ELECTRIC POWER SECTOR IN INDONESIA

November 11, 2011

ANASIA  SILVIATI U.S. Commercial Service CS JAKARTA;

Summary
Indonesia has been experiencing a power crisis since 2004. The massive power blackout on August 18, 2005 was evidence of the lack of infrastructure in the power sector and stateowned electricity company PT PLN’s poor peak load management, inadequate maintenance system, and overloaded transmission and distribution lines. With an average growth rate of 8.3% per year, the electricity demand will increase from 97.9 terawatt hours (TWh) in 2004
to 145.7 TWh in 2009. The electrification ratio is expected increase to reach 67.9% and new customers will increase by 10 million in the next five years. The government has projected that the financial requirement for power development during 2004-2013 is US$ 31.4 billion.

The total market value for electrical power equipment in Indonesia was $ 506 million in 2004. Indonesia imported $ 479 million electrical power equipment in 2004. The market share of U.S. products was 13% of the total value of imported product (or $ 61 million in 2004). The other major suppliers for this industry in Indonesia are Singapore, Japan, France and Germany. Construction of new power plants and transmission lines in Indonesia should bring significant commercial opportunities for U.S. companies that supply engineering services and equipment such as turbines, substations, transmission and distribution
equipment.

Market Overview
In the last two decades, the power industry in Indonesia has experienced high growth in demand, averaging 8% per annum. PT PLN served over 33 million consumers in Indonesia and sold 100.1 TWh in 2004. The biggest demand came from industry (40.4%), followed by residential 38.7%. The total energy produced in 2004 was 120.2 TWh, including electricity purchased from Independent Power Producers (25 TWh). Some 33% of the energy is generated by coal-fired power plants, 18% from gas-fired power plants, 36% from oil-fired
power plants, 10% from hydro power plants and 3% from geothermal power plants.
Based on the assumption of average annual economic growth 6.5% over the next five years, electricity was predicted to increase with an average growth rate of 8.3% per year. By 2009, electricity demand in Indonesia will increase to 145.7 TWh. The electrification ratio is expected increase to reach 67.9% and new customers will increase by 10 million in the next five years. By 2009, the Java-Bali system will need an additional 7,905 MW, 3,720 kms of transmission line and 14,276 MVA (megavolt ampere) substations. For islands other than
Java-Bali, it will need additional 4,362 MW, 3,720 kms transmission lines and 4,120 MVA substations. For the rural electrification program, it is estimated that the village-electrified ratio will be 97% by 2009.

The government has projected that the financial requirement for power development during 2004-2013 will be US$ 31.4 billion. The plan consists of the development of power plants with a generating capacity of 22,261 MW, 17,070 kilometers of transmission networks, the development of major relay stations, distribution network, and rural electricity systems.

However, due to the lack of funding, the government must rely heavily on the private sector to expand the country’s power system. Therefore, the government is trying to create a investment climate conducive to private investment by giving incentives and guarantees against risks.

Market Trends
Indonesia’s Constitutional Court recently annulled Electricity Law No. 20/2002 based on the argument that the law contravened the Article 33 of the 1945 Constitution. According the Constitutional Court, electricity is a vital commodity for people and should be under the control of the government. Law no. 20/2002, enacted by the House of Parliament in 2002, aimed at a gradual liberalization of the power sector, allowing private companies to produce
and sell power to customers in 2007. The Constitutional Court also re-enacted the former Law No. 15/1985. The Constitutional Court specifically reviewed articles 16,17 and 68, which covered to separation of electricity supply ventures, competition in electricity generating ventures and replacement of Electricity Business Authorization holder (PKUK). On February
16, 2005, the GOI issued Government Regulation No. 3/2005 to provide investors with legal certainty in developing power projects. According to this regulation, private sectors can participate in power projects; however, they have to be in partnership with PLN through a tender process. However, power generated from renewable energy, marginal gas fields, mine mouths can be developed without a tender process.

PLN’s President Director, Eddie Widiono has assured that PLN would respect all power contracts that have been signed. Even with the cancellation of the law, PLN’s restructuring program will continue and should provide better services to customers. The IPP is still applicable as long as IPPs are connected to PLN’s grids. In addition, the GOI will speed up the implementation of regional tariffs to their economic tariffs.

During the First Indonesian Infrastructure Summit in January 2005, the GOI offered 91 infrastructure projects worth $22.5 billion in five priority sectors including transportation, gas pipelines, electric power, water supply and resources, and telecommunications. The projects, which span the country for the 2005-2009 period, are designed to attract investment and boost annual economic growth to over 6 percent.

The electricity projects planned for the next five years that were offered during the
Infrastructure Summit:
Name of project Capacity Investment
1. PLTU Tanjung Jati A 1,320 MW $1,311 million
2. PLTU Serang 450 MW $500 million
3. PLTU Tanjung Jati C 1,320 MW $1,311 million
4. PLTGU Pasuruan 500 MW $555 million
5. PLTU Cilegon 400 MW $444 million
6. PLTU Paiton 3-4 800 MW $889 million
7. PLTU Sibolga 200 MW $ 91 million
8. PLTU Amurang 55 MW $109 million
9. LNG Terminal for PT PLN – $251 million
10. Sumatra-Java Interconnection – $217 million
11. PLTU Parit Baru 110 MW $109 million

Note:
PLTA: hydropower plant
PLTD: diesel power generating plant
PLTG: gas fired power plant
PLTP: geothermal power plant
PLTU: steam power plant
PLTGU: coal-steam combined cycle power plant

PT PLN will soon sign 24 private power plant development contracts for small power plants with total capacity of 1,134 MW worth more than US$ 1.1 billion. According to Eddie Widiono, PLN had started tendering process in August 2004. The work consist of 3 projects in South Sumatra (mine mouth power plant, 2×100 MW each), South Kalimantan (mine mouth, 2×65 MW), East Kalimantan (mine mouth, 2×25 MW), steam power plants in 18 provinces (capacity varies from 6 to 66 MW) and gas and fuel power plants in Papua
(2x5MW and 3×3.5 MW). The buying price for mine mouth power plant ranging $0.0388 – $0.434 perkWh, medium power plant (below 25 MW) ranging Rp. 432-Rp.475 perkWh and small power plant ranging from Rp. 489-556 per kWh.
PT PLN planned to develop a Java-Sumatra interconnection submarine electric cable, expected to be finished by 2007. The development of 2 for 200 MW circuit each for 50 km submarine interconnection transmission line will cost US$170 million. With this line, it will solve the power crisis in Java-Bali by getting additional power supply from South Sumatra.

The South Sumatra provincial government will have 3,400 MW installed power capacity by 2009 from PLTU Musi, PLTA Tarahan, PLTU Banjarsari and others.
By the end of this year, the GOI will announce tenders for development of eight non-oil fuel power plant projects worth $3.67 billion. The plants include four in Java, with capacity between 500 MW-1,200 MW each and smaller capacity power plants will be built in Bali, North Sumatra, North Sulawesi and East Kalimantan.
For rural electricfication program, PLN plans to build 12 hydropower plants accros the country. Nine power plants will be financed by JBIC and ADB with total capacity of 447MW and three power plants with 9.9 MW will be financed by the state budget. In 2005, PLN plans to start building 10 more hydropower plants funded by the ADB. Import Market
A. IMPORT MARKET
The total market value for electrical power equipment was US$ 505 million in 2004. The number increased from US$ 461 million in 2003. It is predicted the total market will reach US$ 556.4 million this year. Indonesia imported $397 million electrical power equipment in 2003. The number increased slightly to $479 million in 2004. There will be more opportunities in the next two years as power plant projects are implemented soon. It is predicted that the total market and the value of imported products will increase by 10% in 2005.
US MARKET POSITION
Imported U.S. products comprised $ 54 million or around 13% of the total import value of electrical power equipment in 2003. As the market size increased in 2004, the imported value of US products was also increased slightly to $ 61 million in 2004. Indonesian companies usually imported U.S. products directly or through the agent/distributor in  Singapore. It is estimated that the value of imported products from the US will increase by10% in 2005.

Competition
The other major suppliers of electrical power equipment to Indonesia are Japan, Germany, Singapore, and France. In 2004, Japanese products amounted to $ 73 (or 15% of the total imported value), followed by Singapore with $ 60 million (12%) and Germany with $48 million (10%). Based on market observations and on discussions with agents and distributors, many U.S. products were imported to Indonesia through Singapore. Some reasons cited for importing U.S. products through Singaporean companies are shorter
delivery time, cheaper shipping cost and most of the Singaporean companies are very responsive. However, some Indonesian companies complain that they have to pay more when buying through Singapore as compared to buying directly from U.S. manufacturers Some market players have expressed concern regarding the increasing activities of Chinese power generating companies in Indonesia. In the last three years, Chinese investors developed 4 power plants worth US$ 1 billion with financial package from Chinese Banks.

The Borang gas power plant in Palembang was built in 2004 with a capacity of 100 MW. Other power plants expected to be in operation in 2006-2009, are Karangkandri in Cilacap (2 x 300 MW), Labuhan Angin in Sibolga (4 x 55 MW), and Bangko Tengah in South Sumatra (4 x 600 MW). The Chinese could be more competitive since they offer cheaper financial packages.

End Users
A. PLN
The electric power industry in Indonesia is solely managed by Perusahaan Listrik Negara (PLN), a state-owned monopoly. PLN has various business units that carry out functions as generation, transmission and distribution company. For generation, PLN set up two subsidiary companies: PT Indonesia Power and PT Pembangkit Jawa Bali (PJB).
In addition to the supply from its own power generation plants, PLN has additional power supply from captive power plants. Captive power plants are power generation plants that are built, operated and used by private companies such as mining companies, oil exploration companies, pulp and paper factories and high rise building management companies. The total captive power capacity in Indonesia is 15,200.1 MW, where 7,324.52 MW is in Java and 7,895.61 MW is outside Java-Bali.

In 2004, PT PLN and its subsidiary companies owned and operated more than 4,800 generating units with total installed capacity of 21,768 MW, of which 19,500 MW was installed in Java. Around 83% of the electricity coming from thermal power plants (oil, gas or coal fired), 14% from hydropower plants, and 3% from geothermal power plants.

PT PLN had 33.2 million customers in Indonesia (2004). Around 93% were residential customers, following by business (4%), social (2%) and office + industry (1%). Most of the residential customers were in Java-Bali areas (98.6%). During the peak load, demand in Java-Bali reached 14,500 MW while the supply capacity was 15,000 MW. If there was a problem on one of 11 existing power plants (total installed capacity: 19,500 MW), customers
would experience rotating power blackout. PT PLN sold 100,097 GWh in 2004.

The biggest demand came from industry (40.4%), followed by residential 38.7%. At present, several areas other than Java-Bali are in critical condition, especially Aceh, South Sumatra, West Sumatra, Riau, West Kalimantan, South Kalimantan, East Kalimantan, North Sulawesi, South Sulawesi, Lombok and East Nusa Tenggara. In those areas, PLN has conducted rotating power blackouts. In 2006, PLN expects that there will be additional power supply from PLTU Tanjung Jati B (320 MW), PLTU Cilacap (600 MW), and PLTU Cilegon (720 MW). Additional supply will also come from PLTU Mine Mouth in South
Sumatra (4×600 MW). PLN has established four subsidiaries. PT Indonesia Power, PT Pembangkitan Jawa Bali, and PT PLN Batam are in generation business. One company, PT Indonesia Comnets Plus is in the telecommunication business. In the future, PT PLN plans to have 3 new
subsidiaries: PLN Unit Pembangkitan Muara Tawar, Pembangkitan Tanjung Jati B andPembangkitan Cilegon.

PT Indonesia Power was established in 1995. The total power capacity generated under the management of this company was 7,221 MW in 2004. There are 8 units of generation power centers, which are Tanjung Priok with 1,026 MW, Suralaya with 2,852 MW, Saguling Java with 697 MW, Kamojang with 333 MW, Mrica with 298 MW, Semarang with 1,098 MW, Perak and Grati with 673 MW and Bali with 244 MW. The company produces 44,417 GWh
or 46.51% of the total power output in the Java-Bali system.

PT Indonesia Power offers an opportunity for cooperation in the procurement of various types of generating facilities including PLTU, PLTG, PLTGU, PLTP and PLTA with a capacity of more than 20 MW. Following are some of projects offered: PLTUG Pemaron (3×48 MW), PLTGU Pesanggrahan (40MW), PLTU Gambut (2x25MW), PLTGU Kamojang IV (60 MW), PLTU Padang (2×50 MW) and PLTU Pangkalan (600MW).

PT Pembangkitan Java-Bali was established in 1995. The company owns 8 power generation plants with the total installed capacity of 6,526 MW, which are Brantas with 281 MW, Cirata with 1,008 MW, Muara Tawar with 920 MW, Paiton with 800 MW, Muara Karang with 1,208 MW and Gresik with 2,259 MW.
B. INDEPENDENT POWER PRODUCERS (IPP)
PT PLN has finished the renegotiation process with several Independent Power Producers (IPPs) for 26 power plant projects. As a result, PLN’s purchase price was five cents per kilowatt-hour (kWh) well below the 8.4 cents level set in the previous agreement. Based on this new agreement, PLN will save $5.9 billion over the next 20-30 years. The total investment needed for 26 power projects is US$15.1 billion, with the total power capacity of 10,615 MW. Of the 26 IPPs, fourteen IPPs agreed to continue their projects under a new pricing scheme, while seven will terminate their Power Purchase Agreement (PPAs), and
five projects will be taken over by PLN and Pertamina. Seven projects, which are agreed to continue, are still in process and are scheduled to be finished by 2006/2007. The seven projects are Amurang, Sibolga, Sibayak, Asahan, Paiton I, Paiton II, and Sengkang.
C. PRIVATE POWER GENERATORS
They are almost 400 private companies, scattered in Indonesia, that have their own power generation plants. Most of them are manufacturers, plantations, exploration companies, building management, hospitals, schools and others. Those companies hold a special license that allows each company to generate electricity only for its own use and it can not be sold to the public. Most of those companies are using diesel as an energy source for the generator, with the capacity ranging from 0.30 MW to 15 MW.

Market Acces
The Indonesian electrical power market can be characterized as relatively open and no nontariff barrier exist. Since the government attaches great importance to the development of the electricity sector, imports of related equipment are as much as possible facilitated, to provide the necessary incentives to the private sector. With regard to technical and safety standards, Indonesia has adopted international norms and there are none particular to this
country.

The import duty of various electrical power equipment in 2005 ranges from 5 – 10% and the VAT is 10%.

