Churchill Falls (Labrador) Corporation Limited

The Churchill Falls (Labrador) Corporation, also known as CF(L)Co or CFLco is a Canadian electric company. The company was founded in 1961 and is based in St. John's, Newfoundland and Labrador. Churchill Falls (Labrador) Corporation Limited operates as a subsidiary of Newfoundland and Labrador Hydro.
History.
CF(L)Co was originally formed in 1958 as a subsidiary of British Newfoundland Development Corporation (BRINCO) and known as the Hamilton Falls Power Corporation, it built and operated the Churchill Falls hydroelectric complex.
In 1961, the Government of Newfoundland and Labrador granted the Hamilton Falls Power Corporation a 99-year lease to the 67,340 square kilometers watershed of the Upper Churchill. The Hamilton Falls Power Corporation became known as the Churchill Falls Corporation in 1965 when the name of the falls was changed to commemorate former British Prime Minister Winston Churchill.
CF(L)Co began construction on Churchill Falls Generating Station in 1966 and on May 12, 1969, signed a power contract with Hydro-Québec. The agreement committed Hydro-Québec to buy most of the plant's output at one-quarter of a cent per kilowatt-hour — the exact rate is 0.25425¢ per kilowatt-hour until 2016 and 0.20¢ for the last 25 years of the contract —, to build and maintain power lines to carry the power to market and to enter into a risk-sharing agreement whereas the Quebec Crown corporation would cover part of the interest risk and buy some of BRINCO's debt, in exchange for an increased share in CF(L)Co.
The 5,428-megawatt generating station delivered its first kilowatts on December 6, 1971 and its 11 turbines were fully operational by June 1974. In 1974 the Government of Newfoundland and Labrador purchased a controlling interest in CF(L)Co from BRINCO and turned it over to the Newfoundland and Labrador Power Commission. The Commission had a 65.8% share in the corporation and the remaining 34.2% was owned by Hydro-Québec.
Legal battle.
In 1967, the year CF(L)Co qualified for Crown Corporation status, the Newfoundland Government initiated proceedings in the Newfoundland Supreme Court to recall 800 megawatts (MW) of the Churchill Falls power from CF(L)Co based upon the lease granted to the corporation in 1961. By 1980, the case had not been resolved, and in that year the Newfoundland Legislature passed the Re Upper Churchill Water Rights Reversion Act to reclaim the water rights granted to the corporation.
Both legislations and the contract itself were subject to protracted legal battles between the two neighboring provinces, ending up before the Supreme Court of Canada. The court declared the Upper Churchill Water Rights Reversion Act "ultra vires" in 1984, and twice affirmed the validity of the 1969 contract in 1988.


