via a high impedance and there is no earth current. The symmetrical monopole arrangement is uncommon with line-commutated converters (the NorNed interconnector being a rare example) but is very common with Voltage Sourced Converters when cables are used.
Bipolar.
In bipolar transmission a pair of conductors is used, each at a high potential with respect to ground, in opposite polarity. Since these conductors must be insulated for the full voltage, transmission line cost is higher than a monopole with a return conductor. However, there are a number of advantages to bipolar transmission which can make it an attractive option.
A bipolar system may also be installed with a metallic earth return conductor.
Bipolar systems may carry as much as 4 GW at voltages of ±660 kV with a single converter per pole, as on the Ningdong–Shandong project in China. With a power rating of 2,000 MW per twelve-pulse converter, the converters for that project were (as of 2010) the most powerful HVDC converters ever built. Even higher powers can be achieved by connecting two or more twelve-pulse converters in series in each pole, as is used in the ±800 kV Xiangjiaba–Shanghai project in China, which uses two twelve-pulse converter bridges in each pole, each rated at 400 kV DC and 1,600 MW.
Submarine cable installations initially commissioned as a monopole may be upgraded with additional cables and operated as a bipole.
A bipolar scheme can be implemented so that the polarity of one or both poles can be changed. This allows the operation as two parallel monopoles. If one conductor fails, transmission can still continue at reduced capacity. Losses may increase if ground electrodes and lines are not designed for the extra current in this mode. To reduce losses in this case, intermediate switching stations may be installed, at which line segments can be switched off or parallelized. This was done at Inga–Shaba HVDC.
Back to back.
A back-to-back station (or B2B for short) is a plant in which both converters are in the same area, usually in the same building. The length of the direct current line is kept as short as possible. HVDC back-to-back stations are used for
The DC voltage in the intermediate circuit can be selected freely at HVDC back-to-back stations because of the short conductor length. The DC voltage is usually selected to be as low as possible, in order to build a small valve hall and to reduce the number of thyristors connected in series in each valve. For this reason, at HVDC back-to-back stations, valves with the highest available current rating (in some cases, up to 4,500 A) are used.
Multi-terminal systems.
The most common configuration of an HVDC link consists of two converter stations connected by an overhead power line or undersea cable.
Multi-terminal HVDC links, connecting more than two points, are rare. The configuration of multiple terminals can be series, parallel, or hybrid (a mixture of series and parallel). Parallel configuration tends to be used for large capacity stations, and series for lower capacity stations. An example is the 2,000 MW Quebec - New England Transmission system opened in 1992, which is currently the largest multi-terminal HVDC system in the world.
Multi-terminal systems are difficult to realize using line commutated converters because reversals of power are effected by reversing the polarity of DC voltage, which affects all converters connected to the system. With Voltage Sourced Converters, power reversal is achieved instead by reversing the direction of current, making parallel-connected multi-terminals systems much easier to control. For this reason, multi-terminal systems are expected to become much more common in the near future.
China is expanding its grid to keep up with increased power demand, while addressing environmental targets. China Southern Power Grid started a three terminals VSC HVDC pilot project in 2011. The project has designed ratings of ±160 kV/200 MW-100 MW-50 MW and will be used to bring wind power generated on Nanao island into the mainland Guangdong power grid through 32 km of combination of HVDC land cables, sea cables and overhead lines. This project was put into operation on December 19, 2013.
In India, the multi-terminal North-East Agra project is planned for commissioning in 2015-2017. It is rated 6,000 MW, and it transmits power on a ±800 kV bipolar line from two converter stations, at Biswanath Chariali and Alipurduar, in the east to a converter at Agra, a distance of 1,728 km.
Other arrangements.
Cross-Skagerrak consisted since 1993 of 3 poles, from which 2 were switched in parallel and the third used an opposite polarity with a higher transmission voltage. This configuration ended in 2014 when poles 1 and 2 again were rebuilt to work in bipole and pole 3 (LCC) works in bipole with a new pole 4 (VSC). This is the first HVDC transmission where LCC and VSC poles cooperate in a bipole.
A similar arrangement was the HVDC Inter-Island in New Zealand after a capacity upgrade in 1992, in which the two original converters (using mercury-arc valves) were parallel-switched feeding the same pole and a new third (thyristor) converter installed with opposite polarity and higher operation voltage. This configuration ended in 2012 when the two old converters were replaced with a single, new, thyristor converter.