Market Entry

Foreign suppliers who want to supply to either PT PLN or its subsidiaries must work through a local, Indonesian-owned limited liability company. Only registered Indonesian companies can bid on most service contracts to PT PLN. Most purchases of goods and services are done through tenders. Generally only vendors with a registered vendor ID (Tanda Daftar Rekanan — TDR) are considered qualified contractors (Daftar Rekanan Mampu – DRM) and permitted to bid. Sometimes, however, direct purchasing is permitted without competitive bidding. Under the new Presidential Decree (Keppres) No. 18/2000, the Indonesian Government is establishing new Technical Guidelines for government procurements of goods and services. The decree establishes set-aside for SMEs according to the size of the procurement. Foreign suppliers are restricted to contracts worth over Rp. 10 billion ($1 million) for goods/services and over Rp2 billion ($200,000) for consulting services. A foreign supplier is required to cooperate with a small- or medium-sized company or cooperative in the implementation of the contract. Tender awards by PT PLN are based on price, Indonesian content, technical advantage, and reputation. Domestic goods and services must be used, if available, even at higher cost.

To learn about activities and trade opportunities in energy industry, there are several websites that can be accessed after paying a membership fee:
1. http://www.tender-indonesia.com
2. http://www.iogonline.com
3. http://www.petromindo.com

 

Bawean Island

November 10, 2011

Throughout the Malay world, there survives a belief in the occult, the practice of which is the peaceful syncretism of local animism and the less orthodox Islam brought by Arab traders seven hundred years ago. Bawean Island practitioners of magic called dukuns have a reputation for being particularly skilled. I would have accepted their supernatural intervention in avoiding the nine-hour voyage by cargo ship to get there–a mere speck in the sea north of Indonesia’s eastern Java.

Bawean’s size belies its significance in Southeast Asian history. The islanders’ hard work ethic found deep appreciation in nineteenth century Singapore. Today, Baweanese comprise the second largest ethnic group of Singapore’s Malay community, one of whom invited me along on his next visit home.

Once aboard the rusting 2,000-ton vessel, my host suspended a hammock and went to sleep. Captain Mundiari courteously offered me his cabin for the night crossing but as the K.M. Pratini shuddered through rough seas and stars rocketed between black sky and blacker water, I opted for a plastic chair on deck where I could hang my dizzy head over the railing. Sympathetic crew squeezed by me on their trips to and from the wheelhouse.

All traffic to Bawean moves through its main town and port, Sangkapura. Many Baweanese men are sailors, on large and small vessels across the Indonesian archipelago and beyond; shipbuilders of aged hardwood supply boats called prahu; or fishermen, captains of tiny crafts called gukongs that are unique to Bawean, with white bodies, brightly painted prows and two supporting arms like a catamaran’s. In 1969, a gukong sailed safely to Singapore and back, a distance of 1,400 kilometers, a success viewed superstitiously by its solitary navigator who became a dukun upon his return. Many haven’t been so fortunate–the sea is a constant, reckoning force in the lives of an island culture. It didn’t seem implausible to me, colored as my theory was by motion sickness, that Baweanese consider magic a necessary means of survival.

Bawean means “sunlight exists” in Sanskrit, which is what fourteenth century shipwrecked sailors reportedly exclaimed upon seeing it under clear skies after days tossed about in stormy seas. At three in the morning, my first sight of Bawean–a roller coaster silhouette on a bobbing horizon–made its less romantic name of Big Mountain Island more meaningful, a reference to the ninety-nine hills that occupy its 200-kilometer length. On the summit of one, I imagined the animist King Babileono to have sat in power-rejuvenating meditation.

Not much is known about King Babileono. Documented history of Bawean begins with the arrival in the sixteenth century of Umar Masood who overthrew him. Both men used sorcery against each other, but Masood’s magical feats were made possible by God. This assured him of victory and a thirty-year reign during which his subjects embraced his new faith of Islam. Masood’s legacy is the 186 mosques on Bawean, at least one in every of its thirty villages and the religious instruction that begins earlier than government schooling for Bawean children.

There is no better guardian of the past than sixty-year-old K.H. Abdulrachman, the fifteenth descendant of Umar Masood, who lives in Sangkapura not far from where his revered ancestor is buried. His Bawean history, compiled in 1985 for the benefit of returning emigrants and their families, is an invaluable resource. Like Masood, he is a qualified disseminator of Islam as denoted by the distinguished title of Kiayi Haji that prefaces his name. His religious practice also reflects the ancient belief of prayer as power activated by divine words, the white as opposed to black magic used to an advantage by Masood and today as an antidote for sickness or to remove bad spells cast by malicious persons. During the recounting of his family’s story to me, a message arrived that someone was ill and needed his urgent help. He excused himself but didn’t go to the patient. He never left the house. His prayers traveled instead, when he blew gently upon a glass of water that he had inspired by intoning Koranic scripture.

Nominally secular, Indonesia has the world’s largest Muslim population. The religion’s historical stronghold is Java from where, legend has it, nine holy men or walis, helped further its expansion. One of these men may be buried on Bawean Island. It is more certain that the wife of one of the famous walis renounced her privileged life on Java for one of piety on Bawean. There are myths of Waliyah Zainab’s miracles–her rice bowl was never empty and her water pitcher always full to feed and quench the thirst of her many disciples, magical implements that are exhibited behind her shrine in Bawean’s Diponggo Village. To this day villagers speak the form of Javanese that Waliyah brought with her and not the Baweanese or modern Indonesian languages. Overseas Baweanese come to thank her for their safety and prosperity. That her grave has become an important pilgrimage site for men (those most likely to leave the island) is one of those perplexing gender subtleties of Islam. Waliyah adopted the religious life only in rebellion when her husband took a younger second wife.

Divorce is a Baweanese woman’s prerogative as well as a man’s. Many Baweanese women are married but alone, deciders of their fate, because their husbands are away for years, working. Men become “lost” said a family court lawyer, who settles about fifteen divorce cases a month in his Sangkapura jurisdiction. Because women often outnumber men, a local writer called his early 1990s book about Bawean “The Princess Island.” The royal label infers more choices than are available to the women who heed the religious dictates and customs that govern society. Their role models for independence are religious women. One of them complimented me when she said at my departure, “If you return to us as a religious teacher, you will have many followers.”

When the K. M. Pratini docked at Sangkapura, the first prayer call of the day had begun. We drove north along the east coast to my host’s village, his father’s birthplace, along one of Bawean’s three roads. The azan pursued us, each mosque staggering its beginning so that the summons surged and faded in tandem. From my seat in the back of the truck, I glimpsed pastoral beauty in the strengthening light–harvested rice paddies, swaying coconut palms and drifting fishing boats anchored off sandy beaches.

Bawean is not undiscovered: At any one time, a few dozen private sailboats anchor in sheltered bays and Balinese tour boats periodically discharge passengers on day trips, primarily to visit Danau Kastoba, a large lake where it is said that King Babileono conjured his charms. About twenty Asian tourists a month come to a mangrove forest–called White Beach for its pristine sand–to fish. The master gukong maker has accepted western students. In comparison, however, to the eastern Javanese city of Surabaya, where the use of small hand-held stop signs hanging at intersections are necessary to cross the street, Bawean remains a world apart, the 75 nautical miles a buffer between it and the outside. Baweanese attribute this cultural autonomy to their magic. They maintain that even Dutch colonizers failed to exploit the island–their repeated attempts to extract gold from the island’s mine all meeting with tragic accidents. The elders who remember the mine’s location will not disclose it for fear of spiritual retribution. A less paranormal indication of Bawean’s seclusion was the visit I was paid by the island’s suspicious representatives of Indonesian police.

In my Surabaya hotel room, the evening before my departure for Bawean, I had watched a female entertainer on television, dressed less conservatively than I, while in the screen’s upper corner a little beating drum signaled a prayer call. In the Baweanese towns of Sangkapura and Tambak, acceptable attire did not include a headscarf. In my host’s simple village of devout farmers, where the daily rhythm revolved around prayer times, I covered my head like every woman. It was hot beneath the scarf and difficult to keep in place while I moved about. A veil is not only an article of religious respect, but also enhances a woman’s beauty. My host’s housekeepers, in whose care I was placed, took me to the market to purchase a scarf more becoming than the one I had brought and two of finer material for them. They wore them with pride the day I departed and I was aware that when I removed mine, in their eyes I diminished my femininity.

The headscarf also concealed my differences. At night, the village women gathered at my host’s house for prayers, hour-long recitations of the Koran that became anticipated performances during my visit. Some were surprised at first that I didn’t know the Arabic passages, but as the week went on, they took their leave of me with a single hand raised to their breast in the Malay gesture of respect. Among them lived a centenarian, a woman of such fragility that I could encircle her forearm with my fingers. Yet she lived alone, a widow for decades, in the last mud-floored attap hut of its kind. She was my host’s grandmother and I was the first Caucasian woman that she had met.

When Lake Kastoba was King Babileono’s domain, it was taboo for women to set foot there. One acted as my cheerful escort, along with her husband and five of their nine children, who wanted to picnic and fish. We abandoned the truck after thirty minutes and climbed a steep hill, stopping to introduce me to curious residents who, back from their rice, peanut and cassava fields, rested on attap-surfaced wooden platforms outside their houses called dhurungs. Cultivated fields alternated with teak forests; Baweanese substitute the tree’s dinner-plate sized leaves for paper and plastic to package fresh produce at the markets.

Baweanese folklore maintains that Lake Kastoba was formed by a genie pulling up a tree. Others say that a special tree stands by the lake, its bark eternally free of moss and its falling leaves and branches disappearing before reaching the ground. The lake was a perfect setting for sorcerers: its thick surrounding vegetation dripped creepers and small fruit bats kissed its inky surface. We stayed for sunset, the children engrossed in their play. The photos that I took of this happy time were all inexplicably overexposed. I was not the first disappointed photographer. Professional cameramen, hired to photograph the lake from the air, gave up when film after exposed film remained mysteriously blank.

Upon my return from the lake, I felt a sudden ache in my knee that mystified me. The walk hadn’t been strenuous or difficult. I was still favoring one leg when I boarded the K.M. Pratini for Java. The captain and I greeted each other like old friends. He nodded knowingly when informed of my discomfort. Someone, he said, wanted me to stay longer on the island.

Published on 9/1/99

Tarif dasar Listrik

November 10, 2011
Dari Wikipedia bahasa Indonesia, ensiklopedia bebas

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Tarif dasar listrik atau biasa disingkat TDL, adalah tarif yang boleh dikenakan oleh pemerintah untuk para pelanggan PLN. PLN adalah satu-satunya perusahaan yang boleh menjual listrik secara langsung kepada masyarakat Indonesia, maka TDL bisa dibilang adalah tarif untuk penggunaan listrik di Indonesia. Saat ini TDL rata-rata adalah USD 0,065 /kWh. Pada 2004, tarif nonsubsidi pelanggan 6.600 VA ke atas sekitar Rp 1.380 per kilowatt-hour (kWh), sedang tarif subsidi sekitar Rp 600 per kWh [1]. Pada awal 2008 , diberlakukan tarif non subsidi untuk pelanggan listrik dengan daya 6600 keatas.

Mulai 1 Juli 2010, pemerintah memutuskan menaikkan TDL rata-rata 10%. Hal ini didasarkan pada Pasal 8 UU No.2 Tahun 2010,[2] untuk menutupi kekurangan subsidi sebesar Rp4,8 triliun karena alokasi anggaran subsidi listrik ditetapkan Rp.55,1 triliun. Tetapi untuk TDL 450-900 VA, DPR memutuskan tidak ada kenaikan.[2]

Kenaikan TDL ini mengundang aksi demo dari Mahasiswa[3], menurut mereka kenaikan hanya menambah penderitaan rakyat, terutama dari kalangan menengah ke bawah. Tetapi menurut PLN, kenaikan TDL adalah untuk meningkatkan kinerja PLN. Selama ini PLN berusaha menutupi kekurangan pasokan dengan menambah pembangkit kecil dan genset. Direktur Utama PLN Dahlan Iskan, mengatakan bahwa terjadinya pemadaman di beberapa daerah bukan karena kurangnya pasokan listrik, melainkan karena rusaknya trafo listrik akibat kelebihan beban, yang menurutnya ideal kalau satu trafo maksimal hanya melayani 150 pelanggan. Tapi yang terjadi selama ini melayani lebih dari 200 pelanggan. PT. PLN menjamin tidak akan ada pemadaman bergilir lagi setelah tarif dasar listrik naik pada 1 Juli 2010.[4]

Daftar isi

[sunting] Tarif Dasar Listrik 2004

TDL2004.JPG

[sunting] Tarif Dasar Listrik 2003

Dasar Hukum : Keputusan Presiden Nomor 89 Tahun 2002 tanggal 31 Desember 2002[5]

Masa berlaku : 1 Januari 2003 sampai 1 januari 2004

 

[sunting] Lampiran III A TDL utk rumah tangga

  • 1.R-1/TR s.d. 450 VA
    • BIAYA BEBAN : Rp 12.000/bulan
    • Blok I : 0 s.d.30 kWh : Rp 172/kWh
    • Blok II : di atas 30 kWh s.d.60 kWh :Rp 380/kWh
    • Blok III : di atas 60 kWh : Rp 530/kWh
  • 2. R-1/TR 900 VA
    • BIAYA BEBAN : Rp 23.000/bulan
    • Blok I : 0 s.d. 20 kWh : Rp 310/kWh
    • Blok II : di atas 20 kWh s.d.60 kWh : Rp 490/kWh
    • Blok III : di atas 60 kWh : Rp 530/kWh
  • 3. R-1/TR 1.300 VA
    • BIAYA BEBAN : Rp 30.500/bulan
    • Blok I : 0 s.d. 20 kWh : Rp 395/kWh
    • Blok II : di atas 20 kWh s.d.60 kWh : Rp 490/kWh
    • Blok III : di atas 60 kWh :Rp 530/kWh
  • 4. R-1/TR 2.200 VA
    • BIAYA BEBAN : Rp 30.500/bulan
    • Blok I : 0 s.d. 20 kWh : Rp 400/kWh
    • Blok II : di atas 20 kWh s.d.60 kWh : Rp 490/kWh
    • Blok III : di atas 60 kWh :Rp 530/kWh
  • 5. R-2/TR di atas 2.200 VA s.d. 6.600 VA
    • BIAYA BEBAN : Rp 30.500/bulan
    • Biaya listrik : Rp 575/kWh
  • 6. R-3/TR di atas 6.600 VA
    • BIAYA BEBAN : Rp 34.260/bulan
    • Biaya listrik : Rp 621/kWh