Mangorei Power Station

The Mangorei Power Station is a hydroelectric power facility near Mangorei in Taranaki in New Zealand which makes use of water from the Waiwhakaiho River (which is often written as Waiwakaiho) and the Mangamahoe Stream catchments.
History.
Initial development.
Of the first 14 publicly available electricity supplies in New Zealand, seven were in the province of Taranaki. Most of these were hydroelectric schemes, utilizing the seasonally consistent water supply provided by Mount Taranaki’s many streams. This development was driven by the demand for electric lighting by both town and rural dwellers plus farmers wishing to power their new electric shearing sheds, milking machines and separator.
In the late 19th century the New Plymouth Borough Council decided to investigate its options for constructing a hydro-electric power station to supply the town with electricity as well as providing a water supply. The nearby Waiwhakaiho River was identified as a suitable source of water. In 1898 a completion was held to design a scheme. The completion was judged by respected engineer Richard Liron Mestayer (1843 - 1921).
The council decided not to proceed with any of the schemes put forward and instead engaged Mestayer in 1901 to design his own scheme, which was subsequently accepted.
His design called for an intake on the Waiwhakaiho River from which water was conveyed to a powerhouse first by a tunnel that passed under the Mangamahoe Stream to a forebay on the hill, from which a diameter steel penstock conveyed the water down to a manifold outside of the station from where the water was split to supply two turbines.
Construction begins.
Mestayer's design was accepted, which lead to a construction contract being issued on 13 July 1903 to McWilliams and Andrews to build the scheme. The tunnel was dug from the outlet, from a side drive about 16 chains (322 metres) from the outlet, and from a deep shaft about 21 chains (422 metres) from the outlet. From the side drive and also from the shaft the tunnel was driven in both directions. The alignment of the tunnel was laid out on the surface by Sladden & Palmer, Civil Engineers and Surveyors, and then transferred to the bottom of the shaft by means of heavy plumb bobs suspended from the top by very fine wires, with the plumb bobs themselves hanging in buckets of water to dampen their movement. The line thus transferred was produced in both directions by means of a theodolite. The line was marked inside the tunnel by iron spikes driven into the roof, and from which plumb bobs were suspended to guide the excavation. The levels were transferred from, the surface to the bottom of the shaft using a long steel tape, and then maintained as the work progressed by means of an engineer's level.
The power scheme received a licence from the government to generate electricity on 24 February 1905, and was completed in late 1905.
The first electricity was received in New Plymouth in January 1906, with 120 street lamps and the town hall being lit. By the end of the year the power station which operated from dusk to midnight was supplying 41 customers. By 1907 demand had increased with the power station supplying 126 customers and 230 by 1912.
The power station originally had two turbines each driving a 45 kW single-phase generator. To meet increasing demand the station was enlarged under the supervision of borough engineer A.H. Kendall to accommodate an additional 150 hp turbine driving a 90 kW single-phase generator, which entered service in December 1907.
Expansion.
With no storage capacity the 180 kW power station was strictly run of the river and was proving to be unreliable during periods of low summer flow. The growth of the town, and the impending introduction of electric powered trams necessitated the need for more generation, as well as providing more water for water reticulation purposes. As a result, the council in 1909 employed Henry Westcott Clime, the principal of consulting engineers H.W. Clime & Son to investigate possible options. Climie identified that the generation output was limited by the size of the tunnel, which couldn't be taken out of service and enlarged without cutting off the power supply to the town. He offered three options, (a) build a weir across the Waiwhakaiho below the present intake so as to give a greater head of water; (b) divert a portion of the water from the Waiwhakaiho, at a point about thirty chains above the present intake, by means of a tunnel and open race into the Mangamahoe Stream, and build a dam across the latter a little below where the present tunnel passes under it, or (c) take the water off the Waiwhakaiho at the same point as proposed in (b) and convey it by means of a larger new tunnel through the hill to the power station. Climie's recommended option was (a) which he calculated would give an effective 876 hp, equivalent to nearly 660 kilowatts of electrical energy at an estimated cost of £5,137 for the civil works plus the cost of the additional turbines and generators.
The council initially opted for option (a) but an inability to install a suitable foundation and a large flood caused this to be abandoned in favour of Climie's Option (c) which involved construction on the Waiwhakaiho River of a new intake 25 chains (502 m) further upstream, which diverted water by means of a 22 chain (442 m) long water race, of which consists of a tunnel into the Mangamahoe Stream, where a 13 ft (3.96 m) high concrete gravity dam was constructed in 1914, just downstream of where the original tunnel had crossed it.
Filling of the lake began in November 1914. From the dam the water was taken to a forebay, from where it entered the powerhouse, and the reticulation pipes of the town. This new diversion which cost approximately £4,000, captured not only water from the Waiwhakaiho but also all of the flow of Mangamahoe.
As a result of the increased flow the total output of the power station increased to 750 kW.
The new intake proved difficult to maintain as it frequently became blocked with large stones, gravel and branches which then had to be manually removed. As a result, improvements were made to its design which were completed on 16 January 1916.
At the same time as efforts were being made to increase the supply of water two 250 kW generators ordered from Turnbull and Jones entered service in 1912 and 1913. In 1914 the original two 45 kW generators were replaced by a new 250 kW generator.
In 1915 the council converted the transmission and distribution voltage on its system to 6.6 kV single-phase, which was upgraded in 1921 to three-phase.
Damage to and replacement of the dam.
On 25 March 1917 the bed of the Mangamahoe River was seriously scoured out immediately from under the tunnel where it passed under the dam to a depth of to , which caused all of the water in the dam to be lost.
A temporary sack dam was erected behind the breach which allowed an approximately 3ft 6in (1.1 metre) head to be obtained in the reservoir. However it was difficult to regulate the flow of water while trying to avoid the risk of carrying away the dam at another place.
Rather than repair the damage which would have meant closing down the tunnel and to restricting the town's demand (including closing down the tramways and turning off the street lighting) to what could be supplied via a tie line from the Taranaki Electric Power Board it was decided to build a new dam downstream of the existing dam. A design for a new concrete dam which would give a higher head than the existing dam was submitted to the council on 23 May 1917 and approved.
The new dam was long at the top, high with a bottom thickness of and a top thickness of widened by cornices to 2ft 6in (760 mm), to form a footway, which extends over the by-wash in two 13 ft 6 in (4.1 m) spans. This footbridge and the scour-valve platform were the only portions of the dam in which steel reinforcement was installed. The spillway was widened to . No great difficulties were met during construction, except that it was necessary dig to lower than originally intended in order to find a hard, and watertight bottom which was found to extend for in length from the north end to the centre of the stream. Beyond this to the south end of the wall the excavation was taken down to a depth of from to lower than originally intended. A cast-iron gate valve was installed to allow emptying and letting sand out of the lake.
By February 1918 the dam had finished and refilled with water.
Mason's proposal.
With the demand for electricity within the Borough of New Plymouth showing no sign of levelling off, and with applications for power been received from other local bodies, the council committed to expanding the Mangorei scheme.
The council in late 1918 engaged consulting engineer John Blair Mason (1858 to 1927) of Blair Mason, Lee, Owen and Cree Brown, to investigate the various options. Mason offered a number of options but Scheme D which also had a partial option called E11 became the preferred choice of the council. Scheme D called for tapping the Waiwhakaiho River at a new upstream intake and conveying the water via a tunnel to a lake created by a new high dam on the Mangamahoe Stream about 30 chains (603 m) above the existing dam. This high dam would give a head of above the powerhouse, submerge at least 30 acres (12 hectares) and with a draw off would provide 13,000,000 cubic feet (368,000 cubic metres) of storage. The lake would rise above the saddle about half a mile (800 m) south of a forebay from whence it would be conveyed by water races and penstocks to the powerhouse. The actual storage required with a load factor of 0.45 to develop the maximum water power would amount to 7¼ million cubic ft (205,000 cubic metres). Mason estimated that this would give a maximum of 6,300 hp. His estimated cost for the project was £46,000. Scheme E11 on the other hand he estimated would cost £11,700, of which only £1,300 need be regarded as temporary work, being the estimated cost of race and depreciation on pipe line. It involved constructing the weir, intake and tunnel portions of the permanent works of scheme D, which could reused if the council choose at a later date to proceed with the full scheme. From the outfall of the tunnel the water would be conveyed via a 140 chain (2,800 m) long water race to a penstock above the present forebay. From here up to 100 cusecs (2.8 cumecs) would be delivered to the powerhouse through new penstocks.
Over the next two years the plan were modified, with scheme D being renamed Scheme 1, with a dam now giving a head, which would submerge 95 acres (38 hectares) and have a capacity of 50 million cubic feet (1.4 million cubic metres) with a draw off. This would require the building of two long embankments on the South side of the proposed reservoir to prevent the water overflowing the adjacent lands. There would also be three penstocks running from the forebay/surge chamber to the powerhouse. This scheme was expected to develop 9,000 hp.
The partial scheme now known as E2 was basically as per Mason's but had an increased head and flow of 150 cusec which it was expected would produce an additional 2,000 hp on top of the power station's existing 900 hp.
The council made the decision in 1919 to proceed with the partial scheme. However its estimated cost had to the council's enormous disappointment increased by January 1920 to £112,000 and which they expected to make an annual profit of £13,800 on the electricity being generated. The loans to service this expenditure were approved by ratepayers. In October 1920, the estimate was further increased to £172,000 (which included contingencies of £12,000) with an expected annual profit on the electricity being generated dropping to £6,042. As a result, the council in November 1920 with approximately £60,000 already spent to date reluctantly had to go back to ratepayers to obtain approval to raise another £60,000 loan.
The partial scheme.
The partial scheme as completed in early 1923. had a diversion weir and intake about a mile and a half above the previous intake. The new concrete diversion intake on the Waiwhakaiho River had a base 15 ft below the river level and rose to about 12 ft above the normal height of the river. it was divided into four valve chambers, with three ports open to the river on one face, and one on the other face of the intake. These could be opened or closed by gates as required.
From the intake the water was conveyed through the 1,800 ft (548 m) long Tunnel No. 1. A few feet of this tunnel was driven from the intake end, but the principal excavation work was being done from the opposite end of the tunnel. The haulage of the spoil from the driving was undertaken by pony-drawn trucks. The tunnel was light by electricity with airshafts at regular intervals. The excavation of the tunnel which was estimated to cost approximately £12,000 was undertaken by Payne and Blanchard Ltd using a workforce that varied between 13 and 25 men working in three shifts.
At the exit of Tunnel No.1 a small high dam (which was termed a "Turning Wall") with a concrete core was built to deflect the water into Water Race No. 1. This long race terminated at a 558 ft (170 m) long pipeline which took the water over the Mangamahoe Stream below to the long Water Race No. 2. This race then transitioned to 4,000 ft (1,219 m) long Tunnel No.2 which took it to a forebay/surge chamber 140 ft (42.7 m) higher up the hill than the existing surge chamber. From here a steel penstock conveyed the water down to the powerhouse.
This improved supply of water and increased head of allowed the council to install two new 1,000 kVA generators, convert one of the existing 250 kW machines, to produce 750 kVA, and replace another 250 kW unit with a new 1,000 kVA unit.
Defects were found in Tunnel No.2 which led the council in 1923 to dismiss their consulting engineers Blair Mason, Lee, Owen and Cree Brown, who had been responsible for overseeing all civil works. The council's electrical department was responsible for the electrical work.
On 27 April 1928 approximately of the southern end of the pipeline that carried water across the Mangamahoe Stream was destroyed by a landslide, which cut off the water supply to the power station for approximately two weeks until it was repaired. Until it was the supply the street light lighting and trams were switched off and New Plymouth's demand was restricted to what could be supplied via a tie line from the Taranaki Electric Power Board.
Creation of Lake Mangamahoe.
As demand continued to rise and aware of the benefits of having a larger reservoir that would provide both generation storage capacity as well as delivering a reliable water supply to New Plymouth, the council committed to undertaking the full scheme by building a dam on the Mangamahoe Stream. The contract to build the dam was won by J. T. Julian and Son in March 1929 with a price of £35,310 7s 6d.
Construction started in 1929 with the diversion of the stream through a tunnel on the left abutment. The foundations for the dam were then excavated and a trench dug for the concrete core.
Mechanical earth moving was just starting to be employed in New Zealand, and as a result tractors and scrapers were used to construct the dam.
The dam when finished in 1931 submerged approximately 79 acres (32 hectares) of land to form Lake Mangamahoe.
At the time of its completion the dam was the highest earth dam in Australasia. The existing two water races and the pipeline over the Mangamahoe Stream were left in place and flooded by the lake.
By March 1948 the various modifications to the power station had resulted in it having an output of 3,750 kW, which was provided by one 90 kW, one 240 kW, one 750 kVA and three 1,000 kW generators.
On 1 September 1983 the power station was added to the New Zealand Historic Places list as a Historic Place Category 2.
Changes in ownership.
As a result of the restructuring of the New Zealand electricity sector in the early 1990s, the electricity department of the New Plymouth City Council (trading as New Plymouth Energy) merged with the Taranaki Electric Power Board on 7 May 1993 to form Taranaki Energy Ltd.
In 1995 Taranaki Energy Ltd merged with and took the name of Powerco.
The introduction of the Electricity Industry Reform Act in 1998 required New Zealand's electricity companies to separate their network and retail businesses. As a result, Powerco having elected to remain a network company sold its five power stations (which including Mangorei) to Trustpower.
Improvements.
In recent years Trustpower has undertaken extensive work on the linings of the supply tunnel to reduce friction.
Design.
A weir on the Waiwhakaiho River diverts water into the , 7 ft 3 inch (2.2 m) diameter concrete lined Tunnel No.1 which conveys it to the top of Lake Mangamahoe.
This manmade lake was created by a dam at its northern end which impounds the Mangamahoe Stream above its confluence with the Waiwhakaiho River. The 27.4-metre-high earth dam, which is 160 m long at the crest, has a substantial curved concrete core running throughout its centre and set into the hard sandstone on each bank and is at least 6 m thick. The lake side has a 3-to-1 slope, with the surface exposed to the water surface lined with stone, while the downstream side has a 2-to-1 slope.
To the west of it is an intake structure with four remotely controlled intake gates. From the intake structure the 4,000-foot-long (1,219 m), 7-foot-3-inch-diameter (2.2 m) Tunnel No.2 conveys the water from the lake to a 37-foot-diameter (11.2 m) forebay/surge chamber. From the forebay/surge chamber two steel penstocks carry the water down to the powerhouse which is located on Hydro Rd (S.H.3), Mangorei.
In the powerhouse are one 700 kW generator and three 1.3 MW generators. The generators discharge into a tailrace which flows into the Waiwhakaiho River, approximately six kilometres down stream of the intake.
Water is also taken via two intakes on the lake's western shore to a nearby water treatment plant, from where it is distributed to consumers in the New Plymouth area.
Operation.
Resource consents which were granted in 1996 and which expire in June 2021 allow the power station to divert up to 10 cumecs of water from the Waiwhakaiho River and back into it. The power station is required to maintain a minimum flow in the river below the diversion weir.
Lake Mangamahoe also serves as the water supply for New Plymouth and is a Wildlife Refuge. A trap and transfer programme manages any disruption to the migration of longfin eel.
The power station is embedded in Powerco's network behind Transpower's Carrington Street Substation.
The power station is operated remotely via a SCADA system from Trustpower's control centre in Tauranga.


