Case studies in sustainable energy.
A Microgeneration Strategy for Canada - Part 1A Microgeneration Strategy for Canada - Part 1
This case provides an overview of the potential for microgeneration policy in Canada. It does not provide a detailed analysis of existing or recommended policy options. Instead, it draws attention to the opportunities that microgeneration provides, and shows how other jurisdictions have seized on these opportunities while Canada lags behind. This case is based on a review of relevant literature and on interviews with stakeholders in the microgeneration industry.
The case presents microgeneration technologies as part of a strategy to transition to a low carbon economy. It explores the way in which microgeneration has captured the imagination of the public and policy-makers alike in the UK. The barriers to microgeneration in Canada are considered as well as an outline of government initiatives designed to overcome those barriers, and concludes by suggesting elements for a microgeneration strategy for Canada.
Sustainable Development Characteristics
Microgeneration in the transition to a low carbon society
Canada’s Greenhouse Gas emissions are rising sharply, with energy use in buildings accounting for approximately 30% of emissions (CETC-Buildings Program website). While Canadians are concerned about climate change (Environics Research, reported in Refocus Weekly, 2003), many people feel helpless to act alone, and often do not connect their day-to-day behaviour with climate change. Even in a time of rising energy prices, most consumers find it difficult to link their always-on standby lights with the monthly energy bill, let alone with carbon emissions. It is not surprising that government exhortations to conserve energy appear to be largely ineffective, and successive government programs have failed to engage citizens in the fight against climate change.
At the same time, growth in Canada’s renewable energy lags far behind other nations (Martinot). Despite some of the world’s most abundant renewable resources, and a population that overwhelmingly supports their use (Refocus Weekly, 2003), Canada’s renewable energy industry receives far less government support than that in Germany, the US, Spain or Japan. As a result, Canada’s renewable energy companies, some of them world leaders, often rely principally on exports because domestic markets are held back by limited government support, red tape, and inefficient policy.
Most of Canada’s electricity is generated in large, centralized plants, often some distance from the centres of population where most energy is consumed. While this creates some efficiencies through scale economies, more than 7% of Canada’s electricity is lost in its transmission and distribution (1999 figure; World Bank, 2002). Since Canada’s electricity-related greenhouse gas emissions in 1999 were 134 million tonnes, transmission and distribution losses imply a substantial carbon penalty. With a huge, renewables-rich land mass and a geographically dispersed population, Canada is ideally placed to become a leader in developing small-scale, distributed renewables, or ‘microgeneration’.
"Solar heating and power systems are viewed as the norm, with one in three single family homes using a solar water heating system and one in 10 using photovoltaics." (National Round Table on the Economy and the Environment, 2006).
Engaging the public
For most of us, energy use is largely invisible and unconscious. We simply are not aware of the stand-by lights, the power ratings of our toasters and lightbulbs, and the efficiency of the furnace. Exhorting the public with campaigns to conserve energy had poor results in the past, and although most Canadians are concerned about climate change (Bueckert, 2006), many feel helpless to make any positive changes in their own lives. Environment Canada’s evaluation of the One-Tonne Challenge program found that many people remained unaware of how they could make changes in their daily lives to reduce emissions (Environment Canada, 2006). Encouraging sustainable energy consumption is not straightforward. Canadian energy prices are relatively low, and do not reflect the true environmental and social costs of energy production and consumption. In any case, despite recent price hikes, many consumers find it hard to link the monthly bill to their day-to-day behaviour. But however difficult it may be, failing to engage with consumer behaviour is not an option if Canada is serious about cutting emissions. Microgeneration technologies provide opportunities to engage Canadians in the fight agains climate change with a positive and empowering approach.
Introducing clean, affordable energy generated within their own homes and businesses enables people to see and understand their own energy use, and to be proactive in reducing their emissions. Microgeneration technologies help people to see the bigger energy picture, and help to make people more aware of their energy choices and use at home. This sets residential-scale energy apart from larger alternatives – it is a real way of engaging people with the origins and impacts of energy and the implications of consumption, and combating the apathy that so often accompanies climate change concern.
"I see micropower in terms of a battle for hearts and minds, really, as much as the more mundane but very important fact that it can be part of the energy supply". (UK Energy Minister, Malcolm Wicks, 2006).
A recent study in the UK found that households in which microgeneration technologies have been installed are generally more aware of the energy use in their home, and adapt their behaviour accordingly. This was even true of microgeneration technologies in social housing, where the residents themselves had not made the decision to install the technologies. These residents had never thought of themselves as environmentalists (Dobbyn & Thomas, 2005). In the US, experience from the Sacramento PV (Photovoltaic) Pioneers program demonstrated how homeowners felt benefits from the satisfaction derrived from, and status acquired in being a leader in sustainable energy (Smiley, 2003). Microgeneration is a visible reminder to the whole community of climate change solutions and self-sufficiency.
“I tell people all the time that I generate my own electricity.. I love it.. I think it's fascinating.”(Homeowner in Lancashire, with wind turbine. Dobbyn & Thomas, 2005).
“A lot of parents seem to notice it and ask what we’re doing. It’s good for them to see new things going on in the school.” (Teacher, Scottish primary school with solar panels. Dobbyn & Thomas 2005).
Reducing greenhouse gas emissions
Microgeneration technologies can help achieve a reduction in Canada’s greenhouse gas emissions. Many microgeneration technologies are zero carbon renewables: micro wind power, solar PV and solar thermal, and biomass heating and Combined Heat and Power (CHP). These technologies directly offset energy from carbon emitting sources. Others use renewable energy to supplement traditional sources: ground and air source heat-pumps, for example, use a small amount of electricity to extract heat and cooling from the earth and air.
Realisation of the full market potential would result in the installation of over 600 MW of small wind turbines and greenhouse gas emission reductions of over 300 kilotonnes CO2e per year (equivalent to removing over 50,000 cars from the road).” (Marbek and GPCo, 2005). The solar resource is also huge, again with the southern (populated) areas of the prairies particularly richly endowed, and also southern Ontario (Morris, 2006). On a typical July day, Toronto receives more solar energy than Miami (McGonagle, 2006). In Canada’s forested areas, where wind resources are constrained, bioenergy represents an enormous opportunity. It is worth noting that the provinces that are most dependent on fossil fuels for electricity, such as Alberta and Saskatchewan, also have the richest microgeneration resources.
Already, despite very limited deployment, microgeneration technologies are reducing Canada’s greenhouse gas emissions. For example, active solar heating systems currently operating in Canada replace around 23,200 tonnes of CO2 equivalent every year, while the solar thermal collectors sold during 2004 alone will replace, over their lifetime, 122,600 tonnes. (SAIC, 2005).