A scheme patented in 2004 is intended for conversion of existing AC transmission lines to HVDC. Two of the three circuit conductors are operated as a bipole. The third conductor is used as a parallel monopole, equipped with reversing valves (or parallel valves connected in reverse polarity). This allows heavier currents to be carried by the bipole conductors, and full use of the installed third conductor for energy transmission. High currents can be circulated through the line conductors even when load demand is low, for removal of ice. , no tripole conversions are in operation, although a transmission line in India has been converted to bipole HVDC (HVDC Sileru-Barsoor).
Corona discharge.
Corona discharge is the creation of ions in a fluid (such as air) by the presence of a strong electric field. Electrons are torn from neutral air, and either the positive ions or the electrons are attracted to the conductor, while the charged particles drift. This effect can cause considerable power loss, create audible and radio-frequency interference, generate toxic compounds such as oxides of nitrogen and ozone, and bring forth arcing.
Both AC and DC transmission lines can generate coronas, in the former case in the form of oscillating particles, in the latter a constant wind. Due to the space charge formed around the conductors, an HVDC system may have about half the loss per unit length of a high voltage AC system carrying the same amount of power. With monopolar transmission the choice of polarity of the energized conductor leads to a degree of control over the corona discharge. In particular, the polarity of the ions emitted can be controlled, which may have an environmental impact on ozone creation. Negative coronas generate considerably more ozone than positive coronas, and generate it further "downwind" of the power line, creating the potential for health effects. The use of a "positive" voltage will reduce the ozone impacts of monopole HVDC power lines.
Applications.
Overview.
The controllability of a current-flow through HVDC rectifiers and inverters, their application in connecting unsynchronized networks, and their applications in efficient submarine cables mean that HVDC interconnectors are often used at national or regional boundaries for the exchange of power (in North America, HVDC connections divide much of Canada and the United States into several electrical regions that cross national borders, although the purpose of these connections is still to connect unsynchronized AC grids to each other). Offshore windfarms also require undersea cables, and their turbines are unsynchronized. In very long-distance connections between two locations, such as power transmission from a large hydroelectric power plant at a remote site to an urban area, HVDC transmission systems may appropriately be used; several schemes of these kind have been built. For interconnectors to Siberia, Canada, India, and the Scandinavian North, the decreased line-costs of HVDC also make it applicable, see List of HVDC projects. Other applications are noted throughout this article.
AC network interconnectors.
AC transmission lines can interconnect only synchronized AC networks with the same frequency with limits on the allowable phase difference between the two ends of the line. Many areas that wish to share power have unsynchronized networks. The power grids of the UK, Northern Europe and continental Europe are not united into a single synchronized network. Japan has 50 Hz and 60 Hz networks. Continental North America, while operating at 60 Hz throughout, is divided into regions which are unsynchronized: East, West, Texas, Quebec, and Alaska. Brazil and Paraguay, which share the enormous Itaipu Dam hydroelectric plant, operate on 60 Hz and 50 Hz respectively. However, HVDC systems make it possible to interconnect unsynchronized AC networks, and also add the possibility of controlling AC voltage and reactive power flow.
A generator connected to a long AC transmission line may become unstable and fall out of synchronization with a distant AC power system. An HVDC transmission link may make it economically feasible to use remote generation sites. Wind farms located off-shore may use HVDC systems to collect power from multiple unsynchronized generators for transmission to the shore by an underwater cable.
In general, however, an HVDC power line will interconnect two AC regions of the power-distribution grid. Machinery to convert between AC and DC power adds a considerable cost in power transmission. The conversion from AC to DC is known as rectification, and from DC to AC as inversion. Above a certain break-even distance (about 50 km for submarine cables, and perhaps 600–800 km for overhead cables), the lower cost of the HVDC electrical conductors outweighs the cost of the electronics.
The conversion electronics also present an opportunity to effectively manage the power grid by means of controlling the magnitude and direction of power flow. An additional advantage of the existence of HVDC links, therefore, is potential increased stability in the transmission grid.
Renewable electricity superhighways.
A number of studies have highlighted the potential benefits of very wide area super grids based on HVDC since they can mitigate the effects of intermittency by averaging and smoothing the outputs of large numbers of geographically dispersed wind farms or solar farms. Czisch's study concludes that a grid covering the fringes of Europe could bring 100% renewable power (70% wind, 30% biomass) at close to today's prices. There has been debate over the technical feasibility of this proposal and the political risks involved in energy transmission across a large number of international borders.