Piriaka Power Station

The Piriaka power station is a hydroelectric power facility in Manawatū-Whanganui in New Zealand which draws water from behind a weir on the Whanganui River near Piriaka and diverts it through a canal and penstock to the Piriaka Power Station, which is located approximately southeast of the town of Taumarunui, via SH4. The power station discharges back into the Whanganui River.
History.
Development.
Since 1914 the borough of Taumarunui had had a gas plant supplied by the Dreadnought Gas Co. which supplied the town with gas for lighting and cooking but by 1917 the system was beginning to deteriorate.
The passing of the Electric Power Boards Act in 1918 which allowed local authorities to generate and distribute electricity assisted in converting Andrew S. Laird, who had been the mayor of Taumarunui since 1917 into an enthusiastic proponent of electricity generation. While the Taumarunui borough council had intended to wait until after the First World War had finished before pursuing the matter further, Laird was able to convince the council to follow the lead of others in the region such as Ohakune, Raetihi and Te Kuiti in building its own hydroelectric power scheme. As a result, W. J. Gibbs the engineer of the Te Aroha Borough Council was engaged to investigate possible options. However, nothing appears to have resulted from his endeavours. Then in early 1919, the council asked the Minister of Internal Affairs to request Lawrence Birks, the senior electrical engineer in the Public Works Department (PWD) to assess the hydroelectric potential of the Taumarunui area. The government declined the request and suggested that the council employ a private consulting engineer.
Laird became even more supportive of a scheme after while attending a conference of local bodies in Hamilton in February 1919 to consider the development of hydro-electric power in the Auckland region and visiting the Horohara power station. The borough council polled its ratepayers for approval to raise loan to build a power scheme but the motion was defeated by 118 to 80.
Three months later as a result of losing the April 1919 elections Laird was replaced by former mayor, George Steadman and the idea of a power scheme was dropped.
By 1920 despite there being 71 local electrical supply authorities throughout New Zealand. Taumarunui had no electrical supply despite the Public Works Department pointing out that there was potentially a demand of 2,000 hp from combined population of the 9,667 in Taumarunui and the surrounding region, which was more than enough to justify the establishment of an electrical supply authority.
With the reliability of their gas supply system continuing to deteriorate (for instance by January 1919 it was leaking 25,000 to 30,000 cubic feet of gas per month), the borough council decided to investigate the options for switching to electricity. On 5 August 1920 applications (which closed on 6 September 1920) were called for from electrical engineers to undertake the necessary investigations and to provide an estimate of the required cost of a scheme. From the 16 applications the Wellington-based consulting engineers Hay & Vickerman won the contract, with a fee of £100 subsequently being agreed for their preliminary work.
The borough council formally received Hay & Vickerman's report on 18 November 1920. Hay & Vickerman offered four possible hydro-electric power and lighting schemes. The council adopted the engineer's recommended Wanganui River Number 1 proposal, which they estimated would cost £44,000.
Due to the undeveloped and sparsely populated state of the rural area surrounding Hay & Vickerman recommended against establishing a power board.
After the Wanganui River Trust consented to borough council's proposed power scheme, the Whanganui River or Wanganui River as it was then called, Hay & Vickerman applied on behalf of their client for a water power licence, which was granted on 21 February 1924. This licence also granted the borough council the right to distribute electricity with the borough, the town of Manauni, part of Kaitieke County along the sides of the Whanganui River for a mile either side from Kakahi down to the junction of the Onagare and Whanganui Rivers.
A poll of Taumarunui ratepayers in April 1921 by 230 votes to five approved the raising of a loan to pay for the power scheme. Despite having remit over such a large area the borough council followed Hay & Vickerman advice and refused the urgings of the government and local Chamber of Commerce to become a power board. As a result, Piriaka's installed capacity was only sufficient to supply the Taumarunui load. As a result, even the town of Manauni though which the transmission passed from Piriaka to Taumarunui was not allowed to take a supply from the line. Manauni's situation was only rectified in 1928.
An economic slump due to the collapse in export prices for New Zealand's meat and wool exports made obtaining financing difficult. It took seven attempts between May 1921 and June 1922 before in that month a Wellington insurance company agreed to finance the project at an interest rate of 6%.
With the loan approved the borough council on 18 July 1922 established a committee to oversee the work and obtain the land required for the power scheme.
While agreeing to differ payment until a loan was obtained, Hay & Vickerman had continued with a detailed design of the scheme. This allowed construction work to quickly commence following the granting of the loan. One problem that the borough council had was that Cyril Smith the owner of land where it was proposed that the power station was to be located objected to a surveyor coming onto his land to survey the route of the penstock and take bore samples Even after the borough council advised him that the 1908 Public Works Act allowed them to go into his land, he still refused entry. The borough council, therefore, took him to court and received a ruling from the local magistrate on 8 August 1922 that he could not refuse access and had to pay all legal costs. Eventually, Smith and the borough council entered into negotiations, which resulted in it purchasing 15 acres of Smith's land for £450.
Orders for equipment were placed in February 1923 to Boving & Co Ltd for turbines and governors (£1,905), National Electrical & Engineering for General Electric generators and exciters (£2,352) and British Thomson Houston switchgear and power cabling (£2,244).
Construction.
An access road was built to the construction site, where a simple construction camp of four two-man huts together with a workshop and a building to store equipment was established. The workers paid rent of two shillings a week to stay in a hut. Others lived in tents.
Construction began on the headworks, canal, penstock and power house and the distribution network under the supervision of construction engineer H. Langdon.
As an indication of how many men were employed to build the power station an average of 21.5 men were employed on-site during February 1923.
On 14 March 1924, with electricity from Piriaka becoming available the council decided that the gas works should be shut down by the end of the month. By this time there were only 49 customers receiving a gas supply.
As work continued on the power station the first customers were being signed up, transmission lines were being constructed, street lighting installed and buildings wired to accept electricity. By January 1925 approximately 210 buildings had been wired.
From the power station a 3.3 kV overhead transmission line using No.8 wire was built to supply the village of Piriaka while a second 3.3 kV line was built using7/14 wire via Manunui to Taumarunui.
Commissioning.
By February 1924 construction had reached the point that commissioning tests could be undertaken. By 4 March 1926 the testing had been completed allowing the main street of Taumarunui to be lit by 22 lamps, while 80 smaller lamps were energised in other streets. The shops in the business area were also lit up with a total of 54 consumers receiving a supply.
The power station was commissioned with two Boving & Co 300 hp vertical Francis turbines which were each directly coupled to a General Electric 250 KVA, 212 kW generator to give a total station output of 425 kW at 3.3 kV. The output of the generators connected to British Thomson-Houston switchgear.
To manage their new power station and reticulation system the borough council created the Taumarunui electricity department with a permanent staff of H. F. (Henry) McLeod, electrical engineer on a yearly salary of £400; W. Milne, power station engineer on a yearly salary of £325; R.S. Uren, lineman on yearly salary of £250 and Crawford McHenry as assistant lineman on wages of £4 per week. Henry McLeod was to serve as an electrical engineer until his retirement in July 1949.
The power scheme had cost £50,000 to build and taken 18 months to complete. The power scheme was officially opened on 21 March 1924 by Prime Minister William Massey first at the power station at 2pm and then following dinner there was a separate evening ceremony in Hakiaka Street in Taumarunui when the street lights were switched on.
By August 1925 the uptake of electricity was such that Henry McLeod was recommending that more capacity be installed at Piriaka and that the 3.3 kV transmission voltage be increased to 11 kW. While no more capacity was added at Piriaka the borough council commenced a project in the later half of 1925 to upgrade the transmission voltage to 11 kV. This involved installing a 500 kVA transformer to step up the voltage at Piriaka, replacing the insulators on the 5½ miles (8.85 km) of transmission lines and installing three step down transformers at various locations in the network.
By the 1927 financial year the connected load had increased to 440 kW during the day and 245 kW at night. In that same 12-month period the station generated 927,126 GWh, but the electricity department's metering could only account for 704,842 GWh.
Connection to the national electricity system.
With it unable to meet the demand for more electricity the borough council after investigating other options such as installing a diesel generator at Piriaka reached an agreement with the government in 1938 to connect the local system to the national electricity system via a new transmission line. The connection to the bulk supply entered service on 2 April 1939. As a part of the agreement to take a bulk supply from the government it had been agreed that Piriaka would only be allowed to remain in service as a pumping station for the borough's water supply system. As a result, on 11 October 1939 Piriaka creased generating.
In May 1940 to help with the war effort and the demand for electricity from the new war-related industries Piriaka was returned to service, with the government requesting that it run at its maximum output, 24 hours a day. A shortage of staff meant that the PWD had to help repair the weir and tailrace, while the Auckland Electric Power Board loaned an operator to help run the power station.
A severe flood on 14 December 1958 damaged the weir, headworks and washed away approximately 2 chains (40 metres) of the canal's concrete lining which reduced the station head, allowing only one of its two generating units being able to remain in service. Even then there were regular stoppages to clear blocked intake screens. The repairs to the power scheme cost £14,000.
Upgrading.
In the 1960s the power station's existing Turell voltage regulator was replaced by an ASEA solid state voltage regular which meant that the station's voltage did not now require constant attention, allowing the number of operators at the station to reduced from four (on a 24-hour shift) to two people.
By the late 1960s, Piriaka had been reduced to a single 300 kW generating unit. Mandeno Chitty & Bell were hired to design and oversee increasing the station's output. As a result, a modified Kaplan turbine driving a 700 kW generator was installed in February 1971 in a separate building. However, the new generating unit gave problems from the time it entered service. It was eventually determined that it had been installed a metre higher than it should have been installed. This led to compensation being paid to the Taumarunui Borough Council which was more than the cost of the new generating unit. Even as late as 1978 the new generating unit was still giving problems with cavitation of the turbine blades and leaking bearing seals, both issues eventually being resolved.
The commissioning in 1972 of the Western Diversion of the Tongariro power scheme resulted in the diversion of water from eight tributaries of the upper Whanganui River. By June 1973 so significant was the diversion of waters that it was impacting on the operation of Piriaka. By the end of the year, the NZED was playing compensation to the borough council, the amount depending upon weather conditions and the amount of water they were taking. The lower river flows attracted the attention of other parties which resulted in hearings by Rangitikei – Wanganui Catchment Board in 1982 with 17 submissions and again in 1988 with 1,250 submissions being received. Unhappy with the tribunal's ruling that the NZED and its successor, the Electricity Corporation of New Zealand (ECNZ), should return river flows to full into summer and half in winter and also continue to pay compensation they appealed the decision. By September 1989 a total of NZ$510,00 had been paid to date to the borough council for loss of generation at Piriaka.
In late 1978 a flood blocked the intake gates with mud and the mistake was made to allow the canal to drain through the generating units, rather than keeping it full of water. With nothing to push back against it, the pressure from the saturated ground beside canal caused the canal walls to collapse inwards. It took three months to repair the damage and return the power station to service.
In response to the passing of the 1987 Empowering Act, which opened the electricity supply industry to market forces discussion began between the Taumarunui Borough Council and the King Country Electric Power Board. As a result, the borough council in 1989 sold its electricity assets (including Piriaka) for NZ$750,000 to the power board.
In response to the 1992 Energy Companies Act, the King Country Electric Power Board on 1 July 1993 transitioned to a public company King Country Energy Ltd, which took over ownership of Piriaka.
In the early 1990s, a fire in the windings of the generating unit G1 resulted in it being out of service for 2½ months.
Design.
The scheme was originally designed with provision to allow the mechanical output to be increased from 600 hp (447 kW) to 1,800 hp (1,342 kW).
Three one-metre-high concrete weirs, approximately 200 mm thick connecting natural islands on the Whanganui River impound water in a small headpond. From here water is diverted to control gates and then via a concrete-lined canal to a forebay (fitted with screens) from which it flows through a buried by concrete penstock to a concrete surge chamber located beside the two powerhouses, from which water passes via penstocks to the turbines.
There are two powerhouses, the original 1924 building which houses two vertical Francis turbines, each powering a 0.25 MW generating unit, designated G2 and G3. In a separate adjacent building which was commissioned in 1971 is located generating unit G1 which consists of a horizontal Kaplan turbine driving a 1 MW synchronous generator. From each building, separate tailraces discharge the water back into the Whanganui River.
The scheme has a head of 8.2 metres. Because of the limited storage capacity in the headpond and canal the scheme is essentially run-of-river.
The power station has a total output of 1.3 MW and a mean output of 7 GWh per year.
At the power station the voltage is stepped up to 11 kV for transmission.
The power station is embedded within The Lines Company network behind Transpower's Hangitaki Substation, but can also be switched within The Lines Company network to support Transpower's Whakamaru substation on a limited supply basis.
Operation.
Operation of the power station is covered by the requirements of three resource consents which expire in December 2030.
As the power station is located in an area covered in pumice, the intake to the power station required regular maintenance in its early days to remove the pumice which had become dislodged and then floats down the river to build up behind the weir and block the intake.