Microgeneration technologies alone are not the solution to Canada’s energy policy needs, as they will not serve all of Canada’s energy demands, but neither is the contribution of microgeneration vanishingly small. Modelling for the UK government, based on learning curve estimations of future costs, has suggested market penetration of small (< 50kW) wind and PV could reduce the UK’s carbon emissions by 6% by 2050 if net metering tariffs are in place (Energy Savings Trust et al, 2005). While this would clearly be different for Canada, the UK's experience demonstrates that gains from microgeneration are small, but potentially significant. There is an urgent need for further analysis to assess the potential for market penetration of microgeneration in Canada to reduce emissions.
Providing clean, affordable power to Canada’s remote communities
Reducing infrastructure needs and enhancing robustness
Electricity in Canada is produced far from the point of consumption. The electrical system requires substantial investments in transmission networks to move power around the country. As electricity demands rise over the coming years, costly upgrades to transmission systems will be needed. In any case, long-distance transmission brings inefficiencies into the system. Microgeneration reduces or delays that need, by meeting demand closer to the point of use and thus reducing the need for increased transmission capacity. This economic benefit of microgeneration is not always captured in cost comparisons, which typically represent generated, rather than delivered, electricity costs. This fails to represent the costs of infrastructure and the efficiency losses of long-distance transmission (WADE, 2005).
Microgeneration technologies can also enhance system robustness, and help to prevent black-outs: meeting some electrical load locally reduces the strain on long-distance transmission lines. Studies after the 2003 black-outs in Eastern Canada and the US found evidence that a few 10s of MW of distributed PV could have prevented the black-outs (Perez and Collins, 2004). Canada’s electricity transmission infrastructure is inefficient and stressed, and distributed renewables can ease this pressure (CanREA, 2006). The National Energy Board recently concluded that:
“Alternative and renewable resources and demand management are becoming more important in addressing … supply adequacy.” (National Energy Board, 2005).
PV technologies, in particular, reduce energy demands during summer peak loads, on hot sunny days when air-conditioning demands spike.
Providing opportunities for Canadian business
“Global demand for small, environmentally friendly power systems is rapidly accelerating. In Canada, there is a huge potential market among homeowners and small business operators.…the micropower market could provide thousands of jobs and billions of dollars in revenue.”(Micropower Connect, 2006).
Critical Success Factors
- Dynamism at the local level played a key role in fostering the development of policy.
- National government leadership was essential in encouraging local level progress to spread.
- Enabling straightforward grid connection is essential and a pre-requisite if economic instruments such as capital grants are to work.
- Microgeneration can capture the public imagination, and engage public debate around energy futures.
- Canadian governments have already recognised many of the benefits of public support for microgeneration technologies, and both the federal government and provincial governments have taken important steps to remove barriers and enable growth in microgeneration markets.
- The Renewable Energy Deployment Initiative (REDI) was established in 1998 to provide $51m over 9 years to solar air and water heating and biomass heating in commercial buildings.
- The Class 43.1 Capital Cost Allowance tax incentive for the purchase of renewable energy equipment has been valuable for supporting the small wind market.
- PST exemptions or rebates on renewable energy purchases offered in PEI, BC, and Ontario. Nova Scotia provides a 10% rebate for solar water heating, and $200 for certified clean-burning woodstoves, while the Quebec Energy Efficiency Fund provides $400 towards solar wall installations, a form of active solar air heating. In BC, a project of the BC Sustainable Energy Association, partnered with provincial and federal governments, Vancity Credit Union, and BC Hydro, is providing support for homeowners and communities to access rebates for solar hot water systems.
- Natural Resources Canada and a range of industry associations and other stakeholders have made progress over the last few years in tackling some of the systemic barriers.
- In 2006, a new National Standard of Canada was issued covering grid interconnection of microgeneration technologies, providing a basis for harmonized rules across Canada.
- The Ontario Power Authority’s Standard Offer Program, which provides a guaranteed price for electricity generated from renewable resource installations under 10MW.
- The federal government has provided support to a number of Canadian industry associations representing the microgeneration industry, either with core funding or for specific projects. Government support has also been available for the development of product standards and training and certification programs. Other support has been targeted at raising awareness of small-scale renewables.
- The Aboriginal and Northern Community Action Plan (ANCAP) was developed to help northern communities respond to the challenges of climate change, through adaptation and reduction of greenhouse gas emissions. This includes supporting renewable energy projects, as well as resource estimation (through a Wind Assessment program), and community energy planning in remote communities across Canada.
- There are many Canadian municipalities that have installed small-scale renewable systems, often as part of initiatives to reduce the carbon footprint of civic buildings. The federal government's Green Municipal Funds, which is administered by the Federation of Canadian Municipalities, has been an important source of support for these projects.
What Didn’t Work?
- Energy systems and markets are structured and regulated in such a way as to unfairly exclude small producers, by barring entry into energy markets, failing to compensate small producers for their generated energy, and a host of issues associated with codes and standards, building regulations, and permits.
- The process of connecting to the grid needs to be carefully regulated to ensure safety and reliability, but the process of interconnection is often overly complex, and some observers have suggested that the lack of uniform interconnection standards across the country has been ‘the number one interconnection barrier for small renewable systems.’
- Codes are vital for ensuring that products and buildings are safe and reliable, but they need to be updated as new technologies emerge. This has not always happened.
- Canada currently lacks straightforward training and certification systems for installers of many microgeneration technologies.
- Local by-laws and planning rules have usually been designed without consideration of micro-renewable technologies.
- In an energy system dominated for decades by large, centralized power generators and heating fuel providers, many homeowners, developers, and policy-makers simply do not know about or understand the alternatives.
Financial Costs and Funding Sources
Although they typically have low operating costs, most microgeneration technologies involve large up-front capital costs, and frequently long pay-back timeframes. This is particularly true in Canada, where electricity prices are very low. For many homeowners concerned about reducing their energy bills, upfront costs are a major disincentive, particularly given the difficulty in accessing the financing mechanisms available to investors in large centralized energy systems. High upfront costs were cited as one of the principal barriers to increased microgeneration by most of the industry figures contacted, reflecting the results of recent surveys (Marbek and GPco, 2005).
It is often argued that the high upfront costs of microgeneration technologies are a reason to delay support until costs have come down through R&D. This is often a self-defeating argument, given what we know about the relationship between cumulative installations and cost (see figure below). Removing the barriers to adopting microgeneration technologies will allow costs to fall, and for microgeneration technologies to establish self-supporting markets. This, of course, does not mean that microgeneration should be given a blank check, but rather that targeted support can create momentum for change.
The Renewable Energy Deployment Initiative (REDI) was established in 1998 to provide $51m over 9 years to solar air and water heating and biomass heating in commercial buildings. It provides up to 25% of the cost of these systems, and in 2002 support from REDI was extended to ground source heat. While it has provided much needed support for the development of the renewable heat industries in the commercial sector, and is considered to have been a successful program, it has not engaged with homeowners to bring renewable energies to a wider market.
