Integrated Balance of System Solution: The Next Solar Cost Savings Frontier

Phil is First Green Energy's go to expert on all things Solar!  Great read for those interested in the solar industry. Reducing BoS field labor and material costs on projects are critical to achieving competitive system performance and pricing.

By Phil Winters As PV modules decline in price, the focus on cost savings increasingly turns to the Balance of Systems (BoS). Though material costs of BoS continue to rise (copper, aluminum, steel, etc.), costs savings are derived primarily from the engineered integration of the BOS system which can reduce labor and materials on the job site. Two recent studies concluded that BoS costs will likely exceed the costs of PV modules in the near term, becoming the highest cost portion of a solar system (this is including the mounting system, which we are including in BoS descriptions). According to GTM research, “…attention from developers and EPCs will increasingly be placed on a project’s balance-of-system (BoS) costs. Historically, innovation in the BoS space has been somewhat limited, given its smaller share of the total system. However, BoS costs will represent more than half of total project costs by 2012, and many BoS players are beginning to integrate their offerings into full-service component packages and positioning for greater share in the market via meaningful economic gains.” As well, the recently launched U.S. Department of Energy SunShot Initiative ‘aims to dramatically decrease the total costs of solar energy systems by 75% before the end of the decade’. Much of the focus of this initiative is on BoS and labor savings advancements. During the last decade, we have seen a series of shifts in the PV landscape. In 2002, the solar industry was squarely focused on the modules while the inverter was considered a mysterious box with a limited 3 year warranty that could be sourced from only a handful of suppliers in the market. Slowly the focus changed to the inverter, which now comes with standard 10 and 20 year warranties, and boasts thousands of suppliers globally. Until recently, nary a thought was given to the BoS, with integrators frequently building their own mounting systems out of strut, stuffing their own combiner boxes and cobbling together their BoS solutions from a series of manufacturers via their local electrical distributor. Thankfully, the industry has matured and many of these ‘home-made’ solutions have abated over time with suppliers like Eaton stepping in with high-quality, volume manufacturing. This has contributed to the decreasing installed cost of PV. There is, however, much to improve upon where significant BoS cost savings can occur, which Eaton is now squarely addressing. Take for instance, the current state of connecting modules to combiner boxes. Most contractors currently do all this work manually; running PV cable the length of the combiner box to module connection point, cutting and stripping the wires, crimping their contacts, assembling the connectors, attaching ID labels and terminating the string in the combiner box. This will be repeated dozens, hundreds and thousands of times depending on the scale of the project. Did we mention this is generally being done by highly paid electricians? Like days of old, with homemade mounting systems and combiner boxes, this practice results in more cost, more connection points, more leak paths and definitely more potential quality and safety issues due to human error. On top of this, it is questionable whether testing is conducted on every one of those connection points─i.e. pull, hi-pot and continuity testing─thus further increasing potential human error trouble spots, which can be dangerous down the road, costing significant resources to fix. There’s an option, Eaton BoS alternative: a custom made PV cable assembly that is manufactured for your project in a controlled condition, by highly trained personnel using precision Swiss made equipment. These custom assemblies arrive at the job mapped, labeled, guaranteed and 100% certified for pull test, continuity and Hi-Pot. This approach also reduces material and labor costs up to 30% while significantly increasing the quality and certainty of long-term system performance. The Eaton solution replaces a highly laborious and time consuming process with a plug and play solution. BoS breakthroughs like this are driving the reduction in system costs while driving solar towards grid parity. Companies like Eaton, with their integrated total BoS solution, are driving innovation and cost reductions across the system to benefit the entire solar industry. Part of what differentiates the Eaton approach to BoS is how the engineering teams from each product work together to optimize layouts and system designs to achieve material and labor savings. Eaton engineers across product disciplines work together, so our designs are focused on reducing labor and materials in the field. While other mounting manufacturers design their mounting solution and provide a quote around this one component of the system, the Eaton approach is to review the electrical design parameters of the project to ensure mounting, cable, cable management and combiners are all designed in one integrated fashion to maximize efficiency and cost savings opportunities on each specific project. A complete BoS engineered solution looks at every angle of the project, ensuring consideration of every component in tandem rather than in a vacuum. This reduces cost while increasing certainty of construction logistics, material costs and performance of PV asset. Let me give you a real-world example: Eaton recently worked on a 10 MW project which had received three quotes from three different companies to provide single component solutions (mounting, combiner boxes and PV cable solutions). Standard solutions at a standard price. Then, Eaton got involved with our Total BoS Solutions. What we were able to achieve by integrating our design practices across our BoS solutions was a 15% reduction in mounting costs, and a reduction in pier requirements by 33%. By matching our mounting configuration to the string sizing of the system, were able to reduce PV cable costs by 50% while reducing the labor on PV cable installation by 70%. This is a remarkable achievement on one project─and this approach drove the advancement of innovation at Eaton. It is a remarkable and positive change for the PV industry that one company can offer roof and ground mounting solutions, combiners and re-combiners, cable management solutions, PV cable harness assemblies, wireless monitoring and grid tie solutions all from one qualified highly bankable vendor. As solar continues to step onto the world stage of large scale utility and massively distributed rooftops, the manufacturing community also needs to step up their game to ensure they are integrating BoS solutions which provide better performance, higher long-term certainty and reduced costs in materials and labor. Phil Winters is the Renewable Energy Business Development Manager for Eaton in Canada. Prior to joining Eaton, Winters launched and led project development and EPC firms serving the Canadian and global solar markets. Winters is a graduate of both Solar Energy International (1999) and the Ontario Solar Academy (2009), and is currently the Vice President of the Solar and Sustainable Energy Society of Canada. He holds MBA from Southern Methodist University’s Cox School of Business. http://www.interpv.net/market/market_view.asp?idx=814&part_code=03