Anglia Components

Anglia Components is the UK's largest privately owned independent authorised distributor of electronic components trading under the name Anglia. A signatory of the ADS SC21 programme, Anglia holds AS9120, ISO9001 & ISO14001 accreditations.
History.
Anglia was founded in 1972 by Bill Ingram, who started the business from home as a sole trader. The initial operation was established to provide spare parts to the Radio and TV repair trade. As Anglia developed it moved to premises in Burdett Road, Wisbech, Cambridgeshire, UK. By 1980 Anglia had grown significantly and directed its efforts towards the electronics manufacturing industry.
The signing of numerous distribution agreements and the launch of several direct product brands throughout the 1980s resulted in Anglia holding much more extensive inventory, they moved to a much larger distribution centre and offices in Sandall Road, Wisbech, Cambridgeshire, UK during 1992, where Anglia remains today.
The late 1990s and early 2000s saw considerable expansion at Anglia, of its supplier line card and product portfolio. During this period, Anglia created specialist divisions dedicated to developing and emerging technologies and set up a logistics and distribution operation in Hong Kong.
In 2011 Steve Rawlins (CEO) reached agreement with the majority shareholder Bill Ingram to purchase the remainder of Anglia’s shares thereby securing Anglia’s position as the UK’s largest privately owned distributor. The transfer of ownership was completed in 2019 without the use of any external funding.
At the beginning of 2013 the company launched Anglia-Live, its e-commerce website, offering a comprehensive parametric search engine, live inventory, live pricing and online ordering. In more recent times, Anglia has signed numerous distribution agreements with major semiconductor suppliers significantly enhancing its product profile whilst continuing to receive multiple awards from its principle suppliers.
On Sunday 26th April 2020 Anglia ranked for the first time on the 21st annual Sunday Times Profit Track based on its financial performance over the last three years.


High-voltage shore connection

A high-voltage shore connection (HVSC) is connection used to connect ships to the main grid, shutting engine of the ship and reducing carbon emissions.
The ship can use electric power for its consumption of energy. They are mostly used in the cruise ships which dock for longer time and hence save energy.


Wind Power Production Incentive

The Wind Power Production Incentive, or WPPI, was a program of the Canadian Government that promoted the generation of electricity from wind power in Canada to reduce the amount of greenhouse gas that would otherwise enter the atmosphere from burning fossil fuels.
During the five-year field trial projects were performed to test the performance based on various weather conditions. Provision of economic incentives were guaranteed for up to 1,000 MW of new installed capacity by 2007. New installations in 2003 included the MacBride Wind Farm (75.9 MW) in Alberta, the North Cape Wind Farm Expansion (5.3 MW), and the Aeolous Wind Turbine (3 MW) in PEI, the Parc éolien du Renard (2.25 MW) in Quebec, the Cypress Hill Wind Farm Expansion (4.6 MW) in Saskatchewan, and the Ontario Place Wind turbine (0.75 MW) in Ontario. The government paid about half the excess cost of producing electricity from wind, compared to conventional sources, for the first 10 years of a project. The Canadian WPPI Program started in 2002 and ended on March 31, 2007 after a change of government. A different program partly replaced it.
A wind farm costs about the same to build per watt of nameplate capacity as a coal-fired power station of similar rating, but the economies of scale are fewer for a wind farm due to the lower quantity of power produced over the life of a station. Depending on location, wind farms may produce nearly full power output only about 28% of the time, whereas a base-loaded coal-fired station runs at full output more than 85% of the time. The WPPI provided a direct subsidy per kilowatthour of wind energy produced, from 1.2 cents down to 0.8 cents depending on the startup date of a project. Measures were taken to distribute the incentive across the country. The total estimated cost of the program was (CDN) $260 million. The program lived a short 5 year life.
Project description.
The Canadian government launched the Wind Power Production Incentive in 2002, with the intention of boosting Canada's installed wind capacity by 500% over the course of five years. The program lasted fifteen years and cost Canada 260 million dollars (170 million U.S. dollars), and it was expected to earn roughly 1.5 billion Canadian dollars (1 billion U.S. dollars) of capital investments across the country.
An internal audit in 2006 observed that capacity factors were overestimated by applicants, so less capacity was actually supplied than intended.
Project history.
In 2002, Canada upheld the Kyoto Protocol, a nationwide pledge to help maintain and reduce greenhouse gas based on the theory that society has caused global warming. Canada set goals to increase in renewable resources for energy diversification, further the development of technology in all aspects, create new jobs and increase the amount of trade internationally. Canada is supported by provincial and federal governments because of their increased development of incentive programs such as, arctic energy alliances, gas distribution and a variety of business programs. The Wind Energy Research and Development (WERD) program is the study of kinetic energy transformed into electricity. As a part of National Resources Canada, this program is Canada's main resource for technical support.
Program failures, superseding, and lasting effects.
The Wind Power Production Incentive lost its funding in 2006, five years into its planned 15-year lifespan. It was ultimately replaced the following year in part by a newer, more forward thinking program, ecoEnergy for Renewable Power. The Wind Power Production Incentive was created as an immediate response to Canada's upholding of the Kyoto Protocol. It was one of two programs formed to address the motives of the Kyoto Protocol along with the Renewable Energy Deployment Initiative (REDI), which focused on smaller-scale production and renewable heat. During the life of these programs, their shortcomings began to surface. These shortcomings were the product of government officials reacting too hastily to newly evidenced environmental concerns resulting from the burning of fossil fuels for energy.
Through further research and testing, the concept of relying solely on wind power for Canada's energy needs proved to be inefficient and impractical. The superseding program, ecoEnergy for Renewable Power, uses government funding and tax incentives to encourage the production of various renewable energy sources such as low-impact hydro, biomass, photovoltaic and geothermal energy in addition to the wind power Canada was already heavily invested in. The more diversified approach limits the risks involved with becoming too heavily dependent on a single energy source. These risks include increased cost and unexpected decrease in production of a particular energy source which could cause an energy crisis. EcoEnergy for Renewable Power is part of a larger program called the ecoACTION Clean Air Agenda, which planned to reduce Canada's greenhouse gas emissions 17% from 2005 to 2020.
The Wind Power Production Incentive program was not a complete failure, but merely a premature and under-informed attempt at a large issue. The economics of the program proved quite prolific. Government funding was rewarded with substantial increases in wind power production amounting to 924 MW of clean wind energy. Much of this blueprint created by the WPPI was carried over into the new program with updated logistics. "The ecoEnergy for Renewable Power program will provide an incentive of one cent per kilowatt hour for up to 10 years to eligible projects constructed over the next four years that generate clean electricity from renewable sources" (Brown), a 0.2 cent per kilowatt hour decrease from the initial WPPI incentive. While also being expanded to include incentives for the production of more renewable energy sources, ecoEnergy retained the long-term incentives to provide security for those who participated in the program. The Renewable Energy Deployment Initiative was similarly supplanted by ecoENERGY for Renewable Heat, which "will provide $36 million over four years to increase the adoption of clean renewable thermal technologies for water heating and space heating and cooling" (Brown).
The Wind Power Production Incentive changed the way government officials, energy production companies, and consumers think about clean energy. It jump-started the industry and laid the blueprint for future clean energy acceleration programs in Canada and across the world. Wind energy's share of Canada's total energy consumption has grown at an average rate of 40% annually. Although wind power still accounts for less than 1% of Canada's total energy consumption, the programs the WPPI laid the path for have helped renewable energy sources take on about 11.1 percent of Canada's total energy consumption.