PST exemptions or rebates on renewable energy purchases are offered in PEI, BC, and Ontario. Several provinces have also developed grants for renewable equipment purchases: Nova Scotia provides a 10% rebate for solar water heating, and $200 for certified clean-burning woodstoves, while the Quebec Energy Efficiency Fund provides $400 towards solar wall installations, a form of active solar air heating. In BC, a project of the BC Sustainable Energy Association, partnered with provincial and federal governments, Vancity Credit Union, and BC Hydro, is providing support for homeowners and communities to access rebates for solar hot water systems.
A Microgeneration Strategy for Canada - Part 2A Microgeneration Strategy for Canada - Part 2
Published November 29, 2006
Detailed Background Case Description
Capturing the public imagination: microgeneration in the UK
The Leader of the Opposition wants to install a wind turbine on his roof (Clover, 2006). The Mayor of London believes that his measures to foster distributed generation in London will be one of the most important parts of his legacy (Livingstone, 2006). Major privatized utilities are buying significant stakes in emerging microgeneration companies (Scottish & Southern Energy, 2006). Over the last few years, small energy has become a big deal in Britain.
The explosion of interest in microgeneration has come about as a result of sustained concern about climate change in energy policy circles, together with concerns about rising energy costs and about the need to make a transition to a sustainable, low carbon energy system. The context in the UK is of course very different from that in Canada, with liberalized electricity markets for over 15 years, rather than the near monopoly situations that exist in many Canadian provinces, and substantially lower electricity prices. Many of the issues, however, are the same – interconnection, codes and standards, rewards for generation, local planning issues, and high upfront costs faced by consumers. The UK experience illustrates how microgeneration can become an empowering and positive way to engage the public in energy and climate change issues.
Microgeneration on the policy agenda
Several stages have enabled the UK to move towards a mainstreaming of microgeneration. Interest in microgeneration arose from an awareness that distributed power could reduce the stress on overloaded transmission lines, reduce dependence on imported energy supplies, reduce greenhouse gas emissions, and bring down energy bills for homeowners. In 2000, the government established a working group to address the barriers to increased distributed generation. As a result, in 2003, a uniform set of codes and standards for microgeneration installation and interconnection was established, providing installers with a single set of rules. This enabled a change in regulations to allow customers to install microgeneration equipment and connect to the grid without having to obtain permission from the local distribution network operator, greatly easing the administrative and regulatory burden on customers and installers. This was a key step in enabling microgeneration to establish a respectable niche in energy markets. Also in 2003, the government introduced incentive programs providing up-front grants to homeowners and communities buying and installing accredited microgeneration systems, often up to 50% of installed system costs.
Responding to increasing enthusiasm for microgeneration among lobbyists and policy analysis, the UK government committed to developing a ‘Microgeneration Strategy’ by the end of 2005, in its Energy Act of 2004. As the government was developing the strategy, others joined together to support the emerging microgeneration agenda. Green groups and thinktanks advocated in favour of small-scale renewables, with Green Alliance publishing a ‘Microgeneration Manifesto’ in 2004 (Collins, 2004). This laid out the potential benefits of microgeneration for the UK, and suggested elements for the government’s Microgeneration Strategy.
Industry stakeholders with an interest in microgeneration also grouped together, forming the Micropower Council, in 2004. The Micropower Council includes renewable energy companies and industry associations, and five of the UK’s six biggest utilities. Since then, the Micropower Council, along with the Renewable Power Association, has played an important role in providing a link between policy-makers and the industry.
The Microgeneration Strategy, published in 2006, included £30m in deployment funding through a Low Carbon Buildings Program. This program also provides lists of accredited installers and retailers of microgeneration equipment, and information on available grants and incentives for communities and homeowners interested in installing microgeneration technologies. Later in 2006, HM Treasury announced a further £50m of support for microgeneration, and Parliament passed the Climate Change and Sustainable Energy Act, which included additional measures for supporting microgeneration. The measures included a requirement for utilities to provide customer-generators with compensation for power exported to the grid, and requires the government to explore exempting microgeneration technologies from planning permission requirements.
Local governments lead the way
Perhaps just as important as the development of the national strategy has been the quiet microgeneration revolution sweeping through town halls around Britain. In 2003, The London Borough of Merton announced a new planning policy, which required all new development above 1000m2 to provide 10% of its anticipated energy needs from on-site renewable energy equipment. Part of the rationale for the policy was based on greenhouse gas reductions, but it was also intended to reduce energy bills in new homes and businesses in the borough, providing a long-term competitive advantage (London Borough of Merton, 2006).
“Home energy generation rarely leaves families unchanged in their outlook and behaviour...It seems that microgeneration provides a tangible hook to engage householders emotionally with the issue of energy use…householders describe the sheer pleasure of creation and self-sufficiency.” (Dobbyn and Thomas, 2005).
The government's planning office, at first sceptical of the policy, eventually allowed it and, in 2004, issued policy guidance on renewables that explicitly supported such measures (“Planning Policy Statement 22”). By this time, several other councils had adopted the policy, and by 2006, more than 100 councils were actively developing policies that have come to be called “the Merton Rule”. In June 2006, the Minister for Housing and Planning made clear the extent to which the government now supported the Merton Rule, by saying that:
“In particular, the government expects all planning authorities to include policies in their development plans that require a percentage of the energy in new developments to come from on-site renewables, where it is viable.” (UK Minister for Housing and Planning, 2006).
When the policy was announced, there was a general expectation that the development industry would be vigorously opposed, but this has turned out not to be the case. Planning officers from boroughs that have introduced the policy describe how developers have generally been co-operative.1
Microgeneration captures the public imagination
When Microgeneration Strategy was launched, there was real enthusiasm and support from the public, politicians, and the media. The diagram below indicates the way in which the British press responded to the public interest in microgeneration around the time of the publication of the strategy. The support shown for the strategy has been argued to be a result of the way in which microgeneration is a positive way of engaging citizens with climate change, rather than a negative ‘nagging’ approach.
Moving towards mass markets?
Many of the important barriers for UK microgeneration have been overcome, but many still remain. The industry is united, however, and has momentum, and there is a strong vision of what can be achieved driving developments.
The spread of municipal initiatives to promote microgeneration through the planning system is generating much of the current market, but this is restricted to new buildings. In 2006, Britain’s biggest home and garden retailer started selling domestic roof-mounted wind turbines. With a rated power of 1kW, the turbines are being sold at $3000 CAD, including sales taxes and installation, putting microgeneration technologies within the reach of ordinary homeowners. Curry’s, one of Britain’s biggest electronic goods retailers, has also started selling solar PV equipment, at an installed cost of $14,000 for a 1kW system.