[sunting] Lampiran V B TDL utk industri

  • 1. R-1/TR s.d. 450 VA
    • BIAYA BEBAN : Rp 27.000/bulan
    • Blok I : 0 s.d.30 kWh : Rp 161/kWh
    • Blok II : di atas 30 kWh :Rp 435/kWh
  • 2. I-1/TR 900 VA
    • BIAYA BEBAN : Rp 33.500/bulan
    • Blok I : 0 s.d. 72 kWh : Rp 350/kWh
    • Blok II : di atas 72 kWh : Rp 465/kWh
  • 3. I-1/TR 1.300 VA
    • BIAYA BEBAN : Rp 33.800/bulan
    • Blok I : 0 s.d. 104 kWh : Rp 475/kWh
    • Blok II : di atas 104 kWh s.d.60 kWh : Rp 495/kWh
  • 4. I-1/TR 2.200 VA
    • BIAYA BEBAN : Rp 33.800/bulan
    • Blok I : 0 s.d. 196 kWh : Rp 480/kWh
    • Blok II : di atas 196 kWh : Rp 495/kWh
  • 5. I-1/TR di atas 2.200 VA s.d. 14 kVA
    • BIAYA BEBAN : Rp 34.000/bulan
    • Blok I : 0 s.d. 80 jam nyala : Rp 480/kWh
    • Blok II : di atas 80 jam nyala berikutnya : Rp 495/kWh
  • 6. I-2/TR di atas 14 kVA s.d. 200 kVA
    • BIAYA BEBAN : Rp 35.000/bulan
    • Blok WBP = K x Rp 466
    • Blok LWBP = Rp 466/kWh
  • 7. I-3/TM di atas 200 kVA 29.500
    • BIAYA BEBAN : Rp 31.300/bulan
    • 0 s.d. 350 jam nyala, Blok WBP = K x Rp 468
    • di atas 350 jam nyala, Blok WBP = Rp 468/kWh
    • Blok LWBP = Rp 468/kWh
  • 8. I-4/TT 30.000 kVA ke atas
    • BIAYA BEBAN : Rp 28.700/bulan
    • Biaya listrik : Rp 460/kWh

Catatan :

K : Faktor perbandingan antara harga WBP dan LWBP sesuai dengan karakteristik beban sistem kelistrikan setempat ( 1,4 £ K £ 2 ), yang ditetapkan oleh Direksi Perusahaan Perseroan (PERSERO) PT Perusahaan Listrik Negara.

WBP : Waktu Beban Puncak

LWBP : Luar Waktu Beban Puncak

Jam nyala : adalah kWh per bulan dibagi dengan kVA tersambung

[sunting] Batas hemat

Pada 2009 PLN mengeluarkan batas hemat dimana pemakaian dalam jumlah lebih dari yang ditentukan akan mendapatkan tarif yang lebih berat. Hal ini pada prakteknya menaikan biaya listrik tanpa harus menaikan TDL

adalah sebagai berikut

[sunting] 1. Gol. Rumah Tangga :

  • daya 6600 VA, batas hematnya = 838,2 kWh
  • daya 7700VA, batas hematnya = 754,6 kWh
  • daya 10.600 VA, batas hematnya = 1.038,8 kWh
  • daya 11.000 VA, batas hematnya = 1.078 kWh
  • daya 13.200 VA, batas hematnya = 1.293,6 kWh
  • daya 16.500 VA, batas hematnya = 1.617 kWh
  • daya 23.000 VA, batas hematnya = 2.254 kWh
  • daya 33.000 VA, batas hematnya = 3.234 kWh
  • daya 41.500 VA, batas hematnya = 4.067 kWh
  • daya 53.000 VA, batas hematnya = 5.194 kWh

[sunting] 2. Gol. Bisnis :

  • daya 6600 VA, batas hematnya = 620,4 kWh
  • daya 7700 VA, batas hematnya = 723,8 kWh
  • daya 10.600 VA, batas hematnya = 996,4 kWh
  • daya 11.000 VA, batas hematnya = 1.034 kWh
  • daya 13.200 VA, batas hematnya = 1.240,8 kWh
  • daya 16.500 VA, batas hematnya = 1.551 kWh
  • daya 23.000 VA, batas hematnya = 2.162 kWh
  • daya 33.000 VA, batas hematnya = 3.102 kWh
  • daya 41.500 VA, batas hematnya = 3.901 kWh
  • daya 53.000 VA, batas hematnya = 4.982 kWh

[sunting] 3. Gol. Pemerintahan :

  • daya 6600 VA, batas hematnya = 660 kWh
  • daya 7700 VA, batas hematnya = 770 kWh
  • daya 10.600 VA, batas hematnya = 1.060 kWh
  • daya 11.000 VA, batas hematnya = 1.100 kWh
  • daya 13.200 VA, batas hematnya = 1.320 kWh
  • daya 16.500 VA, batas hematnya = 1.650 kWh
  • daya 23.000 VA, batas hematnya = 2.300 kWh
  • daya 33.000 VA, batas hematnya = 3.300 kWh
  • daya 41.500 VA, batas hematnya = 4.150 kWh
  • daya 53.000 VA, batas hematnya = 5.300 kWh

Sebagai catatan harga rata-rata listrik di Amerika Serikat hanya berkisar Rp 819/kWh. Sedangkan di negara ASEAN rata rata dibawah Rp 800/kWh.

[sunting] Referensi

[sunting] Pranala luar:

Energi  Artikel bertopik energi ini adalah sebuah rintisan. Anda dapat membantu Wikipedia dengan mengembangkannya.

 

Ruang nama

Varian
 

Tindakan
 

PLN

November 10, 2011

Perusahaan Listrik Negara (disingkat PLN) adalah sebuah BUMN yang mengurusi semua aspek kelistrikan yang ada di Indonesia. Direktur Utamanya adalah Dahlan Iskan, yang dilantik pada 23 Desember 2009 menggantikan Fahmi Mochtar (yang menjabat sejak 2008).

Ketenagalistrikan di Indonesia dimulai pada akhir abad ke-19, ketika beberapa perusahaan Belanda mendirikan pembangkitan tenaga listrik untuk keperluan sendiri. Pengusahaan tenaga listrik untuk kepentingan umum dimulai sejak perusahaan swasta Belanda NV. NIGM memperluas usahanya di bidang tenaga listrik, yang semula hanya bergerak di bidang gas. Kemudian meluas dengan berdirinya perusahaan swasta lainnya.

Daftar isi

Sejarah

Pelat peringatan tua di gardu listrik

Setelah diproklamirkannya kemerdekaan Indonesia, tanggal 17 Agustus 1945, perusahaan listrik yang dikuasai Jepang direbut oleh pemuda-pemuda Indonesia pada bulan September 1945, lalu diserahkan kepada pemerintah Republik Indonesia. Pada tanggal 27 Oktober 1945 dibentuklah Jawatan Listrik dan Gas oleh Presiden Soekarno. Waktu itu kapasitas pembangkit tenaga listrik hanyalah sebesar 157,5 MW.

[sunting] Peristiwa

  • Tanggal 1 Januari 1961, dibentuk BPU – PLN (Badan Pimpinan Umum Perusahaan Listrik Negara) yang bergerak di bidang listrik, gas dan kokas.
  • Tanggal 1 Januari 1965, BPU-PLN dibubarkan dan dibentuk 2 perusahaan negara yaitu Perusahaan Listrik Negara (PLN) yang mengelola tenaga listrik dan Perusahaan Gas Negara (PGN) yang mengelola gas.

Saat itu kapasitas pembangkit tenaga listrik PLN sebesar 300 MW.

  • Tahun 1972, Pemerintah Indonesia menetapkan status Perusahaan Listrik Negara sebagai Perusahaan Umum Listrik Negara (PLN).
  • Tahun 1990 melalui peraturan pemerintah No 17, PLN ditetapkan sebagai pemegang kuasa usaha ketenagalistrikan.
  • Tahun 1992, pemerintah memberikan kesempatan kepada sektor swasta untuk bergerak dalam bisnis penyediaan tenaga listrik.

Sejalan dengan kebijakan di atas maka pada bulan Juni 1994 status PLN dialihkan dari Perusahaan Umum menjadi Perusahaan Perseroan (Persero).

[sunting] Konsumsi listrik di Indonesia

Konsumsi listrik Indonesia secara rata rata adalah 473 kWh/kapita pada 2003. Angka ini masih tergolong rendah dibandingkan rata rata konsumsi listrik dunia yang mencapai 2215 kWh/kapita (perkiraan 2005). Dalam daftar yang dikeluarkan oleh The World Fact Book, Indonesia menempati urutan 154 dari 216 negara yang ada dalam daftar.

Menurut koran Sindo hari Senin tanggal 9 Juni 2008 halaman 5, daftar konsumsi listrik perdaerah di Indonesia adalah (dalam satuan kWh/kapita):

  1. Jakarta dan Tangerang: 1873.9
  2. Sumatra Utara: 390.78
  3. NAD: 206.06
  4. Bali: 619.26
  5. Sumatra Barat: 375.83
  6. Jawa Tengah: 343.84
  7. Kalimantan Selatan: 306.14
  8. DIY: 398.77
  9. Jawa Timur: 500.73
  10. Sulawesi Selatan: 281.58
  11. Sulawesi Utara: 290.78
  12. Jawa Barat: 621.4
  13. Banten: 1293.76
  14. Maluku: 176.08
  15. Kalimantan Timur: 461.7
  16. Kalimantan Barat: 214.45
  17. Bengkulu: 176.44
  18. Bangka Belitung: 278.02
  19. Sulawesi Tengah: 146.14
  20. Sumatra Selatan: 256.45
  21. Kalimantan Tengah: 195.87
  22. Maluku Utara: 127.54
  23. Lampung: 208.31
  24. Gorontalo: 134.78
  25. Sulawesi Tenggara: 120.22
  26. Jambi: 213.91
  27. Sulawesi Barat: 79.78
  28. Riau: 274.21
  29. NTB: 119.27
  30. Papua: 180.11
  31. NTT: 64.32
  32. Rata-rata nasional: 352.59

 Direktur Utama

  • Surjono
  • Sardjono
  • Ermansjah Jamin
  • s/d 1996: Zuhal
  • 1996 – 1998: Djiteng Marsudi
  • 1998 – 2000: Adi Satria
  • 2000 – Juli 2001: Kuntoro Mangkusubroto
  • Juli 2001-2008: Eddie Widiono
  • Maret 2008 – Desember 2009: Fahmi Mochtar
  • Desember 2009 – Oktober 2011: Dahlan Iskan
  • Oktober 2011 – sekarang : Jabatan Kosong[1]

 Referensi

  1. ^ Dahlan Iskan: Direktur Utama PLN Harus Orang PLN TEMPO|InteraktifDiakses tangal 19 Oktober 2011

 Lihat pula

 Pranala luar

PT Pembangkitan Jawa-Bali

November 10, 2011

PT Pembangkitan Jawa-Bali (disingkat PT PJB) adalah sebuah anak perusahaan PLN BUMN produsen listrik yang menyuplai kebutuhan listrik di Jawa Timur dan Bali. Saat ini PT PJB mengelola 6 Pembangkit Tenaga Listrik di Pulau Jawa, dengan kapasitas total 6.511 Mega Watt. PT PJB juga mengelola sejumlah unit bisnis, termasuk unit pengelolaan, teknologi informasi, dan pengembangan. Kantor pusat PT PJB berada di Surabaya.

Daftar isi

 Sejarah

Sejarah PJB bermula sejak tahun 1945, dimana didirikan Perusahaan Listrik dan Gas. Tahun 1965, perusahaan tersebut dibagi menjadi 2: Perusahaan Listrik Negara dan Perusahaan Gas Negara. Tahun 1972, status PLN menjadi Perusahaan umum (Perum). Tahun 1982, PLN dipecah lagi menjadi dua: Unit Divisi dan Unit Pembangkitan Tenaga Listrik dan Transmisi. Tahun 1994, status PLN menjadi Persero. Setahun kemudian, dilakukan restrukturisasi atas PT PLN (Persero) dengan pendirian subsider pembangkitan. Restrukturisasi ini dilakukan untuk memisahkan misi perusahaan atas sosial dan komersial.

Pada tanggal 3 Oktober 1995, PT PLN (Persero) membentuk 2 (dua) anak perusahaan untuk mengelola pembangkit listrik yang memasok energi listrik di Pulau Jawa dan Bali. Kedua anak perusahaan PLN tersebut adalah PT PLN Pembangitan Jawa Bali I (PT PLN PJB I) yang berkantor pusat di Jakarta dan PT PLN Pembangkitan Jawa Bali II (PT PLN PJB II) yang berkantor pusat di Surabaya. Pada tahun 2000, PT PLN PJB II diubah nama menjadi PT Pembangkitan Jawa-Bali atau singkatnya PT PJB. Sedangkan PT PLN Pembangitan Jawa Bali I (PT PLN PJB I) berubah nama menjadi PT Indonesia Power.

[sunting] Manajemen

Direksi PT PJB saat ini adalah Agus Pranoto(Direktur Utama), Mustiko Bawono (Direktur Produksi), Aminullah Assegaf (Direktur Keuangan), Sri Djoko M. Kuntjoro (Direktur Pengembangan dan Niaga) dan Achmad Zainuri (Direktur SDM). Sedangkan Komisaris PT PJB saat ini adalah Rachmat Harijanto (Presiden Komisaris), Moestafa Nadjib, Hendi Kariawan, Didin Wahyudin, dan Djoko Tetratmo.

 Pembangkit Tenaga Listrik

PT PJB mengelola berbagai jenis pembangkit tenaga listrik dengan total kapasitas 6.519 MW yang berlokasi di 6 tempat, yaitu PLTU & PLTGU Gresik (Kabupaten Gresik) dengan kapasitas 2.218 MW, PLTU & PLTGU Muara Karang (Jakarta Utara) dengan kapasitas 1.208 MW, PLTU Paiton (Paiton, Probolinggo) dengan kapasitas 800 MW, PLTGU Muara Tawar (Tarumajaya, Bekasi) dengan kapasitas 920 MW, PLTA Cirata (Tegalwaru, Purwakarta) dengan kapasitas 1.008 MW, dan PLTA Brantas (Sumberpucung, Malang) dengan kapasitas 274 MW.