Rotary-screw compressor

A rotary-screw compressor is a type of gas compressor, such as an air compressor, that uses a rotary-type positive-displacement mechanism. These compressors are common in industrial applications and replace more traditional piston compressors where larger volumes of compressed gas are needed, e.g. for large refrigeration cycles such as chillers, or for compressed air systems to operate air-driven tools such as jackhammers and impact wrenches. For smaller rotor sizes the inherent leakage in the rotors becomes much more significant, leading to this type of mechanism being less suitable for smaller compressors than piston compressors.
The gas compression process of a rotary screw is a continuous sweeping motion, so there is very little pulsation or surging of flow, as occurs with piston compressors. This also allows screw compressors to be significantly quieter and produce much less vibration than piston compressors, even at large sizes, and produces some benefits in efficiency.
Working.
Rotary-screw compressors use two very closely meshing helical screws, known as rotors, to compress the gas. In a dry-running rotary-screw compressor, timing gears ensure that the male and female rotors maintain precise alignment without contact which would produce rapid wear. In an oil-flooded rotary-screw compressor, lubricating oil bridges the space between the rotors, both providing a hydraulic seal and transferring mechanical energy between the rotors, allowing one rotor to be entirely driven by the other. Gas enters at the suction side and moves through the threads as the screws rotate. The meshing rotors force the gas through the compressor, and the gas exits at the end of the screws.The working area is the inter-lobe volume between the male and female rotors. It is larger at the intake end, and decreases along the length of the rotors until the exhaust port. This change in volume is the compression. The intake charge is drawn in at the end of the rotors in the large clearance between the male and female lobes. At the intake end the male lobe is much smaller than its female counterpart, but the relative sizes reverse proportions along the lengths of both rotors (the male becomes larger and the female smaller) until (tangential to the discharge port) the clearance space between each pair of lobes is much smaller. This reduction in volume causes compression of the charge before being presented to the output manifold.
The effectiveness of this mechanism is dependent on precisely fitting clearances between the helical rotors and between the rotors and the chamber for sealing of the compression cavities. However, some leakage is inevitable, and high rotational speeds must be used to minimize the ratio of leakage flow rate over effective flow rate.
In contrast to Roots blowers, modern screw compressors are made with different profiles on the two rotors: the male rotor has convex lobes which mesh with the concave cavities of the female rotor. Usually the male rotor has fewer lobes than the female rotor, so that it rotates faster. Originally, screw compressors were made with symmetrical rotor cavity profiles, but modern versions use asymmetrical rotors, with the exact rotor designs being the subject of patents.
Size.
The capacities of rotary-screw compressors are typically rated in horsepower (HP), Standard Cubic Feet per Minute (SCFM)* and pounds per square inch (PSI.) For units in the 5 through 30 HP range the physical size of these units are comparable to a typical two-stage compressor. As horsepower increases, there is a substantial economy of scale in favor of the rotary-screw compressors. As an example, a 250 HP compound compressor is a large piece of equipment that generally requires a special foundation, building accommodations and highly trained riggers to place the equipment. On the other hand, a 250 HP rotary-screw compressor can be placed on an ordinary shop floor using a standard forklift. Within industry, a 250 HP rotary-screw compressor is generally considered to be a compact piece of equipment.
Rotary-screw compressors are commonly available in the 5 through 500 HP range and can produce air flows in excess of 2500 SCFM. While there are high pressure rotary-screw compressors, within the compressed air community, the upper pressure limit is generally around 125 PSI.
Rotary-screw compressors tend to be smooth running with limited vibration, thus not requiring a specialized foundation or mounting system. Normally, rotary-screw compressors are mounted using standard rubber isolation mounts designed to absorb high-frequency vibrations. This is especially true in rotary-screw compressors that operate at high rotational speeds.
History.
The screw compressor was first patented in 1878 by Heinrich Krigar in Germany, however the patent expired without a working machine being built.
The modern helical lobe screw compressor was developed in Sweden by Alf Lysholm who was the chief engineer at Ljungstroms Angturbin. Lysholm developed the screw compressor while looking for a way to overcome compressor surge in gas turbines. Lysholm first considered a roots type blower but found this was unable to generate a high enough pressure ratio. In 1935, Ljungstroms patented a helical lobe screw compressor which was then widely licensed to other manufacturers. Ljungstroms Angturbin AB was renamed Svenska Rotor Maskiner (SRM) in 1951.
In 1952, the first Holroyd cutting machine was used, by the Scottish engineering company Howden, to produce helical lobe compressor rotors greatly reducing both cost and manufacturing time.
In 1954, Howden and SRM jointly developed the first oil flooded screw compressor. Flooding provided both cooling, which allowed higher pressure ratios, and the elimination of timing gears. The first commercially available flooded screw air compressor was introduced in 1957 by Atlas Copco.
Slot valves were developed by SRM in the 1950s, allowing for improvements in capacity control which had been a limiting factor for screw compressor application.
Asymmetric rotors were first patented by SRM and subsequently introduced commercially by Sullair in 1969. The introduction of asymmetric rotors improved sealing, further increasing the types efficiency.
Applications.
Rotary-screw compressors are generally used to supply compressed air for larger industrial applications. They are best applied in applications that have a continuous air demand such as food packaging plants and automated manufacturing systems although a large enough number of intermittent demands, along with some storage, will also present a suitably continuous load. In addition to fixed units, rotary-screw compressors are commonly mounted on tow-behind trailers and powered with small diesel engines. These portable compression systems are typically referred to as construction compressors. Construction compressors are used to provide compressed air to jack hammers, riveting tools, pneumatic pumps, sand blasting operations and industrial paint systems. They are commonly seen at construction sites and on duty with road repair crews throughout the world.
Oil-free.
In an oil-free compressor, the air is compressed entirely through the action of the screws, without the assistance of an oil seal. They usually have lower maximal discharge pressure capability as a result. However, multi-stage oil-free compressors, where the air is compressed by several sets of screws, can achieve pressures of over and output volume of over .
Oil-free compressors are used in applications where entrained oil carry-over is not acceptable, such as medical research and semiconductor manufacturing. However, this does not preclude the need for filtration, as hydrocarbons and other contaminants ingested from the ambient air must also be removed prior to the point of use. Consequently, air treatment identical to that used for an oil-flooded screw compressor is frequently required to ensure quality compressed air.
In small piston compressors carpenters homeowners sometimes use "oil free" compressors in which oil free is a reference to not using oil but Teflon type of coatings permanently adhered to wear surfaces.
Oil-injected.
In an oil-injected rotary-screw compressor, oil is injected into the compression cavities to aid sealing and provide cooling for the gas charge. The oil is separated from the discharge stream, cooled, filtered and recycled. The oil captures non-polar particulates from the incoming air, effectively reducing the particle loading of compressed-air particulate filtration. It is usual for some entrained compressor oil to carry into the compressed-gas stream downstream of the compressor. In many applications, this is rectified by coalescer/filter vessels. Refrigerated compressed air dryers with internal cold coalescing filters are rated to remove more oil and water than coalescing filters that are downstream of air dryers, because after the air is cooled and the moisture is removed, the cold air is used to pre-cool the hot entering air, which warms the exiting air. In other applications, this is rectified by the use of receiver tanks that reduce the local velocity of compressed air, allowing oil to condense, drop out of the air stream, and to be removed from the compressed-air system by condensate-management equipment.
Oil flooded screw compressors are used in a wide variety of applications including air compression, gas refrigeration, hydrocarbon processing and power utilization from low-grade heat sources. Sizes range from small workshop air compressors to heavy industrial compressors with output pressures as high as . New oil flooded screw air compressors release <5 mg/m3 of oil carryover.
Lubricants, Polyalkylene glycol (PAG), Polyalphaolefin (PAO), Mineral Oils.
PAG oil is polyalkylene glycol which is also called polyglycol. PAG oil burns off cleanly, leaving no residue, and have been used as a carrier oil for solid lubricants for high-temperature chain lubrication. Some versions are food grade and biodegradable. PAG lubricants are used by the two largest U.S. air compressor OEMs in rotary screw air compressors. PAG oil-injected compressors are not used to spray paint, because PAG oil dissolve paints. Reaction-hardening two-component epoxy resin paints are resistant to PAG oil.
Polyglycols are not compatible with mineral oil based greases. A mixture of polyglycols with mineral oils results is a gelatinous, gooey mess.
Mineral oil (but not polyalkylene glycol oil) lubricated compressors are recommended for mineral oil greases coated seals, such as pneumatic high speed 4-way valves and air cylinders that operate without mineral oiler lubricators. One manufacturer has rated its pneumatic high speed 4-way valves with a life of 50 million cycles, if not exposed to polyglycol oils.
Polyalphaolefin PAO oil is compatible with mineral oil greases.
Conical screw compressor.
The relatively recently developed conical screw compressor is in effect a conical spiral extension of a gerotor. It does not have the inherent "blow-hole" leakage path which, in well designed screw compressors, is responsible for significant leakage through the assembly. This allows much smaller rotors to have practical efficiency since at smaller sizes the leakage area does not become as large a portion of the pumping area as in straight screw compressors. In conjunction with the decreasing diameter of the cone shaped rotor this also allows much higher compression ratios in a single stage with lower output pulsation.
Control schemes.
Among rotary-screw compressors, there are multiple control schemes, each with differing advantages and disadvantages.
Start/stop.
In a start/stop control scheme, compressor controls actuate relays to apply and remove power to the motor according to compressed air needs. Significant storage is required in most usage cases if the load is intermittent or is poorly matched to the compressor, the storage required will often be larger than the compressor itself.
Load/unload.
In a load/unload control scheme, the compressor remains continuously powered. However, when the demand for compressed air is satisfied or reduced, instead of disconnecting power to the compressor, a device known as a slide valve is activated. This device uncovers part of the rotor and proportionately reduces capacity of the machine down to typically 25% of the compressor's capability, thereby "unloading" the compressor. This reduces the number of start/stop cycles for electric motors over a start/stop control scheme in electrically-driven compressors, improving equipment service life with a minimal change in operating cost. This scheme is utilised by nearly all industrial air-compressor manufacturers. When a load/unload control scheme is combined with a timer to stop the compressor after a predetermined period of continuously unloaded operation, it is known as a dual-control or auto-dual scheme. This control scheme still requires storage since there are only two production rates available to match consumption, although significantly less than a start/stop scheme.
Modulation.
Instead of starting and stopping the compressor, a slide valve as described above continuously modulates capacity to the demand rather than being controlled in steps. While this yields a consistent discharge pressure over a wide range of demand, overall power consumption may be higher than with a load/unload scheme, resulting in approximately 70% of full-load power consumption when the compressor is at a zero-load condition.
Due to the limited adjustment in compressor power consumption relative to compressed-air output capacity, modulation is a generally inefficient method of control when compared to variable-speed drives. However, for applications where it is not readily possible to frequently cease and resume operation of the compressor (such as when a compressor is driven by an internal-combustion engine and operated without the presence of a compressed-air receiver), modulation is suitable. The continuously variable production rate also eliminates the need for significant storage if the load never exceeds the compressor capacity.
Variable displacement.
Utilized by compressor companies Quincy Compressor, Kobelco, Gardner Denver, and Sullair, variable displacement alters the percentage of the screw compressor rotors working to compress air by allowing air flow to bypass portions of the screws. While this does reduce power consumption when compared to a modulation control scheme, a load/unload system can be more effective with large amounts of storage (10 gallons per CFM). If a large amount of storage is not practical, a variable-displacement system can be very effective, especially at greater than 70% of full load.
One way that variable displacement may be accomplished is by using multiple lifting valves on the suction side of the compressor, each plumbed to a corresponding location on the discharge. In automotive superchargers, this is analogous to the operation of a bypass valve.
Variable speed.
While an air compressor powered by a variable-speed drive can offer the lowest operating-energy cost without any appreciable reduction in service life over a properly maintained load/unload compressor, the variable-frequency power inverter of a variable-speed drive typically adds significant cost to the design of such a compressor, reducing its economic benefits over a properly sized load/unload compressor if air demand is constant. However, a variable-speed drive provides for a nearly linear relationship between compressor power consumption and free air delivery allowing the most efficient operation over a very wide range of air demand. The compressor will still have to enter start/stop mode for very low demand as efficiency still drops off rapidly at low production rates due to rotor leakage. In harsh environments (hot, humid or dusty) the electronics of variable-speed drives may have to be protected to retain expected service life.
Superchargers.
The twin-screw type supercharger is a positive displacement type device that operates by pushing air through a pair of meshing close-tolerance screws similar to a set of worm gears. Twin-screw superchargers are also known as Lysholm superchargers (or compressors) after their inventor, Alf Lysholm.
Each rotor is radially symmetrical, but laterally asymmetric. By comparison, conventional "Roots" type blowers have either identical rotors (with straight rotors) or mirror-image rotors (with helixed rotors).
The Whipple-manufactured male rotor has three lobes, the female five lobes. The Kenne-Bell male rotor has four lobes, the female six lobes. Females in some earlier designs had four. By comparison, Roots blowers always have the same number of lobes on both rotors, typically 2, 3 or 4.
Comparative advantages.
The rotary screw compressor has low leakage levels and low parasitic losses vs. Roots type. The supercharger is typically driven directly from the engine's crankshaft via a belt or gear drive. Unlike the Roots type supercharger, the twin-screw exhibits internal compression which is the ability of the device to compress air within the housing as it is moved through the device instead of relying upon resistance to flow downstream of the discharge to establish an increase of pressure.
The requirement of high-precision computer-controlled manufacturing techniques makes the screw type supercharger a more expensive alternative to other forms of available forced induction. With later technology, manufacturing cost has been lowered while performance increased.
All supercharger types benefit from the use of an intercooler to reduce heat produced during pumping and compression.
A clear example of the technology applied by the twin-screw in companies like Ford, Mazda, Mercedes and Mercury Marine can also demonstrate the effectiveness of the twin screw. While some centrifugal superchargers are consistent and reliable, they typically do not produce full boost until near peak engine rpm, while positive displacement superchargers such as Roots type superchargers and twin-screw types offer more immediate boost. In addition to this, twin-screw superchargers can keep the reasonable boost to higher rpm better than other positive displacement supercharges.
Related terms.
The term "blower" is commonly used to define a device placed on engines with a functional need for additional airflow, such as a 2-stroke Diesel engine, where positive intake pressure is needed to "scavenge", or clear spent exhaust gasses from the cylinder and force a fresh intake charge into the cylinder before the compression stroke. The term "blower" is applied to rotary screw, roots-type, and centrifugal compressors when utilized as part of an automotive forced induction system.