Building-mounted wind turbines are relatively new – and controversial in the wind industry. Technical problems with vibration, turbulent air flow and noise have caused some wind experts to reject urban wind turbines as a fundamentally bad idea. A technical appraisal of building-mounted wind turbines suggested, however, that their deployment could be substantial, and that most of the technical barriers can be overcome (Dutton et al, 2005). There is little experience, however, with urban wind systems in practice, and it is difficult to get independent estimates of cost and performance.
Regulatory barriers and market structure
The barriers to microgeneration are systemic, and efforts to support microgeneration must similarly involve federal, provincial and municipal governments in partnership with utilities, developers and the microgeneration industry.
Energy systems and markets are structured and regulated in such a way as to unfairly exclude small producers by barring entry into energy markets, failing to compensate small producers for their generated energy, and a host of issues associated with codes and standards, building regulations, and permits.
“The structure of most electricity markets in Canada is not conducive to distributed generation... The deployment of low-impact renewable electricity applications is still largely up to the discretion of regulated monopolies, which have little incentive to do so”. (The Renewable Energy and Energy Efficiency Partnership (REEEP), 2003).
Canadian energy markets developed around large, centralised generating plants, such as large hydro installations and coal-fired power stations. The institutions, regulatory frameworks, and habits that govern the market have considerable inertia, and help to ‘lock-in’ often inefficient systems. This is increasingly known as ‘carbon lock-in’ by scholars of technological change, and implies that economic instruments and public persuasion campaigns alone are unlikely to change consumption behaviour and purchase decisions. Institutional and regulatory barriers also need to be tackled (Unruh, 2000).
Access to the grid and compensation for electricity generators
Some renewable energy technologies are unpredictable in output because of the intermittency in sunshine and wind, and output does not always match domestic demand. When a microgeneration system produces more electricity than the homeowner is using, the excess power ‘spills’ into the local distribution grid, and is used by neighbours. These neighbours are billed by the utility for this power exactly as if it had been produced centrally, but unless systems have been put in place, the producer receives no compensation. ‘Net metering’ arrangements, in which customer-generators are compensated for their exported power at the retail electricity rate, are one way of restructuring the market so that the customer-generator receives a fair price.
Net metering is an important step in enabling microgeneration. As the experience of Manitoba demonstrates, however, a broad range of additional barriers can act to prevent widespread take-up of microgeneration even when net metering is in place. Manitoba Hydro operated a net metering scheme for more than 10 years, but the number of customers signing up was disappointing (The New Energy Resources Alliance (NewERA), 2006). Net metering does not automatically mean that it is straightforward for customers to install and connect microgeneration technologies, and straightforward interconnection may be more important in enabling microgeneration than rewards for energy exports. While several Canadian utilities have introduced net metering policies, it is frequently a time consuming and difficult process to get connected, not least because the utility has little incentive to do so. Getting connected was cited as a major factor by owners of grid-connected renewable energy systems in a recent survey, even where net metering systems exist (Henderson and Bell, 2003).
The process of getting connected to the grid needs to be carefully regulated to ensure safety and reliability, but the process of interconnection is often overly complex, and some observers have suggested that the lack of uniform interconnection standards across the country has been ‘the number one interconnection barrier for small renewable systems’. Furthermore, it is a problem that many utilities do not have any standards at all for small grid-tied systems. (Micropower Connect, 2006). Consequentially, many customers wishing to connect microgeneration technologies to the grid go through a complex, time consuming and expensive case-by-case inspection and approval process, or through a standard process designed for much larger generators. Standards are essential to provide safety, and maintain system and power quality, but they are also essential in facilitating straightforward grid connection.
Codes & standards
Codes are vital for ensuring that products and buildings are safe and reliable, and they need to be updated as new technologies emerge. This has not always happened, as the example of the solar hot water industry demonstrates. The National Plumbing Code calls for solar hot water systems to conform to a (now outdated) standard that was only ever intended to apply to a particular type of solar hot water system. No laboratory in Canada was certified to test systems to determine if they met the standard, so it was impossible to obtain certification to the CSA standard. As a result, in many areas it became difficult to get planning and plumbing permits, or insurance. This has had a negative impact on the Canadian solar thermal industry, and is only now being addressed, with Natural Resources Canada and the Canadian Solar Industries Association working with the Canadian Standards Association to develop appropriate standards and testing facilities (McGonagle, 2006b).
Consumers are rightly cautious about trusting uncertified products, but even where appropriate standards do exist, such as in the PV market, smaller manufacturers and importers cannot always afford the cost of CSA testing (Canadian Mortgage and Housing Corporation, 2006). Without support, product certification can be a further barrier for many small-scale emerging microgeneration technologies.
Skills & accreditation
Many microgeneration renewables take energy from the local environment: local solar, wind, earth energy and water flows are harnessed to provide for local needs. The result is that many systems are not simply ‘plug-and-play’, but need careful installation to perform properly.
Canada currently lacks training and certification systems for installers of many microgeneration technologies. This leaves potential consumers confused, cautious, and even vulnerable to poorly installed systems. As with product standards, certification is essential for consumer confidence in the industry.
The problem is particularly acute for the solar thermal and ground source heating markets. Both the Canadian Solar Industries Association and Canadian Geo-exchange Coalition have identified a pressing need to develop training programs and certification schemes. The Geo-exchange Coalition notes that “[w]e receive phone calls everyday from desperate customers trying to decipher who does what and who is accredited by whom, under which authority, and so on. In many cases those customers finally decide not to proceed with an installation because of the lack of market cohesion. They are afraid and confused.” (Tanguay, 2006).
Zoning and planning restrictions
Local by-laws and planning rules are usually designed without consideration of micro-renewable technologies. As a result, permitting and planning processes can be expensive and time consuming, as no set procedures are in place. For example, zoning policies such as height restrictions frequently do not include small wind turbine towers in lists of exempt structures (such as silos, water towers, and church spires). A recent review suggested that:
"Few if any municipalities, regions, provinces or other government structures possess an ideal package of policies governing small wind turbines." (Rhoads-Weaver et al, 2006).
In Ontario, other zoning problems have occurred when municipalities question the use of renewables in residential areas. Since the introduction of the Standard Offer Program, there has been at least one case where a resident in an areas zoned as ‘residential’ has been instructed not to install microgeneration equipment, as this has been seen as ‘commercial activity’ by the municipal authority (Ontario Power Authority, 2006).
Many municipalities do not have the capacity to develop renewable-friendly zoning and permitting policies, and are often unfamiliar with the technologies. Without support and direction from provincial governments and organizations such as the Federation of Canadian Municipalities, these local-level barriers will remain.