Ideas for a rational electricity policy platform

Rod Taylor

We are about 10 months away from the next Ontario provincial election, and electricity policy is likely to be one of the top five ballot issues. What follows is a short list of ideas, available free to any political party, on what should make up an electricity policy platform.

1. Reaffirm the principle that making Ontario’s electricity prices competitive with our neighbours is the overriding objective. This principle has been sadly neglected in the recent “maximum renewables whatever the cost” era of Ontario’s Green Energy Act. The price of electricity should be set in the market, but electricity policy should be guided by a comprehensive, independent regulatory analysis of which of the various generation, transmission and demand management options offer the lowest, long-term life-cycle costs.

This analysis should consider all costs, including environmental, such as the cost of long-term nuclear waste storage, mercury emissions from flooding, greenhouse-gas impacts from backing up intermittent solar and wind generation, etc.

2. Recognize that dispatchability is key to operating a power system. Demand and supply must be instantaneously matched, and this means generators must be dispatched on and off the system. Wind and solar power are intermittent, variable and non-dispatchable. Hydroelectricity is renewable and dispatchable.

There are 2000 megawatts of hydro power waiting to be developed in Ontario’s north. In its 2007 integrated plan, the Ontario Power Authority said this option is the most cost-effective of all renewables, including the cost of transmission incorporation.

3. Overcome Ontario’s delusional obsession with electricity self-sufficiency. It is delusional because two-thirds of our power is made from primary energy sources (uranium, natural gas, coal) sourced outside the province. If Boston can rely on northern Canadian hydro power for a substantial portion of its power, why can't Toronto? Ontario sits between the two lowest-cost power jurisdictions in Canada – Manitoba and Quebec. Once we’ve built out our own untapped and renewable northern hydro power, let’s import more from our neighbours. Ontario has world-beating expertise in transmitting high voltage power through climate and distance; let’s use it.

4. Revise the Clean Energy Act. Dramatically reduce the terms for new purchased power to five years; reduce the size of any single installation; reduce the subsidy offered; restore local planning authorities; make competitive electricity prices an objective of the act.

5. Rationalize Ontario’s power sector. The government has announced its intention to reduce the number of agencies, boards and commissions as part of its austerity program. Recombining parts of the power sector must be done with extreme care. For example, the planning parts of the OPA could be merged with the Independent Electricity System Operator, but if the contracting for long-term supply that the OPA currently does joins the IESO, the “I” (for “independent”) will be lost and the credibility of the Ontario market structure destroyed.