Lihat pula

Wind Energy

November 9, 2011
From Wikipedia, the free encyclopedia

 

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Wind power: worldwide installed capacity [1]

Wind power: worldwide installed capacity forecast [1][2]

Burbo Bank Offshore Wind Farm, at the entrance to the River Mersey in North West England

Renewable energy
Wind turbine
Biofuel
Biomass
Geothermal
Hydroelectricity
Solar energy
Tidal power
Wave power
Wind power
v · d · e

Wind power is the conversion of wind energy into a useful form of energy, such as using wind turbines to make electricity, windmills for mechanical power, windpumps for water pumping or drainage, or sails to propel ships. The total amount of economically extractable power available from the wind is considerably more than present human power use from all sources.[3] Wind power, as an alternative to fossil fuels, is plentiful, renewable, widely distributed, clean, and produces no greenhouse gas emissions during operation, and the cost per unit of energy produced is similar to the cost for new coal and natural gas installations.[4]

A large wind farm may consist of several hundred individual wind turbines which are connected to the electric power transmission network. Offshore wind power can harness the better wind speeds that are available offshore compared to on land, so offshore wind power’s contribution in terms of electricity supplied is higher.[5] Small onshore wind facilities are used to provide electricity to isolated locations and utility companies increasingly buy back surplus electricity produced by small domestic wind turbines. The construction of wind farms is not universally welcomed, but any effects on the environment from wind power are generally much less problematic than those of any other power source.[6]

At the end of 2010, worldwide nameplate capacity of wind-powered generators was 197 gigawatts (GW).[7] Wind power now has the capacity to generate 430 TWh annually, which is about 2.5% of worldwide electricity usage.[7][8] Over the past five years the average annual growth in new installations has been 27.6 percent. Wind power market penetration is expected to reach 3.35 percent by 2013 and 8 percent by 2018.[9][10] Several countries have already achieved relatively high levels of wind power penetration, such as 21% of stationary electricity production in Denmark,[7] 18% in Portugal,[7] 16% in Spain,[7] 14% in Ireland[11] and 9% in Germany in 2010.[7][12] As of 2011, 83 countries around the world are using wind power on a commercial basis.[12]

Although a variable source of power, the intermittency of wind seldom creates problems when using wind power to supply up to 20% of total electricity demand, but as the proportion rises, increased costs, a need to use storage such as pumped-storage hydroelectricity, upgrade the grid, or a lowered ability to supplant conventional production may occur.[13][14][15] Power management techniques such as excess capacity, storage, dispatchable backing supply (usually natural gas), exporting and importing power to neighboring areas or reducing demand when wind production is low, can mitigate these problems.

Contents

History

Main article: History of wind power

Medieval depiction of a wind mill

Windmills are typically installed in favourable windy locations. In the image, wind power generators in Spain near an Osborne bull

Humans have been using wind power for at least 5,500 years to propel sailboats and sailing ships. Windmills have been used for irrigation pumping and for milling grain since the 7th century AD in what is now Afghanistan, India, Iran and Pakistan.[citation needed]

In the US, the development of the “water-pumping windmill” was the major factor in allowing the farming and ranching of vast areas otherwise devoid of readily accessible water. Windpumps contributed to the expansion of rail transport systems throughout the world, by pumping water from water wells for the steam locomotives.[16] The multi-bladed wind turbine atop a lattice tower made of wood or steel was, for many years, a fixture of the landscape throughout rural America. When fitted with generators and battery banks, small wind machines provided electricity to isolated farms.

In July 1887, a Scottish academic, Professor James Blyth, undertook wind power experiments that culminated in a UK patent in 1891.[17] In the US, Charles F. Brush produced electricity using a wind powered machine, starting in the winter of 1887-1888, which powered his home and laboratory until about 1900. In the 1890s, the Danish scientist and inventor Poul la Cour constructed wind turbines to generate electricity, which was then used to produce hydrogen.[17] These were the first of what was to become the modern form of wind turbine.

Small wind turbines for lighting of isolated rural buildings were widespread in the first part of the 20th century. Larger units intended for connection to a distribution network were tried at several locations including Balaklava USSR in 1931[citation needed] and in a 1.25 megawatt (MW) experimental unit in Vermont in 1941.[citation needed]

In the 1970s, U.S. industries teamed with NASA in a research program which created the NASA wind turbines, developing and testing many of the features of modern utility-scale turbines.[citation needed]

The modern wind power industry began in 1979 with the serial production of wind turbines by Danish manufacturers Kuriant, Vestas, Nordtank, and Bonus.[citation needed] These early turbines were small by today’s standards, with capacities of 20–30 kW each. Since then, they have increased greatly in size, with the Enercon E-126 capable of delivering up to 7 MW, while wind turbine production has expanded to many countries.

Wind energy

Main article: Wind energy

Map of available wind power for the United States. Color codes indicate wind power density class.

The Earth is unevenly heated by the sun, such that the poles receive less energy from the sun than the equator; along with this, dry land heats up (and cools down) more quickly than the seas do. The differential heating drives a global atmospheric convection system reaching from the Earth’s surface to the stratosphere which acts as a virtual ceiling. Most of the energy stored in these wind movements can be found at high altitudes where continuous wind speeds of over 160 km/h (99 mph) occur. Eventually, the wind energy is converted through friction into diffuse heat throughout the Earth’s surface and the atmosphere.

The total amount of economically extractable power available from the wind is considerably more than present human power use from all sources.[18] The most comprehensive study as of 2005[19] found the potential of wind power on land and near-shore to be 72 TW, equivalent to 54,000 MToE (million tons of oil equivalent) per year, or over five times the world’s current energy use in all forms. The potential takes into account only locations with mean annual wind speeds ≥ 6.9 m/s at 80 m. The study assumes six 1.5 megawatt, 77 m diameter turbines per square kilometer on roughly 13% of the total global land area (though that land would also be available for other compatible uses such as farming). The authors acknowledge that many practical barriers would need to be overcome to reach this theoretical capacity.

Others authors disagree with the bottom-up methodology and cites problems with such methods which can be “violating the first principle of energy conservation”. [20][21] The principe is that the amount of energy which can be extracted from wind power can actually exceed the power currently present in the lower atmosphere using such bottom-up analyses. (i.e. There is 100 TW of total power in the lower 200m of the entire atmosphere and somes studies go well over that limit. [20][21]) Theirs results show 1 TWe for the limit of wind power energy, which is much lower than previous estimates.

The practical limit to exploitation of wind power will be set by economic and environmental factors, since the resource available is far larger than any practical means to develop it.

Distribution of wind speed

Distribution of wind speed (red) and energy (blue) for all of 2002 at the Lee Ranch facility in Colorado. The histogram shows measured data, while the curve is the Rayleigh model distribution for the same average wind speed.

The strength of wind varies, and an average value for a given location does not alone indicate the amount of energy a wind turbine could produce there. To assess the frequency of wind speeds at a particular location, a probability distribution function is often fit to the observed data. Different locations will have different wind speed distributions. The Weibull model closely mirrors the actual distribution of hourly wind speeds at many locations. The Weibull factor is often close to 2 and therefore a Rayleigh distribution can be used as a less accurate, but simpler model.

Wind farms

Landowners in the US typically receive $3,000 to $5,000 per year in rental income from each wind turbine, while farmers continue to grow crops or graze cattle up to the foot of the turbines.[22]

Main article: Wind farm

A wind farm is a group of wind turbines in the same location used for production of electric power. A large wind farm may consist of several hundred individual wind turbines, and cover an extended area of hundreds of square miles, but the land between the turbines may be used for agricultural or other purposes. A wind farm may also be located offshore.

Many of the largest operational onshore wind farms are located in the US. As of November 2010, the Roscoe Wind Farm is the largest onshore wind farm in the world at 781.5 MW, followed by the Horse Hollow Wind Energy Center (735.5 MW). As of November 2010, the Thanet Wind Farm in the UK is the largest offshore wind farm in the world at 300 MW, followed by Horns Rev II (209 MW) in Denmark.

There are many large wind farms under construction and these include BARD Offshore 1 (400 MW), Greater Gabbard wind farm (500 MW), Lincs Wind Farm (270 MW), London Array (1000 MW), Lower Snake River Wind Project (343 MW), Shepherds Flat Wind Farm (845 MW), Sheringham Shoal (317 MW), and the Walney Wind Farm (367 MW).

Wind power usage

Main article: Wind power by country

Worldwide there are now many thousands of wind turbines operating, with a total nameplate capacity of 194,400 MW.[23] World wind generation capacity more than quadrupled between 2000 and 2006, doubling about every three years. The United States pioneered wind farms and led the world in installed capacity in the 1980s and into the 1990s. In 1997 German installed capacity surpassed the U.S., a position it held until passed by the U.S. in 2008. China rapidly expanded its wind installations in the late 2000s and passed the U.S. in 2010 to become the world leader.

Europe accounted for 48% of the world total in 2009. In 2010, Spain became Europe’s leading producer of wind energy, achieving 42,976 GWh. However, Germany holds the first place in Europe in terms of installed capacity, with a total of 27,215 MW at December 31, 2010.[24] Wind power accounts for approximately 21% of electricity use in Denmark,[7] 18% in Portugal,[7] 16% in Spain,[7][24] 14% in the Republic of Ireland,[7] and 9% in Germany.[7][25]

Country Windpower capacity (MW)
Top 10 countries by nameplate windpower capacity (2010)[7]
China 44,733
United States 40,180
Germany 27,215
Spain 20,676
India 13,066
Italy 5,797
France 5,660
United Kingdom 5,204
Canada 4,008
Denmark 3,734
Country Windpower electricity production (GWh)
Top 10 EU countries by windpower electricity production (December 2010)[24]
Spain 42,976
Germany 35,500
United Kingdom 11,440
France 9,600
Portugal 8,852
Denmark 7,808
Netherlands 3,972
Sweden 3,500
Ireland 3,473
Greece 2,200
Austria 2,100

Growth trends

Worldwide installed capacity 1997–2020 [MW], developments and prognosis. Data source: WWEA

In 2010, more than half of all new wind power was added outside of the traditional markets in Europe and North America. This was largely from new construction in China, which accounted for nearly half the new wind installations (16.5 GW). [26]

Global Wind Energy Council (GWEC) figures show that 2007 recorded an increase of installed capacity of 20 GW, taking the total installed wind energy capacity to 94 GW, up from 74 GW in 2006. Despite constraints facing supply chains for wind turbines, the annual market for wind continued to increase at an estimated rate of 37%, following 32% growth in 2006. In terms of economic value, the wind energy sector has become one of the important players in the energy markets, with the total value of new generating equipment installed in 2007 reaching €25 billion, or US$36 billion.[27]

Although the wind power industry was affected by the global financial crisis in 2009 and 2010, a BTM Consult five year forecast up to 2013 projects substantial growth. Over the past five years the average growth in new installations has been 27.6 percent each year. In the forecast to 2013 the expected average annual growth rate is 15.7 percent.[9][10] More than 200 GW of new wind power capacity could come on line before the end of 2013. Wind power market penetration is expected to reach 3.35 percent by 2013 and 8 percent by 2018.[9][10]

Offshore wind power

Main article: Offshore wind power

Aerial view of Lillgrund Wind Farm, Sweden

Offshore wind power refers to the construction of wind farms in bodies of water to generate electricity from wind. Better wind speeds are available offshore compared to on land, so offshore wind power’s contribution in terms of electricity supplied is higher.[5]

Siemens and Vestas are the leading turbine suppliers for offshore wind power. DONG Energy, Vattenfall and E.ON are the leading offshore operators.[5] As of October 2010, 3.16 GW of offshore wind power capacity was operational, mainly in Northern Europe. According to BTM Consult, more than 16 GW of additional capacity will be installed before the end of 2014 and the UK and Germany will become the two leading markets. Offshore wind power capacity is expected to reach a total of 75 GW worldwide by 2020, with significant contributions from China and the US.[5]

Electricity generation

Typical components of a wind turbine (gearbox, rotor shaft and brake assembly) being lifted into position

In a wind farm, individual turbines are interconnected with a medium voltage (often 34.5 kV), power collection system and communications network. At a substation, this medium-voltage electric current is increased in voltage with a transformer for connection to the high voltage electric power transmission system.

The surplus power produced by domestic microgenerators can, in some jurisdictions, be fed into the network and sold to the utility company, producing a retail credit for the microgenerators’ owners to offset their energy costs.[28][29]

Grid management

Induction generators, often used for wind power, require reactive power for excitation so substations used in wind-power collection systems include substantial capacitor banks for power factor correction. Different types of wind turbine generators behave differently during transmission grid disturbances, so extensive modelling of the dynamic electromechanical characteristics of a new wind farm is required by transmission system operators to ensure predictable stable behaviour during system faults (see: Low voltage ride through). In particular, induction generators cannot support the system voltage during faults, unlike steam or hydro turbine-driven synchronous generators. Doubly fed machines generally have more desirable properties for grid interconnection[citation needed]. Transmission systems operators will supply a wind farm developer with a grid code to specify the requirements for interconnection to the transmission grid. This will include power factor, constancy of frequency and dynamic behavior of the wind farm turbines during a system fault.[30][31]

Capacity factor

Since wind speed is not constant, a wind farm’s annual energy production is never as much as the sum of the generator nameplate ratings multiplied by the total hours in a year. The ratio of actual productivity in a year to this theoretical maximum is called the capacity factor. Typical capacity factors are 20–40%, with values at the upper end of the range in particularly favourable sites.[32] For example, a 1 MW turbine with a capacity factor of 35% will not produce 8,760 MW·h in a year (1 × 24 × 365), but only 1 × 0.35 × 24 × 365 = 3,066 MW·h, averaging to 0.35 MW. Online data is available for some locations and the capacity factor can be calculated from the yearly output.[33][34]

Unlike fueled generating plants, the capacity factor is affected by several parameters, including the variability of the wind at the site, but also the generator size- having a smaller generator would be cheaper and achieve higher capacity factor, but would make less electricity (and money) in high winds.[35] Conversely a bigger generator would cost more and generate little extra power and, depending on the type, may stall out at low wind speed. Thus an optimum capacity factor can be used, which is usually around 20-35%.