Awareness and mindsets
In an energy system dominated historically by large, centralized power generators and heating fuel providers, many homeowners, developers, and policy-makers simply do not know about, or understand, alternatives.
The microgeneration industry consistently cites lack of awareness as a major barrier across a range of technologies, including small wind (Marbek and GPco, 2005), solar thermal (Ipsos-Reid, 2002; SAIC, 2005; where it was the single most frequently cited barrier), solar PV (Industry Canada, 2003) and bioenergy (Canadian Bioenergy Association (CanBIO) 2004). Customers and developers are ignorant as to the costs, benefits, performance, and often even the existence of many microgeneration technologies. While industry associations and the federal government’s CanREN website provide useful information to potential consumers, there is no single source of information for residential scale renewables, for homeowners to find out what would, or not, work for them.
Another problem are the misconceptions about microgeneration technologies. For example, many environmental NGOs have not been supportive of biomass combustion technologies, believing them to be a serious air pollution hazard. The Greater Vancouver Regional District prohibits biomass combustion unless emissions are less than natural gas combustion (Bradley, 2005), even though certified clean burning stoves and fireplaces can reduce smoke emissions by 90% compared with conventional wood systems. (Government of New Brunswick, 2001).
It is not just consumers' and developers' lack of knowledge and absence of information, which act as barriers to the diffusion of microgeneration technologies. It is also the mindsets of policy-makers and utilities, accustomed to a model of centralized generation and control. Challenging and broadening this mindset is one of the challenges for microgeneration policy.
Progress in Canada: removing barriers to microgeneration
Canadian governments have recognized many of the benefits of microgeneration technologies, and both federal government and provincial governments have taken important steps to remove barriers and enable growth in microgeneration markets. Canada does not, however, have an integrated strategy for moving the implementation of microgeneration renewables forward. Indeed, existing mechanisms, which support microgeneration renewables are fragmented, and Canada’s flagship renewable energy support structures specifically exclude the microgeneration sector. While these policy measures have been carefully designed to foster renewable energy technologies at least cost, they miss opportunities to promote microgeneration.
Canada’s principal federal mechanism for supporting wind power, the Wind Power Production Incentive (WPPI), provides a guaranteed price, or feed-in tariff for electricity produced from wind. The WPPI excludes wind installations of less than 500kW, although it does have a lower cut-off of 20kW for remote and northern communities. Similarly, while the current status of the Renewable Power Production Incentive (RPPI), announced in the 2005 budget, is unclear, Natural Resources Canada’s September 2005 Discussion Paper on the RPPI suggested that it would only include technologies with a capacity of greater than 100kW (Natural Resources Canada, 2005).
The Renewable Energy Deployment Initiative (REDI) was established in 1998 to provide $51m over 9 years to solar air and water heating and biomass heating in commercial buildings. It provides up to 25% of the cost of these systems, and in 2002 support from REDI was extended to ground source heat. While it has provided much needed support for the development of the renewable heat industries in the commercial sector, and is considered to have been a successful program, it has not engaged with homeowners to bring renewable energies to a wider market.
Similarly, the Class 43.1 Capital Cost Allowance tax incentive for the purchase of renewable energy equipment has been valuable for supporting the small wind market (Marbek and GPco), but it excludes most applications of renewable heat technologies, and there is a cut-off limit under 3kW for solar PV. This is above what most homes would choose to install. Canadian Tire, which started selling small wind and solar PV technologies, advertises an on-grid solar system with a rated capacity of 2.8kW, just under a cut off of 98% of solar PV installed in Canada is below 3kW (Canadian Solar Industries Association (CanSIA), 2004).
In general, provincial governments have been better at targeting support to micro-renewables, with PST exemptions or rebates on renewable energy purchases such as offered in PEI, BC, and Ontario. Several provinces have also developed grants for renewable equipment purchases: Nova Scotia provides a 10% rebate for solar water heating, and $200 for certified clean-burning woodstoves, while the Quebec Energy Efficiency Fund provides $400 towards solar wall installations, a form of active solar air heating. In BC, a project of the BC Sustainable Energy Association, partnered with provincial and federal governments, Vancity Credit Union, and BC Hydro, is providing support for homeowners and communities to access rebates for solar hot water systems.
There are signs that the federal government is considering some form of incentive for supporting microgeneration. In September 2006, Environment Canada issued a request for proposals for work assessing different possible economic instruments to provide incentives for small renewables in the home and farm sectors.
Progress for microgeneration has been made
Despite the lack of a federal incentive program or integrated strategy, Natural Resources Canada2 and a range of industry associations and other stakeholders have, however, made progress over the last few years in tackling some of the more systemic barriers. This is vital – incentives and financial support will not be sustainable if the regulatory frameworks and supporting institutions are not in place to allow the market to become self-sufficient. Poorly targeted incentives can create industries with a culture of dependency, with no incentive to drive down costs and build more robust markets.
Grid access and interconnection standards
For electricity generating technologies, the potential problems of interconnection to the grid have been addressed, since 2001, by Micropower Connect, run by Electro-Federation Canada , and supported by Natural Resources Canada and Industry Canada. Micropower Connect has worked to develop guidelines for interconnection of distributed electrical resources, and published a set of guidelines in 2003. This was followed with a review of the status of interconnection guidelines, codes and standards in Canada in 2006, which made recommendations for uniform interconnection standards to be adopted across Canada. Power generation and infrastructure are provincial responsibilities, and the report argued that:
“It is important that provincial regulators understand the importance of adopting national or international standards, and enforcing consistency within their jurisdictions.” (Micropower Connect, 2006).
In 2006, a new National Standard of Canada was issued covering grid interconnection of microgeneration technologies, providing a basis for harmonized rules across Canada.
While many provinces still need to develop effective interconnection rules, the models and standards now exist, with Micropower Connect having done much of the initial work, and providing a forum for interconnection guidelines to move forward.
Restructuring markets: export price agreements for microgenerators
The way in which utilities manage energy resources, including microgeneration, is governed by provincial rules, resulting in a variety of different approaches across Canada. Around 8 major utilities now have net metering programs (Henderson and Bell, 2003), with the programs in BC and Ontario particularly well advanced (NewERA, 2006). Several others have other grid-connection and compensation programs that are less generous than net metering, but that provide some payment for electricity exported to the grid (Henderson and Bell, 2003).
Net metering schemes include all forms of micro and distributed generation, including those based on fossil fuels, such as natural gas combined heat and power. The only current example of a production incentive specifically aimed at renewable distributed generation in Canada is the Ontario Power Authority’s Standard Offer Program, which provides a guaranteed price for electricity generated from renewable resource installations under 10MW. This is a complementary program to Net Metering, which also operates in Ontario, and customer-generators can choose which program will suit them best. Ontario’s Standard Offer Program issues 20-year contracts, providing consumer-generators with a guaranteed income from their power system for 20 years. While it is too early to draw robust conclusions about the impacts of the program, the Canadian Solar Industries Association (CanSIA) estimates a 400% increase in sales of grid connected PV in the first half of 2006 (CanSIA, 2006). In total, 250 kW are reported to have been installed in Ontario as a result of the program, more than double the capacity of grid-connected solar PV in Canada as a whole in 2004.