There is, however, room in Ontario’s power sector for significant rationalization and that’s on the distribution wires side. This sector offers major opportunities for economies of scale. Local distribution companies should be encouraged to amalgamate or, at the least, share scalable network services (e.g. billing, metering, forestry, line maintenance) to reduce costs.

6. Do not build social programs on the backs of ratepayers. No future government will be elected on the basis of tax increases; but unlike in other sectors (mining, forestry, chemicals, steel, autos, telecom, gas distribution, etc.), in the electricity sector, the province owns the lion’s share of the assets and can send directives to the regulator.

This tempts every government to build social programs (e.g. employment programs) and charge them to the electricity ratepayer (e.g. creating an Ontario nuclear industry, or an Ontario industrial windmill manufacturing industry). No new taxes should also mean no further plundering of the capital pool made available by raising electricity rates by ministerial direction. The best way to prevent this in future is by taking the assets out of the province’s hands, and relying on a well-funded, independent regulator to protect the consumer without ministerial direction.

By taking these six positions, a political party would have a rational and comprehensible electricity policy to offer voters in the October, 2011, election.

Rod Taylor is former executive vice-president, Hydro One, and was a member of the board of the Ontario Independent Market Operator and sat on Ontario’s Market Design Committee.

http://www.theglobeandmail.com/news/opinions/opinion/ideas-for-a-rational-electricity-policy-platform/article1876455/

Ontario opposition would seek green energy changes

Here's an article that I feel is important for Ontario solar, wind and hydroelectric developers, supporters, opposition and voters to be informed about.  

I understand the concerns of the Progressive Conservatives. Any new government's decisions and actions must well thought out. Analyze and understand the near term benefits and longterm impacts to the greater renewable industry involved (developers, operators, manufacturers, installers, communities, First Nations etc.).

If new rates are deemed fair and justified, the industry and the rate base will understand.  Threatening to kill the Green Energy Act (feed in tariff, related programs and procedures) without an immediate system in place will reboot a repeating industry boom and bust cycle that Ontario's renewable industry has experienced over the last 3 decades.  

Read below:

By Nicole Mordant

VANCOUVER, Jan 12 (Reuters) - Ontario's opposition Progressive Conservative Party would overhaul the province's feed-in tariff program for producers of renewable energy if it wins the October provincial election because it is too expensive, a party leader said on Wednesday.

The Conservatives, who have a double-digit lead over the governing Liberal Party in opinion polls, would also comb through existing contracts handed out under the incentive plan to see if changes can be made, said John Yakabuski, who is in line to take over as energy minister if his party takes power.

"Going forward, absolutely, we would not be signing these contracts," Yakabuski said.

"We are not going tear up contracts, but I can tell you we are going to look at each and every one of those contracts to see what options we have," he told Reuters in an interview.

Ontario, Canada's most populous province, has attracted billions of dollars in investment from foreign and domestic producers of renewable energy since it launched North America's richest and comprehensive feed-in tariff program late in 2009.

The program, which is aimed at creating jobs and eliminating coal-fired power plants to cut greenhouse gases, pays above-market rates under 20 year contracts to solar, wind, water and biomass power producers who meet certain criteria.

Ratepayers, who bear the costs of the program, have started to complain as their monthly power bills have risen.

"The problem is that the consumer pays and that is the tremendous, terrible wrong of their program," Yakabuski said.

He said the Conservatives were in favor of closing down coal-fired power stations and encouraging the development of renewable energy, but contracts for new power had to be awarded through a competitive bidding process.

The Conservatives have not yet issued their official energy policy but will do so well before the Oct. 6 election, he said.

The biggest investor in the Ontario green energy program to date is a consortium led by South Korea's Samsung C&T (000830.KS: Quote), which was awarded a C$7 billion ($7.01 billion) contract a year ago to build wind and solar projects and set up manufacturing plants.

Other foreign investors include Germany's Siemens AG (SIEGn.DE:Quote), which plans to build a wind turbine plant in the province, Bosch Solar Energy AG (BSLRF.PK: Quote) and Japan's Marubeni Corp (8002.T:Quote).

"I think the posture of the Conservatives is slowing some investment," said Michael Carten, chief executive of Sustainable Energy Technologies Ltd (STG.V: Quote), which has partnered with Bosch to build solar modules and inverters.