The construction of such green power superhighways is advocated in a white paper that was released by the American Wind Energy Association and the Solar Energy Industries Association in 2009. Clean Line Energy Partners is developing four HVDC lines in the U.S. for long distance electric power transmission.
In January 2009, the European Commission proposed €300 million to subsidize the development of HVDC links between Ireland, Britain, the Netherlands, Germany, Denmark, and Sweden, as part of a wider €1.2 billion package supporting links to offshore wind farms and cross-border interconnectors throughout Europe. Meanwhile, the recently founded Union of the Mediterranean has embraced a Mediterranean Solar Plan to import large amounts of concentrated solar power into Europe from North Africa and the Middle East.
Advancements in UHVDC.
UHVDC (ultrahigh-voltage direct-current) is shaping up to be the latest technological front in high voltage DC transmission technology. UHVDC is defined as DC voltage transmission of above 800 kV (HVDC is generally just 100 to 800 kV).
One of the problems with current UHVDC supergrids is that – although less than AC transmission or DC transmission at lower voltages – they still suffer from power loss as the length is extended. A typical loss for 800 kV lines is 2.6% over 800 km. Increasing the transmission voltage on such lines reduces the power loss, but until recently, the interconnectors required to bridge the segments were prohibitively expensive. However, with advances in manufacturing, it is becoming more and more feasible to build UHVDC lines.
In 2010, ABB Group built the world's first 800 kV UHVDC in China. The Zhundong–Wannan UHVDC line with 1100 kV, 3400 km length and 12 GW capacity was completed in 2018. As of 2020, at least thirteen UHVDC transmission lines in China have been completed.
While the majority of recent UHVDC technology deployment is in China, it has also been deployed in South America as well as other parts of Asia. In India, a 1830 km, 800 kV, 6 GW line between Raigarh and Pugalur is expected to be completed in 2019. In Brazil, the Xingu-Estreito line over 2076 km with 800 kV and 4 GW was completed in 2017. As of 2020, no UHVDC line (≥ 800 kV) exists in Europe or North America.
Further reading.
John Wiley & Sons, 2016
External links.
[[Category:High-voltage direct current| ]]


Radox connector

RADOX Solar connectors are a largely obsolete electrical connector used to connect solar panels together in series to form "strings". The RADOX Solar brand covered a variety of products from Huber+Suhner of Austria, but the connectors are the best known member of the line and the term Radox connector is synonymous. The Radox connectors were most widely known from their use on REC solar panels from Norway, and did not find widespread use outside that market.
Radox connectors did not meet new US standards that required the cables to not be able to disconnect without the use of a tool. Many companies introduced new connectors to meet these requirements, like the MC4 connector and Solarlok, but the Radox was not updated and quickly disappeared from the market.


Lambton Generating Station

The Lambton Generating Station was a coal-fuelled power plant located on the St. Clair River near Corunna, Ontario, delivering up to 950 MW of power to the grid. It is owned by Ontario Power Generation.
The plant previously had a total generating capacity of 1,976 MW, prior to the permanent shutdown of generating units 1 and 2 (of four) in October 2010. The remaining units were shut down in September 2013. It was connected to the power grid via numerous 230 kV lines, and also had two interconnections with Detroit Edison and ITC Transmission via a 230 kV line (Lambton-St. Clair #1) and a 345 kV line (Lambton-St. Clair #2). It is located almost exactly across the St. Clair River from Detroit Edison's St. Clair Power Plant in East China, Michigan.
The facility has three smokestacks, one of which is equipped with flue-gas desulfurization units, commonly called "scrubbers", to remove sulfur oxide. Emissions from scrubbers at the Lambton station could be seen for over 16 km, although with the scrubbers operating properly, these plumes likely had over 90% less SO2 compared with other coal-fired stations without scrubbers.
On November 22, 2016, it was announced that Ontario Power Generation was no longer looking at alternative uses for Lambton Generating Station, and that the facility would be decommissioned in 2017.
It was definitively closed in 2020. Demolition work is in progress and should last 2 years.
Redevelopment.
In 2012, plans were announced to relocate a proposed natural gas-powered generating station, originally intended for construction by Greenfield South Power Corporation in Mississauga, near to Etobicoke's Sherway Gardens, to the Lambton Generating Station site.
Construction in Mississauga had already begun in 2011; the original site selection was cancelled during the October 2011 provincial election with the project becoming a key issue during that campaign and the subsequent 2014 campaign.