Solar power in New Zealand

Solar power in New Zealand is on the rise, but operates in an entirely free market with no form of subsidies or intervention from the New Zealand Government. As of the end of March 2021, New Zealand has 151 MW of grid-connected photovoltaic (PV) solar power installed, of which 29 MW were installed in the preceding 12 months.
Although there are no subsidies, the declining costs of photovoltaics has caused a large increase in demand over the last few years. In 2009, the average turnkey price for a standard PV system of three kilowatts (kW) was about NZ$40,000; by 2019 this had dropped to approx. NZ$8,500.
Adoption.
As of then end of March 2021, 31,589 solar power systems have been installed in New Zealand. For new installations, the average residential system size was 4.6 kW and the average commercial system was 17.8 kW.
The largest solar power system on a school in New Zealand was officially opened in a ceremony in February 2019 at Kaitaia College. Kelvin Davis, unveiled a plaque to acknowledge the installation of the 368 solar panel project which is spread across the rooftop of multiple buildings on the school campus.
By January 2014, solar photovoltaic systems had been installed in 50 schools through the Schoolgen program, a program developed by Genesis Energy to educate students about renewable energy, particularly solar energy. Each school has been given a 2 kW capacity PV system, with a total distributed installed capacity of 100 kilowatts-peak (kWp). Since February 2007, a total of 513 megawatt-hours (MWh) of electrical energy have been recorded.
As of 2021, New Zealand's largest solar power plant is in the Wairau Valley in Marlborough with a total capacity of 2.2 MVA, 1.4 MW is connected as at March 2021.
In July 2019 Refining NZ announced plans for a 26 MW solar farm at the Marsden Point Oil Refinery. In February 2020 Genesis Energy Limited announced plans for a 300 MW facility in the Waikato. In February 2021 Far North Solar Farm applied for resource consent for a 16 MW farm on the Aupouri Peninsula in Northland. In May 2021 Lodestone Energy announced plans for five solar farms in the upper North Island, capable of generating 400 GWh annually.
Cost-effectiveness.
Buy-back rates for solar power exported to the grid range from 7 cents to 12 cents. Cost-effectiveness of a residential solar power occurs when system owners aim to use more of their solar power than what they export, by means of timed appliances, turning on appliances when the sun is out, energy management systems and battery storage. Commercial buildings that use power during the day can get a high return on their investment.
A 2015 study found that PV was more economical than grid supply if all the PV electricity was used on site and none was exported to the grid. For residential and commercial installations, improving energy efficiency is a lower cost option than PV.


Mai-Liao Power Corporation

The Mai-Liao Power Corporation (MPC; ) is an independent power producer company in Taiwan. The total electricity installed capacity of the company is 1,800 MW and is produced using thermal power. The company is the subsidiary of Formosa Plastics Group.
History.
MPC was founded by Formosa Plastics Corp., Nan-Ta Plastics Corp., Formosa Chemical-Fiber Corp. and Formosa Petrochemical Corp. on 12 April 1996 with an initial capital of NT$ 4 billion.