"I am sure that some of the big players are saying 'I have to see some continuity on this, let's see what will happen after the fall'," he said.

($1=$0.99 Canadian) (Editing by Rob Wilson)

© Thomson Reuters 2011 All rights reserved

Industry Insight: Hydroelectricity: The Versatile Renewable

http://www.hydroworld.com/index/display/article-display/7205041011/articles/hydro-review/volume-29/issue-1/lead-story/industry-insight_.html

Hydropower in North America is experiencing a renaissance. As a result, equipment manufacturers are being flooded with orders to provide equipment for projects using improved conventional technology and new, emerging technologies.

By Steve Blankinship

As one of the earliest and most elementary forms of power generation, hydropower remains by far the largest source of renewable energy in the world, including in North America.

In the early 1900s, hydropower was the dominant source of U.S. electric generation. As recently as the 1940s, hydro facilities accounted for more than 40 percent of electricity production. By the 1950s, developers had tapped the hydro potential of the most mountainous regions in the U.S. – many in the Northwest – where steep inclines supply the strongest river flows and permit the most cost-efficient projects.

Hydropower supplies almost two-thirds of Canada's power and makes it the world's largest hydropower producer, representing 13 percent of global output. This country also is the world's second largest exporter of hydro (after France). Altogether, its roughly 450 hydro plants, half of which have a capacity of less than 10 MW, account for 72,660 MW. Another 1,800 MW of capacity currently is under construction, and an additional 12,000 MW are being considered for development, according to the Canadian Hydropower Association.

Today, hydro represents about 8 percent of all power in the U.S. and more than 90 percent of all the renewable power generated in the U.S. Hydro provides more than 16 times as much energy as wind and solar power combined.

Hoover Dam, on the Colorado River between Nevada and Arizona, impounds water for two powerhouses that provide a total capacity of 2,078 MW.

And hydro's use is increasing, both through updates to older generating technology and through new technologies. Utilities are proposing more than 70 projects that would boost U.S. hydroelectric capacity by at least 11,000 MW over the next decade.

Driving a new wave of hydropower development is unprecedented demand for renewable energy and rising fossil fuel costs. The American Recovery and Reinvestment Act and other programs include tax provisions to attract investment in incremental hydropower; hydro at non-powered dams; and ocean, tidal, and in-stream (hydrokinetic) technologies.

Upgrades and new builds

American Municipal Power (AMP) owns and operates power production facilities for 126 member entities in Ohio, Pennsylvania, Michigan, Virginia, West Virginia, and Kentucky. AMP is developing six hydro projects, representing one of the largest deployments of hydroelectric generation in the U.S. The projects are run-of-river facilities to be installed at existing dams on the Ohio River and on the New River in West Virginia. Combined, these projects would add more than 380 MW of new generation at an estimated construction cost of more than $1.5 billion.

As part of the project, AMP signed a contract worth more than $300 million with Voith Hydro to manufacture turbines and generators for the first three of these projects at the Smithland, Cannelton, and Willow Island locks and dams. A fourth Ohio River project will be at the Captain Anthony Meldahl Locks and Dam. In addition, AMP is pursuing a project (called Robert C. Byrd) at the Gallipolis Lock and Dam on the Ohio River and performing a feasibility study for a project at the Bluestone Dam on the New River.

Another company, PPL Corp., recently received approval of its request to the Federal Energy Regulatory Commission (FERC) to expand its Holtwood plant, on the Susquehanna River in Pennsylvania, by 125 MW. Holtwood currently is rated at 108 MW and has generated power since 1910. PPL said that incentives in the federal stimulus package could make the project feasible by offsetting the factors that caused the company to cancel its original plans for expansion in December 2008. Construction of the estimated $440 million project could begin in February 2010 and be complete by spring of 2013.

The boom in construction of larger hydro projects internationally has provided benefits to developers of smaller projects in the U.S. and Canada. "The hydro business is so robust right now that the contractors only go after big projects, leaving lots of room for smaller players to stay busy with medium and smaller projects," said Norm Bishop, senior vice president of hydroelectric and renewable energy for Knight Piesold. Knight Piesold is an international company of consulting engineers and environmental scientists who work in a variety of fields, including hydropower, wind energy, and mining.