In a 2008 study released by the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy, the capacity factor achieved by the wind turbine fleet is shown to be increasing as the technology improves. The capacity factor achieved by new wind turbines in 2004 and 2005 reached 36%.[36]

Penetration

Wind energy “penetration” refers to the fraction of energy produced by wind compared with the total available generation capacity. There is no generally accepted “maximum” level of wind penetration. The limit for a particular grid will depend on the existing generating plants, pricing mechanisms, capacity for storage or demand management, and other factors. An interconnected electricity grid will already include reserve generating and transmission capacity to allow for equipment failures; this reserve capacity can also serve to regulate for the varying power generation by wind plants. Studies have indicated that 20% of the total electrical energy consumption may be incorporated with minimal difficulty.[37] These studies have been for locations with geographically dispersed wind farms, some degree of dispatchable energy, or hydropower with storage capacity, demand management, and interconnection to a large grid area export of electricity when needed. Beyond this level, there are few technical limits, but the economic implications become more significant. Electrical utilities continue to study the effects of large (20% or more) scale penetration of wind generation on system stability and economics.[38][39][40][41]

At present, a few grid systems have penetration of wind energy above 5%: Denmark (values over 19%), Spain and Portugal (values over 11%), Germany and the Republic of Ireland (values over 6%). But even with a modest level of penetration, there can be times where wind power provides a substantial percentage of the power on a grid. For example, in the morning hours of 8 November 2009, wind energy produced covered more than half the electricity demand in Spain, setting a new record.[42]

Variability and intermittency

Wildorado Wind Farm in Oldham County in the Texas Panhandle, as photographed from U.S. Route 385

Electricity generated from wind power can be highly variable at several different timescales: from hour to hour, daily, and seasonally. Annual variation also exists, but is not as significant. Related to variability is the short-term (hourly or daily) predictability of wind plant output. Like other electricity sources, wind energy must be “scheduled”. Wind power forecasting methods are used, but predictability of wind plant output remains low for short-term operation.

Because instantaneous electrical generation and consumption must remain in balance to maintain grid stability, this variability can present substantial challenges to incorporating large amounts of wind power into a grid system. Intermittency and the non-dispatchable nature of wind energy production can raise costs for regulation, incremental operating reserve, and (at high penetration levels) could require an increase in the already existing energy demand management, load shedding, or storage solutions or system interconnection with HVDC cables. At low levels of wind penetration, fluctuations in load and allowance for failure of large generating units requires reserve capacity that can also regulate for variability of wind generation. Wind power can be replaced by other power stations during low wind periods. Transmission networks must already cope with outages of generation plant and daily changes in electrical demand. Systems with large wind capacity components may need more spinning reserve (plants operating at less than full load).[43][44]

Pumped-storage hydroelectricity or other forms of grid energy storage can store energy developed by high-wind periods and release it when needed.[45] Stored energy increases the economic value of wind energy since it can be shifted to displace higher cost generation during peak demand periods. The potential revenue from this arbitrage can offset the cost and losses of storage; the cost of storage may add 25% to the cost of any wind energy stored, but it is not envisaged that this would apply to a large proportion of wind energy generated. For example, in the UK, the 2 GW Dinorwig pumped storage plant evens out electrical demand peaks, and allows base-load suppliers to run their plant more efficiently. Although pumped storage power systems are only about 75% efficient, and have high installation costs, their low running costs and ability to reduce the required electrical base-load can save both fuel and total electrical generation costs.[46][47]

In particular geographic regions, peak wind speeds may not coincide with peak demand for electrical power. In the US states of California and Texas, for example, hot days in summer may have low wind speed and high electrical demand due to air conditioning. Some utilities subsidize the purchase of geothermal heat pumps by their customers, to reduce electricity demand during the summer months by making air conditioning up to 70% more efficient;[48] widespread adoption of this technology would better match electricity demand to wind availability in areas with hot summers and low summer winds. Another option is to interconnect widely dispersed geographic areas with an HVDC “Super grid“. In the US it is estimated that to upgrade the transmission system to take in planned or potential renewables would cost at least $60 billion.[49]

In the UK, demand for electricity is higher in winter than in summer, and so are wind speeds.[50][51] Solar power tends to be complementary to wind.[52][53] On daily to weekly timescales, high pressure areas tend to bring clear skies and low surface winds, whereas low pressure areas tend to be windier and cloudier. On seasonal timescales, solar energy typically peaks in summer, whereas in many areas wind energy is lower in summer and higher in winter.[54] Thus the intermittencies of wind and solar power tend to cancel each other somewhat. The Institute for Solar Energy Supply Technology of the University of Kassel pilot-tested a combined power plant linking solar, wind, biogas and hydrostorage to provide load-following power around the clock, entirely from renewable sources.[55]

A report on Denmark’s wind power noted that their wind power network provided less than 1% of average demand 54 days during the year 2002.[56] Wind power advocates argue that these periods of low wind can be dealt with by simply restarting existing power stations that have been held in readiness or interlinking with HVDC.[57] Electrical grids with slow-responding thermal power plants and without ties to networks with hydroelectric generation may have to limit the use of wind power.[56]

Three reports on the wind variability in the UK issued in 2009, generally agree that variability of wind needs to be taken into account, but it does not make the grid unmanageable; and the additional costs, which are modest, can be quantified.[58] A 2006 International Energy Agency forum presented costs for managing intermittency as a function of wind-energy’s share of total capacity for several countries, as shown:

Increase in system operation costs, Euros per MW·h, for 10% and 20% wind share[14]

  10% 20%
Germany 2.5 3.2
Denmark 0.4 0.8
Finland 0.3 1.5
Norway 0.1 0.3
Sweden 0.3 0.7

Capacity credit and fuel saving

Many commentators concentrate on whether or not wind has any “capacity credit” without defining what they mean by this and its relevance. Wind does have a capacity credit, using a widely accepted and meaningful definition, equal to about 20% of its rated output (but this figure varies depending on actual circumstances). This means that reserve capacity on a system equal in MW to 20% of added wind could be retired when such wind is added without affecting system security or robustness. But the precise value is irrelevant since the main value of wind (in the UK, worth 5 times the capacity credit value[59]) is its fuel and CO2 savings.

According to a 2007 Stanford University study published in the Journal of Applied Meteorology and Climatology, interconnecting ten or more wind farms can allow an average of 33% of the total energy produced to be used as reliable, baseload electric power, as long as minimum criteria are met for wind speed and turbine height.[60][61]

Economics

Cost trends

Turbine blade convoy passing through Edenfield in the UK.

Wind power has low ongoing costs, but a moderate capital cost. The estimated average cost per unit incorporates the cost of construction of the turbine and transmission facilities, borrowed funds, return to investors (including cost of risk), estimated annual production, and other components, averaged over the projected useful life of the equipment, which may be in excess of twenty years. Energy cost estimates are highly dependent on these assumptions so published cost figures can differ substantially. A 2011 report from the American Wind Energy Association stated, “Wind’s costs have dropped over the past two years, in the range of 5 to 6 cents per kilowatt-hour recently…. about 2 cents cheaper than coal-fired electricity, and more projects were financed through debt arrangements than tax equity structures last year…. winning more mainstream acceptance from Wall Street’s banks…. Equipment makers can also deliver products in the same year that they are ordered instead of waiting up to three years as was the case in previous cycles…. 5,600 MW of new installed capacity is under construction in the United States, more than double the number at this point in 2010. Thirty-five percent of all new power generation built in the United States since 2005 has come from wind, more than new gas and coal plants combined, as power providers are increasingly enticed to wind as a convenient hedge against unpredictable commodity price moves.”[62]

A British Wind Energy Association report gives an average generation cost of onshore wind power of around 3.2 pence (between US 5 and 6 cents) per kW·h (2005).[63] Cost per unit of energy produced was estimated in 2006 to be comparable to the cost of new generating capacity in the US for coal and natural gas: wind cost was estimated at $55.80 per MW·h, coal at $53.10/MW·h and natural gas at $52.50.[64] Other sources in various studies have estimated wind to be more expensive than other sources. A 2009 study on wind power in Spain by Gabriel Calzada Alvarez Universidad Rey Juan Carlos concluded that each installed MW of wind power led to the loss of 4.27 jobs, by raising energy costs and driving away electricity-intensive businesses.[65] The U.S. Department of Energy found the study to be seriously flawed, and the conclusion unsupported.[66] The presence of wind energy, even when subsidised, can reduce costs for consumers (€5 billion/yr in Germany) by reducing the marginal price by minimising the use of expensive ‘peaker plants’.[67]

The marginal cost of wind energy once a plant is constructed is usually less than 1 cent per kW·h.[68] In 2004, wind energy cost a fifth of what it did in the 1980s, and some expected that downward trend to continue as larger multi-megawatt turbines were mass-produced.[69] However, capital costs have increased. For example, in the United States, installed cost increased in 2009 to $2,120 per kilowatt of nameplate capacity, compared with $1,950 in 2008, a 9% increase.[70] Not as many facilities can produce large modern turbines and their towers and foundations, so constraints develop in the supply of turbines resulting in higher costs.[71]

Incentives

Some of the more than 6,000 wind turbines in the Altamont Pass Wind Farm, in California, United States. Developed during a period of tax incentives in the 1980s, this wind farm has more turbines than any other in the US.[72]

Wind energy in many jurisdictions receives financial or other support to encourage its development. Wind energy benefits from subsidies in many jurisdictions, either to increase its attractiveness, or to compensate for subsidies received by other forms of production which have significant negative externalities.

In the US, wind power receives a tax credit for each kW·h produced; at 1.9 cents per kW·h in 2006, the credit has a yearly inflationary adjustment. Another tax benefit is accelerated depreciation. Many American states also provide incentives, such as exemption from property tax, mandated purchases, and additional markets for “green credits“. Countries such as Canada and Germany also provide incentives for wind turbine construction, such as tax credits or minimum purchase prices for wind generation, with assured grid access (sometimes referred to as feed-in tariffs). These feed-in tariffs are typically set well above average electricity prices. The Energy Improvement and Extension Act of 2008 contains extensions of credits for wind, including microturbines.

Secondary market forces also provide incentives for businesses to use wind-generated power, even if there is a premium price for the electricity. For example, socially responsible manufacturers pay utility companies a premium that goes to subsidize and build new wind power infrastructure. Companies use wind-generated power, and in return they can claim that they are undertaking strong “green” efforts. In the US the organization Green-e monitors business compliance with these renewable energy credits.[73]

Full costs and lobbying

A House of Lords Select Committee report (2008) on renewable energy in the UK reported a “concern over the prospective role of wind generated and other intermittent sources of electricity in the UK, in the absence of a break-through in electricity storage technology or the integration of the UK grid with that of continental Europe”.[74]

Commenting on the EU’s 2020 renewable energy target, Helm is critical of how the costs of wind power are cited by lobbyists.[75] Helm also says that wind’s problem of intermittent supply will probably lead to another dash-for-gas or dash-for-coal in Europe, possibly with a negative impact on energy security.[75]

In the US, the wind power industry has recently increased its lobbying efforts considerably, spending about $5 million in 2009 after years of relative obscurity in Washington.[76] By comparison, the US nuclear industry alone spent over $650 million on its lobbying efforts during a single ten year period ending in 2008.[77]

Environmental effects

Livestock ignore wind turbines,[78] and continue to graze as they did before wind turbines were installed.

Compared to the environmental impact of traditional energy sources, the environmental impact of wind power is relatively minor. Wind power consumes no fuel, and emits no air pollution, unlike fossil fuel power sources. The energy consumed to manufacture and transport the materials used to build a wind power plant is equal to the new energy produced by the plant within a few months. While a wind farm may cover a large area of land, many land uses such as agriculture are compatible, with only small areas of turbine foundations and infrastructure made unavailable for use.[6]

There are reports of bird and bat mortality at wind turbines as there are around other artificial structures. The scale of the ecological impact may[79] or may not[80] be significant, depending on specific circumstances. Prevention and mitigation of wildlife fatalities, and protection of peat bogs,[81] affect the siting and operation of wind turbines.

A study on wind farm noise reported that people are annoyed by sound from wind turbines at far less sound levels than they are by noises from railroads, aircraft, or road traffic. The study found the percentage of respondents who found noise levels highly annoying rose quickly as sound levels increased above about 37dbA (about the level of a conversation). [82]

Small-scale wind power

Further information: Microgeneration

This wind turbine charges a 12 V battery to run 12 V appliances.

Small-scale wind power is the name given to wind generation systems with the capacity to produce up to 50 kW of electrical power.[83] Isolated communities, that may otherwise rely on diesel generators may use wind turbines to displace diesel fuel consumption. Individuals may purchase these systems to reduce or eliminate their dependence on grid electricity for economic or other reasons, or to reduce their carbon footprint. Wind turbines have been used for household electricity generation in conjunction with battery storage over many decades in remote areas.

Grid-connected wind turbines may use grid energy storage, displacing purchased energy with local production when available. Off-grid system users can either adapt to intermittent power or use batteries, photovoltaic or diesel systems to supplement the wind turbine. Equipment such as parking meters or wireless Internet gateways may be powered by a wind turbine that charges a small battery, replacing the need for a connection to the power grid.