Supporting the industry: product codes and standards, training and accreditation, and the support of industry associations
New industries take time to build the institutional strength that supports the development of markets, and the capacity to address regulatory and other issues. Industry associations are one way in which industries can act together to overcome common barriers. The federal government has provided support to a number of Canadian industry associations representing the microgeneration industry, either with core funding or for specific projects. This includes the Canadian Geo-exchange Coalition, the Canadian Bio-energy Association (CanBIO), the Canadian Wind Energy Association (CanWEA) and the CanSIA.
Government support has been also been available for the development of product standards and training and certification programs. For example, NRCan has been working with CanSIA to provide 90% of the costs of certification for solar hot water systems. The Canadian Geo-exchange Coalition is also working with NRCan to develop both product standards and a training and certification system for installers.
Other support has been targeted at raising awareness of small scale renewables. This has included, for example, funding for the Canadian Wind Energy Association to develop a ‘small wind’ website, to provide information to potential customers, policy-makers and investors on the options for small wind power in Canada. Natural Resources Canada's Canadian Renewable Energy Network (CanREN) website also provides information and case studies on microgeneration.
Clean power to northern communities
The Aboriginal and Northern Community Action Plan (ANCAP) was developed to help northern communities respond to the challenges of climate change, through adaptation and through greenhouse gas reductions. This includes supporting renewable energy projects, as well as resource estimation (through a Wind Assessment program), and community energy planning in remote communities across Canada.
Microgeneration in the planning system
This study is unaware of any clear examples of provinces or municipalities actively streamlining efforts to get micro-renewables through the planning system more quickly. There are many Canadian municipalities, however, that have installed small-scale renewable systems in their communities, often as part of initiatives to reduce the carbon footprint of civic buildings. The federal ‘Green Municipal Funds’, administered by the Federation of Canadian Municipalities, has been an important source of support for many of these communities. One example is the Drake Landing subdivision in the City of Okotoks, Alberta. A solar seasonal storage system will provide 90% of the heating needs for the 74 homes involved.
Microgeneration offers a real opportunity for Canada. It can reduce greenhouse gases, provide opportunities for Canadian businesses, and engage the public in the fight against climate change. At the moment, that opportunity is being overlooked. Many of most important barriers have been overcome, however, and there is real potential for an integrated microgeneration strategy to bring clean and reliable microgeneration within reach of Canadian homeowners and businesses, allowing microgeneration to move from niches into mainstream markets.
A microgeneration strategy for Canada
A Microgeneration Strategy for Canada would consider including some of the following points:
- Set ambitious, but realistic, targets for the uptake of microgeneration in Canada. Targets would be based on analysis of the potential market for microgeneration in Canada (similar to work carried out in preparation for the UK’s Microgeneration Strategy – Energy Savings Trust et al, 2005). This would provide a clear signal of the federal government’s intention to remove barriers to microgeneration, stimulate private sector support, and raise awareness of microgeneration.
- Consult industry views on the establishment of a microgeneration industry association or forum, which would provide policy-makers, developers and customers with a single point of contact for the industry, and provide a space for discussing how best to move forward with support for microgeneration. Such a body should include utilities, as well as microgeneration technology companies.
- Develop a web-based information hub, possibly managed by an industry association, to enable customers and developers to access information on technologies, incentives, prices, and certified products and installers. This would build on the work of the existing CanREN website.
- Support for industry to develop appropriate codes and standards, and accreditation schemes.
- Support for training schemes for installers and technicians.
- Establish a process for the harmonisation of interconnection and metering codes and standards across Canada, leading to uniform codes and standards across all Provinces. This would build on the work of Micropower Connect.
- Lead by example, through a program of public procurement of microgeneration building on the Federal House in Order’s On-site Generation at Federal Facilities program.
Federal or provincial incentives
Measures to encourage consumer uptake could be funded through a ‘public benefit charge’ on energy bills, which is essentially a hypothecated tax earmarked for microgeneration support.
- Tax incentives: Sales tax rebates, expansion of the federal Capital Cost Allowance class 43.1 to all microgeneration technologies.
- Grant schemes or ‘buy downs’, to reduce the capital costs for microgeneration customers. Capital grant schemes must be carefully designed to ensure that incentives for cost reduction remain, and that a subsidy-dependent industry does not develop.
- Feed-in tariffs, providing a guaranteed price for electricity generated by microgeneration.
- Low interest loans, or ‘net financing’ schemes, where loan repayments equal energy bill savings from the microgeneration installation. A program for farmers, who often have high energy costs and abundant opportunities for microgeneration, would be particularly valuable.
- Require utilities to provide fair export prices for customer-generators, such as net metering arrangements.
- Support microgeneration through building codes, for example, by introducing a requirement for buildings to be ‘solar retro-fit ready’.
- Enable and encourage municipalities to develop innovative policies to promote microgeneration through the planning system. ‘Merton Rule’ style policies, which make the incorporation of renewable energy a requirement of development, would currently not be legal in most Canadian municipalities. Provincial legislation covering the powers of local governments could change to promote such policies.
- Lead by example, through the public procurement of microgeneration technologies for public buildings.
Municipalities can take three broad approaches to supporting microgeneration renewables within their communities.
- ‘In-house’ microgeneration. Most municipal efforts to promote small scale renewables to date have focused on the development of renewable energy in municipal buildings. This provides examples of leadership within local communities, but municipalities can do much more beyond their own operations.
- Enabling microgeneration. Removing barriers to the installation of microgeneration is essential in fostering microgeneration markets. Municipalities can adopt streamlined permitting rules for renewables, such as the model zoning guidelines for small wind developed by the Canadian Wind Energy Association (Rhoads-Weaver et al, 2006).
- Promoting microgeneration. Municipalities can go further than simply removing planning and zoning barriers by taking an active lead in promoting microgeneration through the planning system. Although ‘Merton Rule’ policies are not currently possible in most Canadian municipalities, other possibilities include reduced development permit fees, and making the inclusion of on-site renewables a consideration in re-zoning applications.
The potential for municipal action to enable and promote microgeneration through the planning system should not be underestimated. The National Round Table on the Environment and the Economy estimated that a third of the buildings that will be standing in Canada in 2050 have not yet been built (NRTEE, 2006). This is a massive opportunity to change the way in which energy is produced and consumed.