In addition to the demand for renewables and the rising costs of fossil fuels, Bishop cites hydro's flexibility that allows it to meet today's power market demands. These demands include ancillary grid support, which is especially critical in places with increasingly high penetrations of wind farms.

And the potential to make cheap power from water has barely been tapped. Of the existing dams in the U.S., only 3 percent (or around 2,400) are equipped to produce power. These facilities annually generate 270,000 gigawatt-hours (GWh), according to the U.S. Department of Energy (DOE). DOE estimates another 30,000 MW of capacity could be developed, including 17,000 MW at existing dams.

Pump it up

After decades of little or no development, pumped storage in the U.S. is seeing renewed attention. Between 2007 and 2009, FERC issued preliminary permits for more than 20 pumped-storage projects, representing a total capacity of more than 15,000 MW.

In early 2009, Energy Secretary Steven Chu said hydro pumped storage must be a part of a national plan to expand clean energy resources and to integrate variable renewable energy resources into the transmission grid. Chu said the U.S. has limited existing resources for storing energy, and most of what it does have comes from the 20,355 MW of pumped-storage capacity now in service.

National Hydropower Association (NHA) Executive Director Linda Church Ciocci said that expanding hydro pumped storage capacity will be a high priority for her association's new pumped storage council. "The federal government has no program to spur expansion of U.S. pumped storage," she said. "We advocate investment tax credits or other similar measures that can incentivize pumped storage development immediately."

One benefit could be changes to the licensing process, an initiative NHA has worked on for many years. The new process focuses on collaboration among agencies, which should reduce the amount of time required for a new or renewed license from 15 years to as little as three or four years.

Relicensing is hot right now as owners hope to reap even 2 or 3 percent improvements for a price tag that can be as low as $200 per kilowatt.

"There's a tremendous opportunity to repower and upgrade the mechanical aspects of existing facilities to increase output," said Don Erpenbeck, vice president of engineering firm MWH. He's particularly upbeat about some new technologies, such as ultra-low-head hydro, and emerging technologies such as hydrokinetic. "If a project is 20 years old, there's a good chance today's technology can eke out more power at a very small cost per kW," he said.

Water to wire = ultimate efficiency

Hydropower has always had high availability and quick ramping rates. No fuel is needed, just the volume and motion of the water. It also enjoys an overall efficiency unmatched by any other power source. Mechanical efficiency is high, and the only true efficiency losses are limited to line loss.

"Availability is pushing 90 percent with hydro, and on the mechanical side we hit 95 percent efficiency," Erpenbeck said. But some plants have lost as much as 10 percent of their efficiency due to the age of their turbine-generating units. New technology can reclaim that efficiency and even increase output above previous levels. "You could be looking at up to 20 percent efficiency increases if the existing machines are in bad shape," he said.

The new turbines being installed at the 1,038-MW Wanapum project are fish-friendly and also will increase efficiency by 3 percent per unit over the old turbines.

Hydro's ability to ramp quickly enhances its attractiveness as a power portfolio asset. New technology can expand that flexibility. "We can make the efficiency curve flatter, so hydro is more efficient running off peak," said Erpenbeck. "We can now run with even greater flexibility and respond to market conditions across a wider range of megawatts in terms of cycling, load following, and turn down."

Erpenbeck said hydropower can routinely operate at 55 to 100 percent of rated load and back off to 20 to 40 percent as needed.

Increases to operating range provide prime quality spinning reserve for grid support, which is more important today than ever before. The increases are achieved through the ability to run in condensing mode where the generator is synchronized and motoring while the turbine spins air, or synchronized at low power (20 to 40 percent of rated load) and going to full power in seconds. For example, a single unit in the Third Powerhouse at the 6,809-MW Grand Coulee project on the Columbia River in Washington State can go from low load to full load (about 800 MW) in a matter of seconds.

Technology improvements

Improvements to conventional hydro technology provide a variety of upgrades that help hydropower remain low cost while offering environmental benefits.