In locations near or around a group of high-rise buildings, wind shear generates areas of intense turbulence, especially at street-level.[84] The risks associated with mechanical or catastrophic failure have thus plagued urban wind development in densely populated areas,[85] rendering the costs of insuring urban wind systems prohibitive.[86] Moreover, quantifying the amount of wind in urban areas has been difficult, as little is known about the actual wind resources of towns and cities.[87]

A new Carbon Trust study into the potential of small-scale wind energy has found that small wind turbines could provide up to 1.5 terawatt hours (TW·h) per year of electricity (0.4% of total UK electricity consumption), saving 0.6 million tonnes of carbon dioxide (Mt CO2) emission savings. This is based on the assumption that 10% of households would install turbines at costs competitive with grid electricity, around 12 pence (US 19 cents) a kW·h.[88]

Distributed generation from renewable resources is increasing as a consequence of the increased awareness of climate change. The electronic interfaces required to connect renewable generation units with the utility system can include additional functions, such as the active filtering to enhance the power quality.[89]

Research and development

Despite growing worldwide demand for wind energy, present wind technology is not optimized and there are still significant challenges. Most of the research has occurred in industry, and is not always easily shared. According to a research agenda from from a coalition of researchers from universities, industry, and government, supported by the Atkinson Center for a Sustainable Future, wind energy research requires a drastic transformation. According to the report:

The gains that we are seeking require new innovations in fluid dynamics, control, materials, manufacturing, structures, and electric power distribution, as well of new ways of engaging the public in appreciating and accepting this technology, the associated transmission infrastructure and its effects on reducing climate change. Design and analysis tools need to be developed. Common computer codes need to be shared and refined in an open collegial way that cannot occur in industry. Researchers need to disseminate, debate, and share results openly, accelerating innovation in the subject.[90]

See also

References

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  74. ^ House of Lords Economic Affairs Select Committee (November 12, 2008). “Chapter 7: Recommendations and Conclusions. In: Economic Affairs – Fourth Report, Session 2007-2008. The Economics of Renewable Energy”. UK Parliament website. http://www.publications.parliament.uk/pa/ld200708/ldselect/ldeconaf/195/19510.htm. Retrieved September 6, 2009. 
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  76. ^ Cassandra LaRussa (March 30, 2010). “Solar, Wind Power Groups Becoming Prominent Washington Lobbying Forces After Years of Relative Obscurity”. OpenSecrets.org. http://www.opensecrets.org/news/2010/03/solar-wind-power-becoming-prominent.html
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  82. ^ Pederson, Eja (December 2004). Perception and annoyance due to wind turbine noise—a dose–response relationship. Accoustic Society of America. 
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External links

Wikimedia Commons has media related to: Wind power

 

The True Cost of Electricity from Wind Power

November 9, 2011
 

 

 

 
 

 

 

And

Windmill “Availability” Factors

Glenn R. Schleede*
April 2003

Contents
The Questions
The Response
A. True Cost of Electricity from Wind
1. Capital costs, which are generally specific to equipment, site and owner
2. O & M, Repair and Replacement
3. Income Taxes
4. Cost per kilowatt-hour (kWh)
a. Capacity Factors
b. Useful life of turbines
5. Extra costs of electricity from wind because of intermittence, variability, unpredictability and uncontrollability of electricity output from wind turbines
a. Cost of backup generation
b. Transmission costs
c. Extra grid management burden
d. Arbitrary assignment of costs
e. Penalties in competitive markets
f. Who bears the costs?
g. Shifting of costs from “wind farm” owners to electric customers by regulation
6. Tax breaks and subsidies for “wind farm” owners
a. Tax breaks
1) The Federal Production Tax credit
2) Five-year double declining balance accelerated depreciation (5-yr., 200% DB).
3) Reduction in state corporate income tax due to federal accelerated depreciation
4) Reduction in state and local property, sales, and other taxes
b. Subsidies for the wind industry
1) Federal subsidies
2) State subsidies
3) Renewable portfolio standards – an insidious subsidy
4) “Green” energy programs
B. Availability, Capacity Factors and “Homes Served”
1. Availability factors
2. Capacity factors
3. “Homes served”
Endnotes
 

Question:

Do you have a simple one-page analysis of the current cost of wind power, before and after tax subsidies, and the availability factors of most windmills?

Response:

The short answer is “No.” In fact, it will take:

  • • Several pages to identify and describe the many elements of the full, true cost of electricity from wind (the relative importance of the elements varies widely.), and
  • • Another 2 pages to explain why “availability” factors are meaningless when talking about windmills, and why “capacity” factors are more important but still limited in value.

However, the questions are good ones because:

  • • The information on the cost of electricity from wind power that is distributed by all of the following groups is grossly incomplete and misleading:
  • • US Department of Energy’s (DOE) Office of Energy Efficiency and Renewable Energy.
  • • DOE’s National Renewable Energy Laboratory (NREL).
  • • The wind industry and its Washington-based trade association and lobbyists.
  • • Information distributed by the same organizations about wind turbine “availability” is meaningless.

To help answer your question, this paper will identify the many elements of the full, true cost of electricity from wind energy, including the elements of true cost that the above organizations like to ignore. It will also explain why the “availability” of wind turbines is meaningless.

While this paper does NOT provide the specific answer you are looking for, it may prove helpful to many people around the US (as well as Europe, Australia and New Zealand) who are trying to learn the truth about the cost of electricity from wind energy.
 

A. True Cost of Electricity from Wind

Note that this paper focuses on the true cost of producing and delivering electricity from wind and not on the price paid when a utility buys electricity from a “wind farm.” This latter number will often have no relationship to the true cost because of the extensive subsidies available to “wind farm” developers and owners. In fact, in the early years of a “wind farm’s” operation the value of tax breaks and subsidies generally will exceed substantially the income that a “wind farm” owner will receive from the sale of electricity!

In summary, good cost numbers for electricity from wind are not now available because:

  • Like all generating units, the true costs vary depending on equipment, site, ownership, etc.
  • Only the “wind farm” owners have numbers approaching accounting quality on costs and even those numbers will often be based on assumptions (e.g., O&M costs over the life of a facility; cost per kWh). In any case, owners probably will consider this data confidential.
  • Some parts of the full, true costs of producing and transmitting electricity from wind turbines (e.g., backup generation, extra costs imposed on transmission and grid management) vary widely depending on the control area involved, the unit or units providing backup generation, the output and variability of output from the generator, load on the grid, etc. etc.
  • Some tax breaks and subsidies are somewhat fixed but others vary, for example, with actual production of electricity – which, when estimating future kWh costs, are based on assumptions and guesses (e.g., the useful life of a facility).
  • In fact, except for money already expended and future costs that are locked in (e.g., in contracts), most estimates depend on assumptions, particularly the cost per kWh numbers.
  • Thus far, the US DOE, the National Renewable Energy Laboratory (NREL), the wind industry and other wind advocates have shown little interest in providing citizens, consumers and taxpayers with complete, objective information on true costs – possibly because such information would call into question many of their promotional activities.

Many of the elements of cost identified in the pages that follow have “counterparts” in the case of generating units powered by energy sources other than wind (e.g., interconnection costs). However, it is also the case that many of the cost elements differ (e.g., transmission costs).

Of all the points about wind energy discussed below, those that deserve particular attention include:

  • The fact that very high profits due to generous tax breaks and subsidies for “wind farms” – not claimed environmental benefits — are probably the principal motivation for investments now being made in “wind farms.” Often, “green washing” will be part of the motivation.
  • The high capital costs of “wind farms.”
  • The high transmission costs, particularly when wind farms are remote from where electricity is needed and because electricity from wind uses transmission capacity inefficiently.
  • Due to the intermittence, variability, and unpredictability of electricity from wind, it has less real value in an electric system than electricity from “dispatchable” sources.
  • The small amount of electricity produced by wind turbines, particularly due to their inherently low capacity factors. If all the thousands of windmills in the US as of the end of 20021 operated with a 25% capacity factor, they would produce less electricity (10,260,150,000 kilowatt-hours – kWh) than two 750-megawatt (MW) gas-fired combined cycle generating plants operating in base load with an 80% capacity factor (10,512,000,000).2 The windmills are scattered over thousands acres in 27 states (90% in CA, TX, IA, MN, WA and OR), while the gas-fired plants would take up only a few acres. Also, they are available when needed (i.e., dispatchable), not just when the wind blows.
  • The fact that the useful life of today’s wind turbines and their lifetime O&M, repair and replacement costs are unknown.

EIA data on costs of windmills. While the data do not answer your question, you may want to note that the US Energy Information Administration (EIA) – which does seek to provide objective information – does make some estimates of costs associated with electricity from wind for use in preparing its Annual Energy Outlook. EIA estimates include (a) total overnight capital cost including contingency for wind – $1,003 per kW, (b) variable O&M – $0, (c) fixed O&M of $26.10 per kW –all in 2001$.3

EIA also makes estimates of interconnection costs which are not peculiar to wind but which vary by region from $175 to $457 per kW (in 2001$). Finally, EIA provides estimates for adding transmission capacity to serve “wind farms, which include data for situations requiring transmission in the 0-5 mile range ($8.74 to $15.23 per kW, depending on region), 5-10 mile range ($26.23 to $45.70 per kW), 10-20 mile range ($52.47 to $91.40 per kW) all in 2001$.4

EIA indicates that its staff consults with wind experts when developing its estimates and assumptions. While such EIA estimates are essential when making forecasts about future energy markets, the data are not the type and quality required to assess costs and benefits associated with specific wind energy projects.

The next 9 pages identify and describe elements of the full, true costs of producing and transmitting electricity from wind turbines. As indicated earlier, data on the full, true costs are not now available.


1. Capital costs, which are generally specific to equipment, site and owner

a. Turbines, blades, etc. (including everything mounted at the top of towers). There are a wide variety of turbines available and at least 10 turbine manufacturers, most foreign (e.g., Vestas, NEG Micron, Mitsubishi). GE manufactures some in the US and some in Europe. Vestas often talks of building a plant in Portland, OR. The price undoubtedly varies with demand at the time, quantity, currency exchange rates, and more.

b. Towers. Again, there are a variety of styles and heights. Some are made in the US; others are imported.

c. Base. Lots of concrete – but amount undoubtedly depends on soil conditions, terrain, tower height, turbine size, wind conditions, transportation to site, etc.

d. Access roads and clearing of land. Again, these costs are affected by terrain and other local conditions.

e. Computer equipment, cabling, controls, etc. all vary somewhat from one project to another.

f. Interconnection costs (substations, etc.) – to permit delivering electricity from a “wind farm” to transmission lines that can deliver electricity to places where it is needed.

g. Transmission lines to move the electricity from a “wind farm” to the nearest transmission lines that can move the electricity to places where it is needed. As illustrated by the EIA data cited above, these costs vary widely by region and specific project, particularly due to distance, terrain and availability of rights of way. Also, as noted below, in paragraph 5.b., electricity produced by wind turbines use transmission capacity inefficiently. Since acceptable sites for “wind farms” are often distant from where the electricity is needed, both transmission costs and line losses tend to be high.

h. Cost of development (which can be capitalized if the project becomes operational but must be written off immediately if the project isn’t built). This includes the cost of gaining land use and zoning approval from local and/or state authorities that regulate such projects. Costs vary widely and often include significant fees for lawyers, public affairs/lobbyists, and engineers involved in the effort to gain approval. In addition, developers are generally liable for damage to existing infrastructure (e.g., roads) caused by “wind farm” construction. Some states (e.g., New York, Illinois) are now offering up-front grants that may defray some or all of these costs but, as discussed later, the money used to provide these subsidies is often collected from electric customers via charges added to monthly electric bills (so-called “public benefit charges”) so they are still a part of the full, true costs of electricity from wind.

i. Cost of financing: These cost depend on such factors the owner’s credit rating, the proposed debt-equity ratio, the market for the electricity that would be produced, and whether a contract is in place for its sale.

j. Payments in lieu of taxes: Sharp reductions or exemptions from local government property taxes – which are provided in several states – creates a situation where “wind farm” owners can appear magnanimous by making “voluntary” payments to counties, towns and schools to help cover costs. Such payments tend to be much less than the taxes that have been forgiven.5

k. Land. If owned and capitalized. (Or, if leased, lease rates and terms – see below.)

l. Decommissioning cost (if capitalized). (FYI, I generally urge that landowners insist that decommissioning costs be covered by cash bonds held by independent third parties because many wind farm “owners” turn out to be LLCs with few assets. Because tax breaks for wind are heavily front-loaded (depreciation – 5-6 years; production tax credit – 10 years), there are huge incentives for sales of facilities after tax breaks are used, or for abandonment if costs of maintenance, repair and/or replacement rise substantially. There is little protection for landowners from surety bonds that depend on premium payments or cash bonds held by an LLC-owner – in case of insolvency or abandonment.)


2. O&M, repair and replacement

There are many variables here, too, and some big unknowns:

a. Actual operating experience is probably around 5 years for the smaller (660 kW – 750 kW) turbines, 2 or 3 years for the 1.5 MW, and a few months for the really big ones like GE’s new 3.6 MW turbine. Anyone claiming to have solid numbers may not be telling the truth. (Also, some manufacturers have had costly problems – e.g., with gearboxes – on big, relatively new machines.)

b. Useful life of the turbines (see a., above).

c. Land rent can be expensed. Most land seems to be rented with prices seeming to vary from around $1,500 per MW of capacity to alleged offers as high as $15,000 per MW. Some are fixed payments and some vary with amount of electricity produced.

d. Insurance.

e. Property, sales, use and other taxes: Due to a variety of tax breaks (discussed below, with examples), the tax burden on “wind farms” is very low.

f. Monitoring and Response Costs. Cost of monitoring and response, if any. This might include monitoring and responding to noise complaints, and/or icing and other dangerous conditions. Some municipalities may require establishment and maintenance of a “Complaint Hotline” and/or periodic reporting to ensure compliance with terms of the conditional use permit.

g. Decommissioning (see paragraph 1.l., above).


3. Income taxes

Again, due to very generous federal and state corporate income tax breaks (discussed below), the income tax burden, if any, on the “wind farm” owner may be very low.


4. Cost per kWh

DOE, National Renewable Energy Lab (NREL) and the wind industry often cite cost per kWh numbers but seldom, if ever, provide the assumptions underlying their estimates. Actual cost per kWh will vary widely depending on all the items identified above, but two variables have an especially large impact on actual average cost per kWh of electricity from wind:

a. Capacity factors.6 Actual costs per kWh depend on the number of kWh of electricity actually produced. For example, wind speed is one critical factor in determining the amount of electricity produced and wind speed varies widely with stronger wind tending to occur at night and in colder months. Wind speed measurements taken during winter months are atypical. Wind characteristics also vary by height of the measurement and are affected by terrain.

Actual capacity factors and actual kWh production tend to be less than claimed by “wind farm” developers. Also, published estimates of “wind resources” and “wind classes” in various areas may be based on limited empirical data.

b. Useful life of turbines. Estimates of cost per kWh also depend heavily on assumptions about the useful life of turbines (which is a big unknown because of limited experience with machines now being used). Obviously, the numbers will be a lot different if one assumes 20-year life or 30 year life (i.e., take total estimated costs and divide by kWh produced over 20 years vs. over 30 years).

Published estimates of lower per kWh costs of electricity from wind are often based on vague assumptions (e.g., wind conditions, site availability, bigger machines, higher efficiency, “economies of scale”) or guesses that may or may not prove to be correct.


5. Extra costs of electricity from wind because of the intermittence, variability, unpredictability and uncontrollability of electricity output from wind turbines

As indicated, these costs vary widely depending on the control area involved, the location of the “wind farm,” unit or units providing backup generation, the output and variability of output from the “wind farm,” the share of capacity on line coming from wind turbines, the location and amount of load on the grid at the time, the capacity of the transmission lines, etc.

The problem stems from the fact that wind turbines produce electricity only when the wind is blowing with the right speed ranges. For example, the forty-four 1.5 MW turbines employed at FPL Energy’s Mountaineer Energy Center (Backbone Mountain, WV), according to the turbine manufacturer (NEG Micon), begin producing electricity when the wind reaches about 3 meters per second (or 8.9 miles per hour, achieve rated capacity at about 15 m/s (or 33.6 mph) and cut out at 25 m/s (or 55.9 mph).

a. Cost of backup generation

Since the grid or control area must be kept in balance at all times (supply and demand, frequency, voltage), some generating unit(s) must be immediately available at all times to provide backup service (or balance) for the electricity (if any) coming from the wind turbines. This means that the unit(s) providing the backup service may be operating in an automatic generation control mode, running at less than peak capacity, and/or running in spinning reserve mode.