Wairere Power Station

The Wairere Power Station is a hydroelectric power facility in the Waikato region in New Zealand which makes use of water from the Mokau River. Water is drawn from behind a dam above the Wairere Falls, which diverts the water through two penstocks to the Wairere Power Station, before being discharged back into the Mokau River. The station was commissioned in 1925 with the first generating unit. Three more generating units were added between 1938 and 1981 before a major refurbishment resulted in three of the units being replaced by a single generating unit in 2013-2014.
History.
Development.
After being hired in 1903 by the Public Works Minister William Hall-Jones to investigate the hydro-electric potential of New Zealand, American electrical engineer L. M. Hancock identified 41 locations in 1904. Wairere Falls was ranked number 27. Lawrence Birks had become the chief electrical engineer of the Public Works Department (PWD) in 1919 was familiar with the falls and was able to convince a number of residents of Aria and Piopio that the Mokau River and Wairere Falls should be developed.
As a result, in November 1919 a group of citizens in Aria and Piopio formed a committee to undertake the work. They engaged experienced engineer Henry "Harry" Richmond Climie (1884-1961) of consulting engineers H.W. Clime & Son to undertake an investigation which he reported on at two meetings that were held recently at Piopio and Aria respectively. Climie estimated that a turbine capacity of 125 hp would be ample to supply present requirements within a radius of the proposed power station and that double this amount would meet the demand for many years, provided no large industry such as a freezing or lime works required a supply. He estimated that the location had a potential total capacity of 1,500 hp
As work progressed the committee were invited by an offer in August 1922 to amalgamate their efforts with the new created Te Kuiti provisional power board. Wishing to maintain their independence and aware that they were remote from Te Kuiti they decided to continue on their own. Despite the withdraw of some of the potential customers who had initially expressed their support the Wairere Electric Power Board was established in January 1923.
The new board's first official meeting was in Piopio in May 1923, which Harry Climie attended. He was subsequently engaged to design the power station and the associated distribution system.
Climie submitted his design within several weeks. Following acceptance, the board began the process of obtaining the required water, power and distribution licences, as well as polling the ratepayers in their area to raise a loan to pay for the works. Climie had estimated that the construction of the power station and associated distribution network would cost £38,500 plus an additional amount to pay for the first three years of operation until sufficient customers could be connected. Unfortunately no one was prepared to provide the money. With the assistance of their local MP the board was able to obtain enough funds to commence construction of the power station. It was several more months before a loan for the full amount was able to be obtained.
Construction.
Construction of the power station was undertaken by a workforce under the control of the board’s engineer, F. Harvey.
Commissioning.
The power station commenced commercial generation in December 1925, with 80 customers receiving a supply in Aria and Piopio and surrounding districts by January 1926.
The new power station was officially opened on 27 May 1926 by Prime Minister Gordon Coates with a single generating unit (G1) which had a Boving & Co horizontal Francis turbine driving a ASEA generator which gave an original installed capacity of 480 kW, which was generated at 6.6 kV. The generating unit was supplied with water via a concrete and steel diameter, long penstock with a capacity of up to 3.1 cumecs.
By 1936 the Wairere Power Board had an annual revenue of £5,000, with the power station supplying about 350 consumers via approximately 120 miles of transmission line.
On 9 January 1936 while in the process of assisting in installing a new and more efficient stator on the generating unit Francis Rosengrave Harvey, an engineer employed by the Wairere Power Board was electrocuted and killed at the power station when a ruler with which he was taking measurements, came into contact with live equipment.
Installation of G3.
In September 1937 the board gave approval for its consulting engineer Lloyd Mandeno to purchase a second machine.
In 1938 the powerhouse was extended which allowed an additional 240 kW machine (G2) with a Boving & Co horizontal Francis turbine driving a ASEA generator to be installed which increased the total installed capacity to 624 kW.
This generating unit was supplied via a dual end concrete diameter, long penstock with a capacity of up to 7.1 cumecs to G2.
Eels were initially a problem at the power station, which was solved in 1939 by suspending an electrified rod in the surge chamber.
Following a period of dry weather which reduced the station's output and faced with increasing demand the board installed a second hand 200 kW diesel generator at the power station to supplement the station's output.
The commissioning of the second generating unit (G2) allowed essential loads to be supplied while G1 to be taken out of service and overhauled after having been in practically continuous operation since its installation. Taken out of service on the evening of 20 June 1939, G1 was dismantled overnight, transported up the hill from the power-house, from where all parts requiring repair were transported to Hamilton, where for the next two days it was refurbished and by the midnight on the following Tuesday last the machinery was returned to the power station and returned to service in time to carry the evening load on Thursday. While this repair was being carried out opportunity was taken install a new and more efficient stainless-steel runner, a rubber-lined submerged bearing was installed in place of the old oil circulation bearing, and improvements made to the lubrication system. These improvements lead to a 12 per cent, increase in output.
To impound more water a weir was built across the head of the falls and flashboards installed to raise the river level. The tailrace was deepened in order to utilise all of the available head, while the riverbed downstream from the power station was blasted to remove the rock bars which have impeded the flow of the stream below the station.
Associated with the expansion of the power station the capacity of the transmission line which conveyed power from the power station to Piopio was doubled to cope with the heavy increase in consumption in this part of the Board's district.
Following the death of the power station's operator in October 1942 the offer of his widow Isobel Gibbs to undertake his duties as a contribution to the war effort was accepted at a salary of £4 10 shillings, which was 25% less than her late husbands. She worked seven days a week from 6 am to 10 pm.
Following the end of the Second World War the board hired Lloyd Mandeno to about improving the power station and its connection to the system. He recommended that the board build a tie-line to connect the power station's output to the State Hydro-Electric Department's (SHD) system which would allow the board to supply its customers when the station was unable to supply all of its load as well as allowing them during periods of low load to sell any surplus generation from Wairere to the SHD. A condition of the connection to the SHD system was that the power station had to be manned 24 hours a day, which led to a second operator joining Mrs Gibbs at the power station. Upon her resignation in 1952 the board paid her a gift of £20.
Installation of G3.
In August 1952 a major upgrade of the power station was completed which included the installation of an additional generating unit (G3) which had a horizontal Francis turbine driving a 825 kW Lancashire Dynamo & Crypto generator.
Following discussions that had been going on intermittently since the early 1930s the Wairere Electric Power Board merged with the Waitomo Electric Power Board in 1978 and took its name.
Installation of G4.
Between 1978 and 1981 the Wairere Power Station was upgraded at a cost of NZ$2 million and a new machine (G4) was added in 1981 which improved efficiency and maximized the use of the river flow.
In response to the introduction of the Energy Companies Act in 1992, the Waitomo Electric Power Board changed its financial structure to become Waitomo Energy Services Ltd.
In 1998 the New Zealand Government passed the Electricity Industry Reform Act which was intended to change the structure of the electricity industry to encourage competition. This Act required the operational separation of lines and generation business activities by 1 July 1999 and separation of the ownership by 1 January 2004. To lead after a period of consultation to King Country Energy on 1 April 1999 purchasing the generation and retail assets of Waitomo Energy Services while the later company purchased the network assets of King Country Energy and changed its name to "The Lines Company". As a result in 1999 Wairere became owned by King Country Energy.
In 2005 upstream and downstream fish passages were commissioned with a monitoring programme which includes maintaining video footage. During the summer period of 2009 it was estimated that 1000 eels migrated downstream through the fish passage while approximately of juvenile eels (elvers) had moved upstream.
Installation of a tipping gate which would minimize upstream impacts in low to medium flood events was completed in 2006.
In 2009 G4 was overhauled and fitted with replacement runner blades.
Installation of G5.
In 2010 the company reviewed the operation of Wairere and identified the option of either overhauling the three old units or install a single new one. At the time the station was generating a combined mean output of 18 GWh a year. The company opted for the latter and in December 2013 decommissioned units 1, 2 and 3 and replaced them with a single new generating unit, G5. The commissioning of the new generating unit in June 2014, lead to a five per cent improvement in efficiency compared to what the older three units produced altogether.
As well as the installation of a new penstock, draft tube, main inlet valve, turbine, and generator, two of the existing turbines and associated draft tubes were removed. At the same time the powerhouse was seismically strengthened and the existing tailrace lowered by .
In 2015 Trustpower became a majority shareholder of King Country Energy, which lead in 2017 to Trustpower taking over operation of all of KCE’s power stations following the signing of an operation and maintenance contract with KCE.
Design.
Water is impounded by a high concrete dam with a spillway flap gate, that can discharge up to 110 cumecs in normal conditions and up to 320 cumecs in a flood.
There are two sets of intakes both fitted with an automatic screen cleaner and hydraulic gate.
The original intake which supplied G1 is now decommissioned.
From each intake a single penstock transports the water to respectively the powerhouse, which was built in the late 1980s to house machine G4 and to a second powerhouse containing machine G5 which was commissioned in 2014. The penstock that supplies G4 has a capacity of 17.55 cumecs, is of concrete construction, has a diameter of and is in length.
Generating unit G4 which was installed in 1989 consists of a Kaplan turbine driving a Parsons Peebles 3 MW generator. Generating unit G5 which was installed in 2014 consists of a Turab 1.12 m dia horizontal Francis turbine driving a 1.2 MW generator.
The power station is embedded within The Lines Company network behind Transpower's Hangitaki Substation, but can also be switched within The Lines Company network to support Transpower's Whakamaru substation on a limited supply basis.
Operation.
Operation of the power station is covered by the requirements of three resource consents which expire in December 2032.


KeySpan

KeySpan Corporation, now part of National Grid USA, was the fifth largest distributor of natural gas in the United States. KeySpan was formed in 1998 as a result of the merger of Brooklyn Union Gas "Company" (founded 1895 by merging several smaller companies) and Long Island Lighting Company (LILCO), and briefly operated under the name MarketSpan following the merger. On November 8, 2000, KeySpan acquired Eastern Enterprises, Eastern's natural gas distribution subsidiaries including Boston Gas Company, Colonial Gas Company and Essex Gas Company; Eastern's unregulated businesses including ServicEdge Partners, the largest unregulated provider of residential HVAC equipment installation and services in Massachusetts; and EnergyNorth Natural Gas in New Hampshire. It also was the operator of the Long Island Power Authority's electrical grid, which had previously been part of LILCO before LIPA took it over in 1998. KeySpan had its headquarters in Brooklyn, New York, USA and employed 9,700 people.
In February 2006, National Grid USA, a wholly owned subsidiary of National Grid plc of the United Kingdom, announced that it had agreed to buy KeySpan for $7.3 billion (£4.1 billion) in cash, the deal being subject to regulatory approval and endorsement by the shareholders of the two companies. In 2007 National Grid plc announced the acquisition of KeySpan Corporation.
KeySpan received a 100% rating on the Corporate Equality Index released by the Human Rights Campaign starting in 2004, the third year of the report.
Brooklyn Union Gas.
The Brooklyn Union Gas "Company" was originally established in 1825 as the "Brooklyn Gas Light Company", changing its name after a series of mergers in 1895. Rapid growth in the early 1900s prompted the company to establish a new headquarters at 180 Remsen Street. Noted Brooklyn architect Frank Freeman was commissioned to design the new headquarters, which was built in 1914. In 1962, a new six-story headquarters was built at 200 Montague Street.
At some point it had 3,651 Employees and nearly $1 billion in sales.


Synergy North

Synergy North Corporation is a municipally-owned local power distribution company which services the cities of Thunder Bay and Kenora in Ontario, Canada. It was formed on January 1, 2019 through the merger of Kenora Hydro and Thunder Bay Hydro.
The company is headquartered in Thunder Bay and governed by a 16-member board of directors, 8 members appointed by the Thunder Bay City Council and 8 appointed by Kenora City Council.
Thunder Bay Hydro.
Thunder Bay Hydro was formed in 1970 when Fort William Hydro and the Port Arthur Public Utilities Commission were merged coinciding with the amalgamation of towns Fort William and Port Arthur.