Grant County Public Utility District in Washington State is installing ten $15 million fish-friendly turbines at its 1,038-MW Wanapum project and plans to replace another ten turbines at 855-MW Priest Rapids. The old turbines are being replaced with models that use six smaller blades instead of five. When completed in 2012, the work is expected to improve each turbine's efficiency by 3 percent and the Priest Rapids facility's overall capacity by 15 percent.

Recent upgrades to the Sacramento Municipal Utility District's 154-MW Jaybird and 82-MW Loon Lake powerhouses have led to still more efficiency gains. Installing new computerized controllers to better regulate water flow to the turbines increased output by 15 MW for the same amount of water when running at low power levels. The new governor control system automatically regulates the Pelton nozzles.

With the old equipment, the controller opened all six needles at once, boosting water flow to the turbine as electricity demand rose. When the unit was at low load, it required less water. But this fanned out of the needles similar to a garden hose set to a wide spray pattern and caused most of the water to miss the turbine wheel.

The new equipment opens two needles initially and adds others as demand for power rises. By moving the same volume of water through two needles instead of six, the water stream is more tightly focused and hits the turbine wheel more directly. This results in significant water savings for the same amount of power generation. Based on current short-term power price forecasts, the utility estimates the equipment will save it $130,000 a year.

Canada's two largest hydro utilities – Ontario Power Generation (OPG) and Hydro-Quebec – continue to expand capacity. Hydro-Quebec's expansion plans include completing the last generating units at the 385-MW Peribonka development and the first units at 62-MW Chute-Allard and 76-MW Rapides-des-Coeurs.

Work also proceeds at the utility's 906-MW Eastmain-1-A/Sarcelle/Rupert jobsite. The project will divert a portion of the flow from the Rupert River watershed into the Eastmain River watershed. The complex will involve four dams, a spillway on the Rupert River, 74 dikes, two diversion bays, and construction of a 1.8-mile-long tunnel and a network of canals and hydraulic structures on the Rupert River to maintain post-diversion water levels along half of the river's length.

OPG's Niagara tunnel project will increase the amount of water flowing to turbines at the 2,000-MW Sir Adam Beck complex at Niagara Falls, allowing the utility to better use available water. When the 6.5-mile-long tunnel is complete, average annual generation from the Beck stations is expected to increase by about 1,600 GWh. In April 2009, OPG completed a 12.5-MW hydroelectric station on the English River. The new Lac Seul facility uses most of the spill currently passing the existing 18.5-MW Ear Falls generating station, thus increasing overall efficiency, capacity, and energy generated from the plant.

Operation of the first of two turbines at Mississippi Lock and Dam No. 2 heralded the opening of the first commercially-operational hydrokinetic station in the U.S.

OPG also is proceeding with the definition phase for a 450-MW development on the Lower Mattagami River, including replacing the 52-MW Smoky Falls station and expanding the 136-MW Little Long, 140-MW Harmon, and 158-MW Kipling stations. The company also approved redeveloping four existing stations, which otherwise would have been removed from service.

New wave for hydropower

The tremendous force of moving water is obvious to anyone who has stood in breaking ocean waves or swum against a river's current. Ocean, tidal, and instream technologies generate electricity from waves or directly from the flow of water in ocean currents, tides, or inland waterways. This technology is gaining increased attention.

Hydrokinetic technology uses stream flow to make power and requires a steady 3 to 5 knots of flow to operate. Hydrokinetic water turbines can be placed where there is no dam; for example, they may be attached to bridges or to frames on the river bottom. Hydrokinetic technology boosts potential capacity far beyond conventional hydro power. As one example, thousands of miles of canals in California are designed primarily for irrigation but could also host hydrokinetic turbines.

Hydrokinetic turbines are smaller than wind turbines because water is about 800 times denser than air. Ocean tidal currents can deliver a predictable 20 hours per day of energy, and a hydrokinetic turbine can produce up to four times more energy than a wind turbine on a good day. Venturi and centrifugal designs can accelerate water speed through the turbine and double the energy produced. Current project proposals suggest that energy produced by U.S. waves, tides, and rivers could provide a capacity of 13,000 MW by 2025.