Depending on wind conditions, the amount of backup capacity may have to equal the peak capacity of a “wind farm.” That is, if wind conditions exceed the cutout speeds, the entire output of the “wind farm” could be lost.

All the potential modes result in costs – and those costs are properly allocated to the cost of the electricity from wind turbines.

Some limited empirical work has been done to define these costs but it is quite limited – in terms of the period of time covered and the location(s) studied.7 There is no universally applicable, empirically based cost estimate available.

These “costs” may, at some point, be established in wholesale ancillary service markets. PJM, for example, apparently has created or is experimenting with such a market for spinning reserve capacity.

Almost certainly, a control area that has significant hydro capacity in reasonably close proximity to a “wind farm” would have relatively low backup generation costs because of the excellent load-following characteristics of hydro generation. That is, assuming that variation in the flow of water through the hydro plants can be accommodated within constraints on the hydropower facility (e.g., levels of water in the reservoir and in the river downstream of the plant). However, actual backup power costs are likely to be higher when generation is powered by other energy sources.

b. Transmission costs

As indicated earlier, electricity from wind turbines generally makes inefficient use of the transmission capacity that serves the turbines. Enough capacity must always be available to handle the peak output of a “wind farm.” However, that peak output is unlikely to occur more than about 30% of the time. The capacity may not be used at all by the electricity from wind turbines for 50 to 70% of the time. Also, as noted above, tend to be high because acceptable sites for “wind farms” are often distant from load centers – which mean both higher capital costs due to longer lines and greater line losses of electricity.

In some cases, heavy concentration of wind turbines has made it necessary to add transmission capacity to serve the output from “wind farms” (e.g., Texas, Minnesota, Nordel Grid in Europe).

c. Extra grid management burden

The presence of variable output from “wind farms” quite likely imposes some extra costs for the management and control of the grid or control area. These costs may be minor if the electrical output from the “wind farms” is small and/or it can be handled with automatic generation control.

d. Arbitrary assignment of costs

The owners or managers of some control areas have adopted somewhat arbitrary cost factors to compensate for the above-described costs (e.g., Bonneville Power). Several studies are underway to get a better fix on the true costs but they are complicated by the wide variability in true costs.

e. Penalties in competitive markets

Some grid owners or managers have applied penalties to electric generator owners or operators who deliver more or less electricity to a transmission system than was bid into the system. Often these penalties are designed to (a) encourage generating companies to help keep the grid in balance by delivering amounts of electricity promised, when promised, (b) pay for costs imposed when electricity delivered differs from contracted amounts, and (c) discourage “gaming.” The wind industry has complained that such penalties are inappropriate for wind because of its inherent intermittence, variability and unpredictability. Bonneville –under pressure from the industry and DOE wind advocates– recently reduced its imbalance penalty.

f. Who bears the real costs?

In some cases, all or a part of the costs of a., b. and/or c. above, have been imposed on a “wind farm” owner. In other cases, it appears that the purchaser of the output from a “wind farm” pays a specified amount for each kWh of electricity and absorbs the extra costs.

Unless the costs are clearly assigned to and paid by the “wind farm” owner, it is quite likely that they are rolled through and spread over all of an electric suppliers customers – probably without the knowledge of those customers.

g. Shifting of costs from “wind farm” owners to electric customers by regulation

FERC apparently has approved an approach developed in California – and favored by the wind industry – which limits penalties associated with the impact of electric from “wind farms” on transmission. Also, the Minnesota PUC recently approved a $148 million expansion of Xcel’s transmission capacity in Southwestern Minnesota that Xcel claimed was necessary to serve planned new “wind farms.” Those costs apparently will be included in rate base and spread over all Xcel’s Minnesota customers – rather than being allocated to the owners of the planned “wind farms” that will make the expenditures necessary.

Also, the American Wind Industry Association (AWEA), the industry’s Washington-based lobbyists, have a major effort underway to shift the costs of transmission of electricity from wind turbines away from “wind farm” owners.8


6. Tax breaks and subsidies for “wind farm” owners

Some of the above elements of the full, true costs of electricity from wind are dwarfed by the value of tax breaks and subsidies available to “wind farm” owners:

a. Tax breaks

Of course, tax breaks for “wind farm” owners don’t show up directly in electric bills but, nevertheless, are part of the full, true cost of electricity from “wind farms.” These tax breaks shift costs from the “wind farm” owners to remaining taxpayers. Important tax breaks include:

1) The Federal Production Tax Credit (currently $0.018 per kWh but the rate is adjusted for inflation) which is available for the first 10 years of operation of the wind facility.

2) Five-year double declining balance accelerated depreciation (5-yr., 200% DB)9  – a generous form of MACRS (Modified Accelerated Cost Recovery System) now available in federal tax law is available to “wind farm” owners. This benefit permits a wind farm owner to recover the full amount of his capital investment in 5 to 6 years through depreciation deductions from income. (This compares with 20-year, 150% DB accelerated depreciation for most other generating units. Simple cycle gas turbines qualify for 15-year, 150% DB.)

The depreciation deductions by tax year for commercial wind energy facilities are:

  1st Year 2nd Year 3rd Year 4th Year 5th Year 6th Year
“Normal” DB1 20% 32% 19.2% 11.52% 11.52% 5.76%
“Bonus” DB2 44% 22.4% 13.44% 8.064% 8.064% 4.032%
  1. Under “Normal” 5-yr. 200% DB; 2. Under “Bonus: 5-yr. 200% DB” established by the Job Creation and Worker Assistance Act of 2002 which applies to qualifying assets purchased after September 10, 2001 and before September 11, 2004, provided those assets are placed in service by January 1, 2005.

Accelerated depreciation produces huge tax avoidance benefits in the first few years of project ownership. The value of this accelerated depreciation is higher under the “bonus” arrangements described above. However, those are scheduled to end by January 1, 2005, so the value of accelerated depreciation will be illustrated here using the “Normal” deduction schedule described above – which is still exceedingly generous to “wind farm” owners.

To illustrate the value, assume that a 100 MW (100,000 kW) “wind farm” has a capital cost of $1 million per MW (i.e., total capital cost of $100,000,000 million) and comes on line after the “Bonus” provisions have expired, let’s say after January 1, 2005. Regardless of when it comes on line after that (i.e., anytime from January 2, 2005 to December 31, 2005, the owner can take a $20,000,000 depreciation deduction from income for the 2005 tax year.10 With a 35% marginal tax rate, the “wind farm” owner could reduce his federal income tax liability by $7,000,000 BEFORE taking advantage of the federal Production Tax Credit.

If the wind farm began operation on July 1, 2005, and produced at an annual average 30% capacity factor for the rest of the year, it would produce 132,480,000 kWh (100,000 kW x 4416 hours x .30 capacity factor). Therefore, the value of the depreciation deduction in 2005 in reduced federal tax liability would be equal to $0.0528 per kWh ($7,000,000 divided by 132,480,000 kWh).

When the $0.018 per kWh production tax credit is added, the value of the two federal tax benefits in 2003 would add up to $0.0708 per kWh.

In the second year 2006), the owner would be able to take a $32,000,000 deduction from income. With a 35% marginal tax rate, the “wind farm” owner could reduce his federal income tax liability by $11,200,000 BEFORE taking advantage of the federal Production Tax Credit. If the “wind farm” averaged a 30% capacity factor for all of 2006, it would produce 262,800,000 kWh. The value of the reduction would equal $0.0426 per kWh in 2006, not counting the $0.018 per kWh PTC.

When the $0.018 per kWh production tax credit is added, the value of the two federal tax benefits in 2003 would add up to $0.0606 per kWh.


3) Reduction in state corporate income tax due to federal accelerated depreciation

In most states, accelerated depreciation available to wind energy facilities can also be used to reduce state corporate income tax liability. For example, in a state that fully conforms its corporate income tax to the federal system and has a 10% corporate tax rate, the “wind farm” owner could reduce its state income tax liability by $2,000,000 in 2005, or the equivalent of an additional $0.015 per kWh for a “wind farm” that began operation on July 1, 2005, with a 30% capacity factor. In 2006, the “wind farm” owner could reduce tax liability by $3,200,000 or the equivalent of and additional $0.012 per kWh.


4) Reduction in state and local property, sales and other taxes

Several states have also reduced or eliminated other taxes and, therefore, shifted more costs from “wind farm” owners to remaining taxpayers. Here are a few examples:

  • • Iowa exempts materials used in constructing wind farms from sales and use taxes and has sharply reduced property taxes (eliminating them totally in the first year, then raising them in 5% increments until reaching 30% of normal property taxes.
  • • West Virginia has reduced both Business & Occupation Taxes and Property taxes for “wind farms” by about 90%.
  • • Wisconsin, Minnesota and Kansas exempt wind facilities (i.e., the value added, not the land) from property taxes.
  • • North Dakota exempts large wind project equipment from sales tax and provides a 70% reduction in property taxes.


b. Subsidies for the wind industry

There are many subsidies available to the wind industry in addition to the tax breaks identified above. For example:

1) Federal subsidies, all of which shift costs from the wind industry to taxpayers, include:

  • • Some $38 million per year for US Department of Energy “wind energy R&D”.
  • • Promotional “studies,” “analyses,” “reports,” web sites, and conferences paid for with tax dollars flowing through DOE’s Office of Energy Efficiency and Renewable Energy, and carried out by DOE employees and employees of DOE National Labs and other contractors, grantees and subcontractors.
  • • Renewable Energy Production Incentive (REPI) which provides direct per kWh payments to organizations that do not pay income taxes (e.g. rural electric coops, municipal utilities) – at the same per kWh rate as the Production Tax Credit.

2) State subsidies

Some of these may be paid from general tax revenues but many are paid from so-called “public benefit charges” added to electric customers’ monthly bills – which charges raise well over $1 billion per year. Examples of such subsidies include but are not limited to:

  • New York and Illinois – Grants to “wind farm” developers (In NY, $22 million have been announced).
  • California – Payments to customers who agree to buy electricity produced from “renewable” energy sources (this program may be suspended at present).
  • Minnesota – State production tax credits.
  • New Mexico – Use of industrial development bonds.


3) Renewable portfolio standards – an insidious subsidy

Renewable portfolio standards (RPS) adopted by several states are another form of subsidy for “wind farm” owners. Such standards are a particularly insidious subsidy since they force higher costs on millions of electric customers without their knowledge. The standards force suppliers of electricity to purchase electricity from “wind farms” or other “renewable” energy facilities, generally without regard to its higher cost. In some cases, a few electric customers who agree voluntarily to pay a premium price – through so-called “green” energy programs – for electricity produced from “renewable” sources pay part of the extra cost. However, the remaining cost of the electricity, as well as the cost of administering the voluntary programs is passed on to electric customers in their monthly electric bills.


4) “Green” energy programs

Many electric utilities have established programs that permit customers to volunteer to pay premium prices for electricity generated from “renewable” energy sources (with varying definitions of “renewable). Some utilities adopt these programs voluntarily and others are mandated by state statutes or regulations. Typically, only a very small percentage of customers volunteer to pay premium prices – in fact so small that the premium revenue is unlikely to cover the extra cost of buying or producing the “green” electricity and the cost of administering the program. When this occurs, the portion of costs not recovered from volunteers is likely to be spread over all electric customers.

B. Availability, Capacity Factors and “Homes Served”

Wind energy advocates often mislead the public, media and government officials with claims about “availability” and “homes served.”

1. Availability factors are meaningful for generating units that are “dispatchable” (i.e., can be called upon to produce electricity whenever needed) but are meaningless for “intermittent” generating sources such as windmills which can produce electricity only when the wind is blowing within certain speed ranges.

In fact, electricity from wind turbines is of less value than electricity from “dispatchable” generating units because it is available only when the wind is blowing within certain speed ranges. In electric industry terms, it has very little, if any, “capacity” value. It provides “capacity” value only if the wind happens to be blowing when electric demand is at high levels (at or near peak). Winds are not uniform throughout a day or year. Instead, winds tend to be strongest at night and in cold months while many electric systems in the US experience highest demands during summer afternoons.

The wind industry often talks about “availability factors” which the industry seems to define as time when the wind generation equipment could be generating if wind was available within the right speed ranges. Such use of “availability” is totally misleading and deceptive.

2. Capacity factors. Capacity factors for wind turbines and “wind farms” are somewhat more meaningful since they are a measure of kilowatt-hours (kWh) actually produced by the wind turbines. Capacity factors are determined by dividing kWh produced by the rated (“nameplate”) capacity of the turbine(s) times the hours in the period for which the factor is calculated – usually a year or a month.

Capacity factors are not totally meaningful because, as indicated above, the kWh may be generated at a time when the electricity isn’t really needed – and when electricity is available at less cost from other generating sources.

Capacity factors vary WIDELY for many reasons, including wind “class” or wind speed (which varies by location, turbine height, terrain, windmill spacing, obstructions, etc.), vintage of the turbines, condition of the turbine and blades and the specific turbine technologies, time of day and year. For example:

  • • Smaller old turbines in California built in response to the unwise tax credits of the 1980s, it they are running at all, probably have capacity factors in the 5% to 20% range.
  • • A turbine in Traverse City, Michigan, has achieved a 15.1% capacity factor during a 5+-year period for which data are available (through the fall of 2002) while one in Mackinaw, MI has achieved an 18% capacity factor.
  • • Some of the “wind farms” in Wisconsin have had capacity factors in the low and mid 20 percentages.
  • • Data on electricity output from “wind farms” reported to EIA (on EIA Form 906) include factors ranging from about 10% to 36%.
  • • The Northwest Power Planning Council uses 33-34% capacity factors when estimating the output of wind farms in Washington and Oregon.
  • • FPL Energy used an implicit capacity factor of 38.15% when “bidding” into California Energy Commission’s “Production Incentive” auctions #2 and #3.
  • • Some in the wind industry claim that newer turbines (generally on taller towers) will achieve capacity factors in the 40s.

In summary, many factors must be taken into account when picking a capacity factor. Also, landowners that are considering renting their land under agreements where payments depend on actual electricity production need to recognize that “wind farm” developers have an incentive to overestimate potential capacity factors – if they are not contractually bound by those numbers.
3. “Homes served”

Once of the highly deceptive measures of “wind farm” output widely used by DOE, NREL, the wind industry and other wind energy advocates is “homes served.” That measure is somewhat meaningful when referring to a “dispatchable” generating unit. It is meaningless when referring to electricity from “wind turbines” which produce electricity only intermittently. In fact, NO homes are served by electricity from wind because electric customers – at least in those served by electric distribution systems – in the US and most developed nations are unwilling to “live with” electricity service that is available only when the wind is blowing in the right speed range.