Wind power in India

Wind power generation capacity in India has significantly increased in recent years. As of 28 February 2021, the total installed wind power capacity was 38.789 GW, the fourth largest installed wind power capacity in the world. Wind power capacity is mainly spread across the Southern, Western and Northern regions.
Wind power costs in India are decreasing rapidly. The levelised tariff of wind power reached a record low of per kWh (without any direct or indirect subsidies) during auctions for wind projects in December 2017. However, the levelised tariff increased to per kWh in March 2021. In December 2017, union government announced the applicable guidelines for tariff-based wind power auctions to bring more clarity and minimise the risk to the developers.
Installed capacity.
The table below shows India's year on year installed wind power, annual wind power generation and annual growth in wind power generation since 2006.
History.
Development of wind power in India began in December 1952, when Maneklal Sankalchand Thacker, a distinguished power engineer, initiated a project with the Indian Council of Scientific and Industrial Research (CSIR) to explore the possibilities of harnessing wind power in the country. The CSIR established a Wind Power Sub-Committee under P. Nilakantan, which was assigned the task of investigating the available resources that could be practically utilized, along with researching the economic possibilities of wind energy. With assistance from the Indian Meteorological Department, the Sub-Committee extensively reviewed available data on surface winds in India and their velocity duration, and began detailed surveys of promising sites for harnessing the optimum amount of wind energy; it also successfully developed and tested large wood-and-bamboo windmills.
In September 1954, a Symposium on Solar Energy and Wind Power organised by the CSIR and UNESCO was held in New Delhi; among the attendees was E. W. Golding, a British power engineer and authority on wind energy generation. Convinced of the potential of wind power in India, he recommended continued and extensive wind velocity surveys in different regions of India, the full-time assignment of staff to experimental wind power studies, the establishment of a dedicated research laboratory and development of small to medium-sized wind-powered electrical generators. Golding's recommendations were adopted by the CSIR in 1957. By this time, regions of Saurashtra and around Coimbatore had been identified as promising sites for generating electricity from wind power, and the Wind Power Sub-Committee had begun to erect 20 wind velocity survey stations across India, in addition to testing its indigenously designed windmills and obtaining a 6 kW. Allgaier wind turbine, which was presented to India by the West German government; experiments at Porbandar with the latter had commenced by 1961. The Indian government also considered a proposal to erect over 20,000 small to medium-sized wind-powered electrical generators in rural districts, to be used for powering water pumps and supplying electricity for remotely situated structures such as lighthouses.
In 1960, the CSIR established a Wind Power Division as part of the new National Aeronautical Laboratory (NAL) in Bangalore, which was founded that year. From the 1960s into the 1980s, the NAL and other groups continued to carry out wind velocity surveys and develop improved estimates of India's wind energy capacity. Large-scale development of wind power began in 1985 with the first wind project in Veraval, Gujarat, in the form of a 40-kW Dutch machine (make Polenko) connected to the grid. The project, an initiative of late Dr. K S Rao, the then Director of GEDA (Gujarat Energy Development Agency), was a joint venture between GEDA and J K Synthetics Ltd. Though the performance of this machine was quite poor, it established the technical viability of operating wind turbines in the grid-connected mode in India. Subsequently, the Government of India planned several demonstration wind farms in the coastal regions of the country and simultaneously launched a massive programme to identify sites suitable for wind projects. In 1986, demonstration wind farms were set up in the coastal areas of Maharashtra (Ratnagiri), Gujarat (Okha) and Tamil Nadu (Tirunelveli) with 55 kW Vestas wind turbines. These demonstration projects were supported by the Ministry of New and Renewable Energy (MNRE). The demonstration projects set up in 1985-86 established beyond doubt, both the technical and economic viability of the wind energy projects, while the wind-mapping programme resulted in the identification of many sites suitable for wind power projects (C-WET 2001; Mani 1990, 1992, 1994; Mani and Mooley 1983).
The potential for wind farms in the country was first assessed in 2011 to be more than 2,000 GW by Prof. Jami Hossain of TERI University, New Delhi.
This was subsequently re-validated by Lawrence Berkley National Laboratory, US (LBNL) in an independent study in 2012.
As a result, the MNRE set up a committee to reassess the potential and through the National Institute of Wind Energy (NIWE, previously C-WET) has announced a revised estimation of the potential wind resource in India from 49,130 MW to 302,000 MW assessed at 100 m hub height. Wind turbines are now being set up at even 120 m hub height and the wind resource at higher hub heights of around 120 m or more that are prevailing is possibly even more.
In 2015, the MNRE set the target for Wind Power generation capacity by the year 2022 at 60,000 MW.
East and North east regions have no grid connected wind power plant as of December 2017.
No offshore wind farm is under implementation as of December 2017.
However, an Offshore Wind Policy was announced in 2015 and presently weather stations and LIDARs are being set up by NIWE at some locations.
The first offshore wind farm is planned near Dhanushkodi in Tamil Nadu.
Electricity generation.
Wind power accounts for nearly 10% of India's total installed power generation capacity and generated 62.03 TWh in the fiscal year 2018–19, which is nearly 4% of total electricity generation. The capacity utilisation factor is nearly 19.33% in the fiscal year 2018-19 (16% in 2017–18, 19.62% in 2016-17 and 14% in 2015-16). 70% of annual wind generation is during the five months duration from May to September coinciding with Southwest monsoon duration.
In India, solar power is complementary to wind power as it is generated mostly during the non-monsoon period in daytime.
Wind power by state.
There is a growing number of wind energy installations in states across India.
Tamil Nadu.
Tamil Nadu's wind power capacity is around 29% of India's total.
The Government of Tamil Nadu realized the importance and need for renewable energy, and set up a separate Agency, as registered society, called the Tamil Nadu Energy Development Agency (TEDA) as early as 1985.
Tamil Nadu is a leader in Wind Power in India.
In Muppandal windfarm the total capacity is 1500 MW, the largest wind power plant in India. The total wind installed capacity in Tamil Nadu is 7633 MW.
During the fiscal year 2014–15, the electricity generation is 9.521 GWh, with about a 15% capacity utilization factor.
Maharashtra.
Maharashtra is one of the prominent states that installed wind power projects second to Tamil Nadu in India. As of end of March 2016, installed wind power capacity is 4655.25 MW . As of now there are 50 developers registered with state nodal agency "Maharashtra energy Development Agency" for development of wind power projects. All the major manufacturers of wind turbines including ReNew Power, Suzlon, Vestas, Gamesa, Regen, Leitner Shriram have presence in Maharashtra.
Gujarat.
Gujarat government's focus on tapping renewable energy has led to sharp rise in the wind power capacity in the last few years. According to official data, wind power generations capacity in the state has increased a staggering ten times in last six years. Gujarat have 16% of total capacity of country. ONGC Ltd. has installed a 51MW wind energy farm at Bhuj in Gujarat. Renewable energy projects worth a massive Rs 1 lakh crore of memorandums of understanding (MoUs) in the Vibrant Gujarat Summit in 2017.
Rajasthan.
4298 MW wind power plant has been installed in Rajasthan.
Madhya Pradesh.
In consideration of unique concept, Govt. of Madhya Pradesh has sanctioned another 15 MW project to Madhya Pradesh Windfarms Ltd. MPWL, Bhopal at Nagda Hills near Dewas under consultation from Consolidated Energy Consultants Ltd. CECL Bhopal. All the 25 WEGs have been commissioned on 31.03.2008 and under successful operation.
Kerala.
55 MW production of wind power is installed in Kerala. The first wind farm of the state was set up in 1997 at Kanjikode in Palakkad district.
The agency has identified 16 sites for setting up wind farms through private developers.
Odisha.
Odisha a coastal state has higher potential for wind energy. Current installation capacity stands at 2.0 MW. Odisha has a windpower potential of 1700MW. The Govt of Odisha is actively pursuing to boost Wind power generation in the state. however it has not progressed like other states primarily because Odisha having a huge coal reserve and number of existing and upcoming thermal power plants, is a power surplus state.
West Bengal.
The total installation in West Bengal is 2.10 MW till Dec 2009 at Fraserganj, Distt- South 24 Paraganas. More 0.5 MW (approx) at Ganga Sagar, Kakdwip, Distt - South 24 Paraganas. Both the project owned by West Bengal Renewable Energy Development Agency (WBREDA), Govt. of WB and project was executed on turnkey basis by Utility Powertech Limited (UPL).
Ladakh.
The union territory of Ladakh and its Kargil district are potential wind energy areas, which are yet to be exploited. Wind Speeds are higher during the winter months in Ladakh, which is complementary to the hydro power available during the summer months from the snow melt water. Being a Himalayan region located at higher altitude, the heating energy requirements are high which can be met by the renewable energy resources such as wind, solar and hydro power. The union territory is yet to open its account in grid connected wind power installations.
Projects.
India's largest wind power production facilities (10MW and greater)
Offshore wind power plants.
India has an offshore wind energy potential of around 70 GW in parts along the coast of Gujarat and Tamil Nadu.
India started planning in 2010 to enter into offshore wind power, and a 100 MW demonstration plant located off the Gujarat coast began planning in 2014. In 2013, a consortium (instead of group of organizations), led by Global Wind Energy Council (GWEC) started project FOWIND (Facilitating Offshore Wind in India) to identify potential zones for development of off-shore wind power in India and to stimulate R & D activities in this area. The other consortium partners include the Centre for Study of Science, Technology and Policy (CSTEP), DNV GL, the Gujarat Power Corporation Limited (GPCL) and the World Institute of Sustainable Energy (WISE). The consortium was awarded the grant of €4.0 million by the delegation of the European Union to India in 2013 besides co-funding support from GPCL. The project action will be implemented from December 2013 to March 2018.
The project focuses on the States of Gujarat and Tamil Nadu for identification of potential zones for development through techno-commercial analysis and preliminary resource assessment. It will also establish a platform for structural collaboration and knowledge sharing between stakeholders from European Union and India, on offshore wind technology, policy, regulation, industry and human resource development. FOWIND activities will also help facilitate a platform to stimulate offshore wind related R&D activities in the country. The consortium published initial pre-feasibility assessment reports for offshore wind farm development in Gujarat and Tamil Nadu on 16 June 2015.
In September 2015, the India's cabinet has approved the National Offshore Wind Energy Policy. With this, the Ministry of New & Renewable Energy (MNRE) has been authorized as the Nodal Ministry for use of offshore areas within the Exclusive Economic Zone (EEZ)
India seems pacing up rapidly towards offshore wind energy development as the Nodal Ministry (MNRE) & Nodal Agency (NIWE) calls with the Expression of Interest (EoI) inviting the bidders for development of first 1000MW commercial scale offshore windfarm in India, near the coast of Gujarat. The EoI published on 16 Apr 2018, specifies the proposed area identified under the FOWIND & FOWPI study funded by European Union. The proposed location of the offshore windfarm could be 23–40 km off the coast from the Pipavav port, Gulf of Khambhat. The proposed area covers about 400sq km. The wind measurements & other data collection are under progress under the supervision of NIWE.