In August 2009, officials celebrated the opening of the first commercially-operational hydrokinetic power station in the U.S. The first of two turbines was installed and operational at the 4.4-MW Mississippi Lock and Dam No. 2 facility, in Hastings, Minn., This installation will use two hydrokinetic units, each with a nameplate capacity of 100 kW. The second unit is expected to be installed in 2010.

Near-shore and offshore ocean waves might have the greatest hydrokinetic potential. Extracting just 15 percent of the energy in U.S. coastal waves would generate as much electricity as is currently produced at conventional hydro projects. Much of this wave potential is along the Pacific Coast and close to population centers.

Beyond the sheer size of the resource, ocean, tidal, and in-stream resources are attractive because of their predictability. Wave patterns can be predicted days in advance. Because the kinetic energy in a stream is related to its speed cubed, extracting the most electricity from each hydrokinetic project will depend heavily on site selection. Energy output increases eight times with only twice as much water current speed.

State and federal policymakers across the U.S. have taken notice of the potential of hydrokinetic energy and have begun to support its development through legislative and monetary means. Ocean energy is eligible for credit under renewable electricity standards in 16 states and for federal renewable production tax credits, as expanded in the Energy Policy Act of 2005. Furthermore, hydrokinetic energy development was marked for increased research funding appropriations in the 2007 Energy Independence and Security Act.

Overcoming environmental opposition

Hydro has all but disappeared from the energy options usually cited by renewable energy advocates. Many environmentalists have long opposed hydroelectric power and do not consider it "green" or renewable. Much of the opposition is based on the water diversions required by traditional hydroelectric projects and the effects on land and wildlife. Fish killed as a result of passing hydro turbines has also led to a substantial amount of environmental concern.

Because of this environmental opposition, some states restrict the extent to which hydroelectric projects may qualify under renewable portfolio standards. "Policy makers at the federal and state level have a difficult task of designing regulations and incentives that recognize the fact that an existing renewable source like hydropower can be further developed with the right incentives," said Michael Cutter, vice president of engineering and development for Brookfield Renewable Power. The company has developed, owned, and operated hydro facilities for more than 100 years and has 100 hydropower facilities totaling nearly 2,000 MW in nine U.S. states.

Cutter said opportunities exist throughout the U.S. for continued development of hydroelectric generation. "Recent studies show the amount of hydropower could double from the current amount of installed hydro generating capacity by 2030 if the country could upgrade existing hydropower, add hydropower at non-power dams, and develop some of the new technologies," he said. "To reach hydropower's potential, it is important to continue to strengthen federal and state energy policies and to educate the public on hydropower's role as an indigenous, renewable energy source." 

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Steve Blankinship was associate editor of Power Engineering magazine, a PennWell Corporation publication. This article originally appeared in the June 2009 issue of Power Engineering. Blankinship passed away in 2009. 

Plutonic Power, GE Energy agree to buy 50MW Canadian portfolio

Plutonic Power and GE Energy Financial Services have agreed to buy three of First Solar’s power plants in Ontario, Canada. Permitting for the projects, which have a combined capacity of 50MW, is expected to take place this spring and construction scheduled to start in June.

Despite selling the portfolio, First Solar has agreed to long-term contracts to supply engineering, procurement, construction and operation services for the 10MW Amherstburg, 20MW Belmont and 20MW Walpole facilities. The electricity generated by the three sites will be will be sold to the Ontario Power Authority under a 20-year energy-purchase agreement and connected to the province's distribution grid at five points.

"Expanding into both a new market and a new technology represents significant growth for Plutonic," said Donald McInnes, vice chairman and CEO of Plutonic Power. "Our solid relationship with GE Energy Financial Services enabled this expansion into our third joint near-term operating asset."

"This transaction is GE Energy Financial Services' first solar investment in Canada, broadening our US$6 billion renewable energy portfolio and supporting our strong partnership with Plutonic," said Mark Tonner, GE’s managing director. "We see significant growth potential for solar power worldwide, which continues to improve on technology costs and efficiencies."

Plutonic Power is expected to make an equity contribution of around CAN$6 million towards the project and will also take on the role of senior partner in the agreement; debt financing will be coordinated by First Solar and is expected to be in place at financial close.

http://international.pv-tech.org/news/plutonic_power_ge_energy_agree_to_buy_50mw_canadian_portfolio