Endnotes

1 The American Wind Energy Association (AWEA) reports that capacity at the end of 2002 totaled 4685 megawatts.
2 Such gas-fired units are being built in various areas around the US. The calculations of potential windmill output are 4,685 MW x 8760 hours x .25. The assumed capacity factor may be too high because many of the windmills are old ones built in response to tax credits of the 1980s. The calculation for the gas-fired combined cycle plants are 1,500 x 8760 x .80. Other interesting comparisons are that all the wind turbines would produce less electricity than either the Surry or North Anna nuclear plants in Virginia produced in 2001 (12,662,376,000 kWh and 13,096,754,000 kWh, respectively) or the Mt. Storm coal-fired generating plant in West Virginia in 2000 (11,595,299,000 kWh).
3 EIA, Assumptions to the Annual Energy Outlook 2003, Table 40, page 73. EIA estimates of the cost of generation units and cost of transmission apparently are assumptions based on staff discussions with DOE, National Lab and wind industry experts. Presumably most are nationwide averages that don’t reveal likely variability among specific projects.
4 EIA, NEMS Renewable fuels Module Documentation Report – Wind, pp. 39-40.
5 Schleede, Glenn R., Energy Market & Policy Analysis, Inc. “Wind Energy Economics in West Virginia,” pp.8-9.
6 Capacity factors are determined by dividing kWh produced by the rated (“nameplate”) capacity of the turbine(s) times the hours in the period for which the factor is calculated – usually a year or a month.
7 Among recent reports dealing with the problems and extra costs of integrating electricity from wind turbines with bulk power systems are the following:
 a. “Assessing the impact of wind generation on System Operations at Xcel Energy – North and Bonneville Power Administration,” a study for the Utility Wind Interest Group (UWIG) by Electrotek. < http://www.uwig.org/opimpactspaper.pdf  >.
 b. Eric Hirst, “Integrating Wind Energy with the Bonneville Power System – Preliminary Study,” September 2002: < http://www.ehirst.com/PDF/BPAWindIntegration.pdf >.
 c. Eric Hirst, “Integration of Wind Farms with Bulk Power Operations and Markets, September 2001: < http://www.ehirst.com/PDF/BPAWindIntegration.pdf >.
 d. “Non-Dispatchable Production in the Nordel Network,” by Nordel’s Grid Group, May 2000. (Nordel is the network that serves Denmark, Sweden, Norway and Finland. This report (which I can provide) describes the problems caused by Denmark’s extensive production of electricity from wind and by combined heat and power units. It’s not typical of anything found in the US but illustrates the problems and the costs of extensive dependence on wind for electricity).
8 The effort is described in a 20-page “White Paper” that can be found on AWEA’s website < http://www.awea.org/policy/documents/Transmissionwhitepaper12-2002.pdf >.
9 DB = Declining balance.
10 The depreciation deduction in the first year (20%) is less than the second year (32%) because the IRS prescribes the “half-year convention” which permits deducting one half-years depreciation in the first tax year, regardless of when the facility actually begins operation during that year. See IRS Publication 946.
_____
Used with permission of the author.
* This analysis was prepared by Glenn R. Schleede, April 7, 2003
Energy Market & Policy Analysis, Inc.
PO Box 3875, Reston, VA 20195-1875
Email: EMPAInc@aol.com

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Overblown: The Real Cost of Wind Power

November 9, 2011

By Peter Glover and Michael Economides

 

Windfarm in the North of England

If you have a hankering to see Britain’s green and pleasant countryside or its rugged coastline, you shouldn’t wait too long. They are both likely to disappear soon under thousands of massive, swirling, 400-foot wind turbines. Recently, U.K. Industry Secretary John Hutton announced that the British government is planning 25 gigawatts of offshore wind power capacity, adding to the 8 GW already in development. A grand plan that could, in theory anyway, power all of Britain’s 25 million homes by as early as 2020.

Wind seems to be blowing in the minds of the politically correct and those on the environmentalist bandwagon. But the cost is going to be huge, no companies will plunge into it without massive government subsidies, and should the turbines actually be built, power reliability will almost certainly take a nosedive.

The extent of Britain’s wind power commitment can be shown by the fact that by itself, the 8 GW capacity under construction will give Britain world leadership in installed wind power production. So why is Britain jumping ahead?

Wind power has become the energy source du jour, the darling of (most) environmental groups and governments. Currently, just 2 percent of the U.K.’s power comes from renewable energy sources, with wind providing less than 0.5 GW of the total generation capacity. Hutton’s plan would mean an astonishing leap for the British wind power industry. Of the 8 GW in capacity that’s currently planned, the London Array, with 271 wind turbines to be built in the Thames estuary, will be the world’s largest plant, providing 1 GW of nominal capacity by itself. The London Array should be operational by 2014 and is expected to power 750,000 homes. But it would be upstaged by an even bigger project currently under consideration: the proposed $6 billion Atlantic Array, which would consist of 350 turbines off the southwest coast of England.

Hutton’s plan would literally change the face of Britain. On the BBC’s “Politics Show” he recently said the plan will result in roughly 7,000 turbines – astoundingly, one every half-mile around the entire coast of Britain. His justification: “There is no way of making the shift to low-carbon technology without there being change and for that change to be visible and evident to people.” So there will be enormous aesthetic, environmental, and economic costs – costs driven primarily by the belief that man’s carbon emissions are the main cause of the world’s global warming of 1 degree or so over the last century.

Who Will Pay for the Plan?

While the renewables-at-any-cost lobbies applauded Hutton’s announcement, the more realistic wind energy groups were a bit more circumspect. Welcoming the commitment to the goal of greater wind power sufficiency, the British Wind Energy Association’s Gordon Edge called the government’s plan “pie in the sky.” Edge’s view is that the plan suffers from one major flaw: private capital investment will not be forthcoming. Dan Lewis, of the Economic Research Council, adds his opinion that the British government is “deluding itself on a grand scale. There will be no race by investors to build offshore wind farms.” These voices recognize that, to date, the taxpayer has picked up the wind power tab.

Despite U.K. wind industry subsidies of over $500 million, so far such a massive investment has only provided less than 0.5 percent of the U.K.’s electricity needs. In August 2007, the BBC’s Radio 4 “Costing the Earth” program reported that the government’s financial incentives were encouraging wind industry firms to take advantage of massive government subsidies and build wind farms on non-viable sites across the mainland. So it seems winds are too variable even in Europe’s windiest country, with most turbines consistently underperforming as a result. (For more on the “Costing the Earth” report, see “U.K. Wind Blown Off Course,” ET, October 2007.) Jim Oswald, a consulting engineer, analyzed figures submitted to Ofgem (the U.K.’s electricity watchdog) on each wind farm’s load factor. He explained to the BBC, “It’s the power swings that worry us. Over a 20-hour period you can go from almost 100 percent wind output to 20 percent.”

A “load factor” of just over 30 percent is recommended for a wind farm to be economically viable. However, many of Britain’s onshore farms have been running at around 20 percent, with some in urban areas dropping as low as 9 percent. Oswald believes that overly relying on wind power will result in major power failures across the U.K. and an increase of up to 50 percent in electricity bills. While nothing comes close to the capricious aspect of nature itself, the industry also still suffers from some severe technical difficulties.

In August 2007, Germany’s Der Spiegel reported the rising incidence of “mishaps, breakdowns and accidents” associated with ever-larger turbines. When one rotor blade broke away in Oldenburg in northern Germany, an examination of six other turbines was ordered. The results proved so alarming that the authorities immediately ordered four to be shut down. The same Der Spiegel article noted that manufacturers’ claims that turbines would last for 20 years have proven hollow. Indeed, it appears that they are not allowing time for proper stress-testing procedures. And even though global demand for turbines is growing at double-digit rates, German manufacturers cannot keep up. That’s a remarkable fact, given that the German wind power industry now employs some 74,000 people.

Industry insider Jerome à Paris, writing on the Oil Drum: Europe Web site as recently as December 2007, admitted that the industry is still suffering from “unresolved technical difficulties with some turbine models that have been withdrawn from the market.” Since turbines are the industry’s backbone, this has undoubtedly proven a key deterrent for prospective investors – except for prospective government investors, apparently.

Much has been written about Denmark’s success as the world’s wind power pioneer. But the regularly repeated claim – that Denmark generates 20 percent of its electricity demand from wind sources – is highly misleading. That 20 percent of electricity is not supplied continuously from wind power. Denmark’s wind supply is so variable that it relies heavily on neighbors Norway and Sweden, taking their excess production. In 2003 its export figure for wind power electricity production was as high as 84 percent, as Denmark found it could not absorb its own highly variable wind output capacity into its domestic system. The scale of Denmark’s subsidies was such that in 2006-07 the government increasingly came under scrutiny from the Danish media, which claimed the subsidies were out of control.

Back in Britain, the high maintenance costs associated with the same problems Germany and Denmark have lately reported – ones that can only be exacerbated by even larger offshore plants – are yet to be reaped. Once again, the inability to store a highly variable power output while also sustaining a consistent supply to the U.K. national grid, present major problems. Considering those problems on top of the enormous unresolved technical problems with turbines, it becomes increasingly easy to understand why it takes the political will of government to bridge the private investment gap.

In a recent U.S. report about Silicon Valley’s investments in clean-energy technologies, Vinod Khosla, founder of Khosla Ventures, said, “I worry about over-investing from firms that don’t understand the energy markets.” He’s not alone. In last June’s Energy Pulse, consulting engineer Brian Leyland warned that the entire investment boom in alternative energy renewables could turn into just another “dotcom bubble.”

Leyland noted that the boom is driven by “a belief that we must reduce emissions of manmade” carbon dioxide, which in turn has “led to direct and indirect subsidies for otherwise non-economic renewables. These subsidies and tax breaks caused the boom. Without them, it wouldn’t have happened.”

The bottom line is that the debate about renewables, and investment in them, is as much about ideology and political belief as about economics and environmental issues. When the real cost of wind power as a major player in our future power needs is assessed, the answer won’t be found just “blowin’ in the wind.”

Cost benefits of wind turbine

November 9, 2011

Wind energy is the big new thing in both viable alternative energy and commercial electricity generation. It is both clean and fully energy independent–the turbines can be made in most any industrialized country, and the wind can be found anywhere. Although not the cheapest form of electricity in standard terms, wind energy still offers a number of benefits.

 

  1. Wind Power

    • Wind power works by converting the kinetic energy present in wind first into mechanical energy and then into electrical energy. The conversion to mechanical energy uses a technique as old as windmills. Wind turns a turbine’s blades, which are shaped to catch the wind. This turning motion is then transferred by gears to the turbine’s rotor, causing the turbine to generate electricity.

    Cheap and Getting Cheaper

    • Sources of U.S. electricty

      According to the U.S. Dept. of Energy, clean wind power costs $55.60 per MWH (megawatt hour). Meanwhile coal energy costs $53.10 per MWH; nuclear power $59.30 per MWH; and natural gas $52.50 per MWH. At the moment, wind power is more expensive than fossil fuels, but those costs are dropping as wind turbines are starting to be produced in mass numbers, making them less expensive. Wind power costs dropped by 80 percent between 1984 and 2004.

    Lower Operating Costs

    • Wind power has no fuel costs and low or negligible costs for maintenance. However, there is a relatively high initial investment cost. Wind farm producing the same amount of electricity as a mid-sized coal-fired power plant will cost more to build, but substantially less to operate over a 20 year-plus time frame. It is in this higher initial investment that makes the cost per KWh higher.

    No Carbon Costs

    • The previously cited statistics on the cost of wind power do not take into account environmental costs. Wind power has no clean-up costs, but fossil fuels do. Any serious plan to tackle global warming will necessarily have to include some mechanism like a carbon tax or carbon cap-and-trade system, making carbon emissions more expensive and therefore providing a negative motivation for moving to cleaner energy sources. If these costs were added into the equation, wind power would already be competitive with fossil fuels, despite the higher initial capital investment.

    Good for the Trade Deficit

    • The United States imports 60 percent of the oil and 15 percent of the natural gas it consumes. In 2007, 21.6 percent of U.S. electricity output came from natural gas and 1.6 percent came from oil. Natural gas and oil imports are major contributors to the U.S. trade deficit, so dependence on foreign fossil fuels has an indirect and negative impact on the American economy. For example, if wind power were to completely replace oil as a source of electricity, the result would be roughly 517,000 fewer barrels of oil imported into the U.S. annually. The impact of this reduction would naturally vary with the price of oil, but it is certainly a start, and one that could be expanded. The Netherlands is currently studying not just replacing oil-fired thermal power plants with North Sea-based wind farms, but building so many that they could export surplus electricity to neighboring countries. That is a source of trade surplus replacing a source of trade deficit.

    Potential Job Creator

    • There is no reason why the U.S. could not only make wind turbines for its own need, but become a wind turbine exporter. In fact, the main reason why the growth of wind power is lagging in the U.S. is not lack of demand, but lack of supply, with many of the turbines being set up in the U.S. being imported from Europe. This is creating jobs and trade surplus in Europe, while contributing to the trade deficit and being an example of lost opportunity for the USA

Regenedyne Wind Turbine

November 8, 2011

http://youtu.be/wZv6Hof7Tr0

http://www.Regenedyne.com Demo CGI for proposed 2GW Magnetic Leviatated wind Turbine. *Efficient Frictionless Power Generation with less maintenance,compared to HAWT. No oil change or replacement of the bearings, gears. Since, MAGLEV does NOT require such. ** Current bearing technology has forced wind turbine designers into horizontal spindle three bladed wind turbines. In this design the huge blades are connected to a spindle in the center.

The bearings that support the spindle and control the pitch of the blades (which can be hundreds of feet long) see huge pitch-moment loading, some of which is manifest as torque energy that is focused through the center spindle. The target speed for the spindle is 18 or 20 rpm and the bearings holding the spindle are mounted in a huge casting which also contains a large gearbox stepping the speed up to 1800 to 2000 RPMs which allows for the proper surface speed relationship between the coils and magnets. It is necessary to invert or condition the current, which is expensive.

This gearbox is full of many large bearings, gears and castings; for a 2 MW turbine the gearbox can easily weigh 30 tons. This gearbox needs to be mounted on the top of a pole more than 150 feet in the air and be able to support the turbine blades under full-force wind conditions. ***MAGLEV Power Generation, the pitch moment ratio is closer to 1-to-1 then the 100-to-1 as with a horizontal spindle design.