- It is not only in the UK that municipal planning policies have fostered microgeneration. In Spain, a policy pioneered by Barcelona required all new buildings to source a percentage of their hot water needs from solar water heating systems. This policy was taken up by dozens of other municipalities, and in 2006, entered the national building code.
- In particular, Natural Resources Canada's Integration of Decentralised Energy Resources program run by CETC-Varennes.
Resources and References
Anon, 2003. Poll shows Canadian enthusiasm for renewables. Article on a poll conducted by Environics Research Group. Refocus Weekly, October 1st, Toronto.
Ayoub, J. & L. Dignard-Bailey. 2003. Photovoltaic technology status and prospects: Canadian annual report 2003. Canmet Energy Technology Centre – Varennes, Natural Resources Canada.
Ayoub, J., Dignard-Bailey, L., and A. Filion. 2000. Photovoltaics for Buildings: Opportunities for Canada: A Discussion Paper, Report # CEDRL-2000-72 (TR), CANMET Energy Diversification Research Laboratory, Natural Resources Canada, Varennes, Québec, Canada.
Bradley. 2005. Canada Biomass-Bioenergy Report. Climate Change Solutions, Ottawa.
CanBIO, 2004. Barriers to increased bioenergy use and some solutions. Canadian Bio-energy Association, Ottawa.
CanREA, 2006. Distributed generation in Canada: maximising the benefits of renewable resources. Model National Renewable Energy Strategy for Canada. Canadian Renewable Energy Alliance.
CanSIA. 2006. Sales of grid connected PV systems soar in Ontario. Canadian Solar Industries Association Press Release, July 24th 2006.
CanSIA. 2004. Towards a sunny future for Canada: Federal fiscal policy recommendations for empowering Canadians to make their own contribution to climate change through the use of solar technologies. Canadian Solar Industries Association Report C02, Ottawa.
CETC-Varennes Building Program, accessed October 11th, 2006.
Clover, C. 2006. Power struggle over miniature wind turbines. Daily Telegraph, 13th March 2006, London.
CMHC. 2006. Photovoltaics – Maximising performance and assuring a safe installation. Photovoltaic Factsheet, Canadian Mortgage and Houseing Corporation, Government of Canada. Accessed on October 11th 2006.
Collins, J. 2004. A Microgeneration Manifesto. Green Alliance, London.
Dobbyn & Thomas 2005. Seeing the light: the impact of microgeneration on the way we use energy. Report for the Sustainable Consumption Roundtable. UK Sustainable Development Commission, London.
DTI, 2006. Our Energy Challenge: Power from the People. The Microgeneration Strategy, Department for Trade and Industry, HM Government, London.
Dutton, Halliday, and Branch, 2005. The feasibility of building mounted/integrated wind turbines (BUWTs): Achieving their potential for carbon emissions reductions. Final Report. Report for the Carbon Trust. Energy Research Unit, Rutherford Appleton Laboratory, CCLRC, UK.
Environment Canada. 2006. Evaluation of the One-Tonne Challenge Program. Government of Canada, Ottawa. Available online at:
Government of New Brunswick. 2001. White Paper: New Brunswick Energy Policy. New Brunswick Natural Resources and Energy, Fredericton.
Henderson & Bell 2003. Small-scale renewable energy systems, grid connection and net metering: an overview of the Canadian experience in 2003. Report to the Canadian Mortgage and Housing Corporation, Government of Canada.
Industry Canada. 2003. Unleashing the power of on-grid photovoltaics in Canada: an action plan to make PV an integral component of Canada’s energy future. Industry Canada, Ottawa.
Ipsos-Reid 2002. Survey to gauge awareness, knowledge and interest levels of Canadians toward solar domestic hot water systems: Final Report. Report to Natural Resources Canada, Ottawa.
Keirstead, J. 2006. Microgeneration in the News. Small is beautiful blog, 26th April 2006.
London Borough of Merton. 2006. The Merton Rule 10% Policy Briefing. Informal Briefing Note, London Borough of Merton.
McGonagle, R. 2006. Toronto as a solar city. Dan Leckie Forum, May 29th 2006, Toronto.
McGonagle, 2006b. Plumbing inspectors solar hot water workshop. Canadian Solar Industries Association, March 31st, 2006.
Micropower Connect 2006. Connecting micropower to the grid: a status and review of micropower interconnection issues and related codes, standards and guidelines in Canada, 2nd Edition. Report to Natural Resources Canada, Industry Canada, and Electro-federation Canada.
Morris, R. 2006. The solar and wind resource in Canada. Pollution Probe Green Power in Canada Workshop, Montreal, November 3-4, 2003.
National Energy Board, 2005. Outlook for electricity markets 2005-2006: an energy market assessment. Government of Canada, Ottawa.
New Energy Resources Alliance. 2006. A review of net metering policy and practice in Canada. New Energy Resources Alliance, Calgary, AB.
Natural Resources Canada. 2005. Renewable Power Production Incentive: a discussion paper Natural Resources Canada, Ottawa.
National Round Table on the Environment and the Economy. 2006. Advice on a long term strategy on energy and climate change. Report of the National Round Table on the Environment and the Economy, Government of Canada, Ottawa.
Ontario Power Authority 2006. Question SOP12858M, Standard Offer Program Q&A. Accessed October 11th 2006.
Perez, R. & B. Collins. 2004. Solar energy security: could dispersed PV generation have made a difference in the massive North American blackout? Refocus July/August.
REEEP. 2003. The Renewable Energy and Energy Efficiency Partnership (REEEP) Background paper for the North American regional meeting. 7th July 2003, Washington, DC.
Rhoads-Weaver, Asmus, Savitt Schwartz, MacIntyre, Gluckman, Healey, 2006. Small wind siting and zoning study: development of guidelines and a model zoning by-law for small wind turbines (under 300kW). Report developed for the Canadian Wind Energy Association.
SAIC 2005. Survey of active solar thermal collectors, industry and markets in Canada: Final Report. Report to Natural Resources Canada, Ottawa.
Scottish and Southern Energy (2006). Scottish and Southern increase investment in microgeneration. Scottish and Southern Energy Press Release, 5th May 2006.
Smiley, 2002. Building integrated solar photovoltaic and small-scale wind. Green energy study for British Columbia. BC Institute of Technology, Burnaby, BC.
Tanguay, D. 2006. Setting the record straight. Geoconnexion – the Newsletter of the Canadian Geo-Exchange Coalition, May, 2006.
Umedaly, M., 2005. A vision for growing a world-class power technology cluster in a smart, sustainable British Columbia. Report of the Power Technology Task Group to the Premier’s Technology Council, Victoria.
Unruh, C, 2002. Understanding carbon lock-in. Energy Policy 28: 817-830.
WADE 2005. Projected costs of generating electricity (2005 update): WADE’s response to the report of the international energy agency and the nuclear energy agency. World Alliance for Decentralized Energy.
World Bank. 2002. World Development Indicators on CD-ROM. World Bank, New York.
Deep Water CoolingDeep Water Cooling
Published September 19, 2006
Deep water cooling involves using naturally cold water as a heat sink in a heat exchange system, thereby eliminating the need for conventional air conditioning. We compare deep water cooling systems in Halifax, Nova Scotia and Toronto, Ontario, and find that this technology has significant ecological benefits and long-term economic benefits. This technology requires that a client with a large cooling need is situated near a deep, cold body of water, and payback times vary depending on the site. Diffusion is hindered by the low cost of energy. The City of Toronto's approach, in which many buildings are serviced at once while piggybacking onto existing water piping and pumping capacity, can deliver cost savings on a shorter time span. Other locations in which heavy air conditioning users are located next to deep, cold water bodies could use this technology to encourage sustainable building.
Sustainable Development Characteristics
In many areas of the world including North America, air conditioning imposes a significant load on local electrical systems. Air conditioning is required even in temperate areas, as technologies such as lighting and electronic equipment produce significant indoor waste heat that must be vented to the outdoors. Cooling can be particularly troublesome as it is thermodynamically more difficult than heating and demand is intermittent; air conditioning demand can trigger summer brownouts and voltage drops on hot summer afternoons. Air conditioning currently consumes 18 percent of US electrical output (Cox, 2006); any technologies that can considerably lower the energy demand of air conditioning will create a significant drop in electrical use and mitigate the associated environmental concerns of greenhouse gas emissions and local air pollution.
Conventional air conditioning functions by transferring heat from the air to a chilled medium, and then uses a compressor, motor, and refrigerant to transfer the heat from the chiller medium to the outdoors. If it is warmer outside than inside, heat must be pushed “uphill”, a very energy intensive operation. Significant energy savings can be realized if heat can instead be transferred to a mass of cooler material with a high capacity for absorbing heat, such as water, eliminating the need for a compressor-based cooling cycle. Water is not only a good heat sink, it also has an unusual relation between its density and its temperature. Like most substances, water becomes denser as it cools, but unlike most substances it reaches a maximum density at 3.9 degrees Celsius. As a result, in winter, cold water on the surfaces of oceans and lakes cools and sinks through the warmer water below. In summer, the warm surface layers float on top of the cooler water below, as it is less dense. A layer of perpetually cold water is created below a certain depth, known as the hypolimnion.
Over the years, there have been many suggestions on how to utilize this cold water; for an exploration of some of these suggestions, see (Lennard, 1995). One of the simplest applications, however, involves pumping hypolimnion water to the surface and using it as a heat sink. Hypolimnion water would be pumped from the water body and into a heat exchange unit where it comes into contact with a closed cooling loop. The heat exchanger takes the place of the traditional “chiller” or air conditioner.
Energy savings of up to 90% over conventional air conditioning can be achieved, depending on how the system operates. The system requires only the energy to run the pumps and the fans that blow air over the cooling loops. As conventional air conditioning units are no longer needed, the need for ozone harming chemicals such as CFCs would be eliminated.
Though the impact of deep water cooling is generally positive, some concerns have been raised that, if overused, the cold water source could experience “heat pollution”, which would negatively affect habitat and species composition. In the oceans, such effects might occur at the local level, but the amount of heat involved is too small to have a large scale effect. Lakes are another matter. A study of Lake Ontario estimated that up to 20,000m3/s of water could be withdrawn from the lake and used for cooling without changing its physical properties (Boyce et al, 1993). For the Great Lakes, the maximum draw amount is very large. The maximum amount will be lower for smaller lakes, however, and must be taken into account in discussions on the sustainability of deep water cooling using lake water. The projects discussed followed established procedure for construction in coastal area, but long-term effects might not yet be known.
The opportunities in Canada for expanding deep water cooling are quite large. Both Halifax and Toronto could greatly increase their use of this technology without creating a serious environmental hazard. Other cities that could take advantage of this technology include Victoria, Vancouver, Prince Rupert, Hamilton, Yellowknife, Kingston, and St. Johns. As well, there are hundreds of smaller centres located next to deep bodies of cold water that could utilize this form of cooling. One of the theoretical barriers to future expansion is what Gregory Unruh calls “carbon lock-in” (2000), as energy technologies have co-evolved to require carbon-based fuel and their return-on-investment increasingly favours large scale technologies and discourages the diffusion of non-carbon options, even if economically sound.
Critical Success Factors
Success in both of the study cases hinged upon the private-public partnership model. This model provided the means to overcome the high up-front costs associated with this technology.
In the City of Toronto case study, what really pushed the project forward was the pairing of deep water cooling and deeper water intakes for the drinking water supply. In effect, two major projects were combined into one, a good use of holistic planning processes that differed quite a bit from more traditional planning processes where different infrastructure needs are considered separately. Enwave’s Kevin Loughborough reported that this is the first such combination of uses with this technology. Toronto’s success was also supported by the establishment of Enwave as a “middleman”. Individual developers didn’t have to install the infrastructure, they just had to make the choice to hook into the cooling network. The Toronto project succeeded as it had support from individuals in government and in business. The Purdy’s Wharf project went forward because the developer was willing to take a risk on fairly new technology. The projects' “champions” worked together to move their projects over various hurdles.
Community Contact Information
Enwave can be contacted through their press office at http://www.enwave.com/contact_us.php; the corporation is interested in developing other deep water cooling projects. Purdy’s Wharf is a private development.
Each project achieved its goal to significantly lower energy use. Economies of scale seem to be applicable here as well; larger projects might be more practical as a bigger cooling load can be displaced with a similar initial infrastructure layout. Each building that hooks onto the Enwave system lowers the cost per displaced kWh. The larger and newer project in Toronto, which continues to expand, has attracted more attention partly due to its location in a city experiencing significant smog problems and electricity shortages. The Purdy’s Wharf project, however, demonstrates that, in certain situations, deep water cooling technology can also work successfully on a smaller scale.
What Didn’t Work?
The Purdy’s Wharf project did not create a widespread adoption of the technology even though it is considered a successful project. This probably was due to the low cost of energy at the time of the project, a lack of comparable projects, and as it was one of the first in the world. Also, a developer wanting to mimic the Purdy’s Wharf project would have to start from scratch as the infrastructure has capacity for only the one development. One could say that deep water cooling has now hit a “critical mass” of sorts with several large projects in the planning phase, including projects in Hawaii and the Persian Gulf. Kevin Loughborough says the main factor in a successful deep water cooling project is geography. Key ingredients for successful projects are a high density cooling cluster located near a renewable cooling resource.” (Loughborough, per. comm.)
Financial Costs and Funding Sources
The Purdy’s Wharf project was funded jointly as a demonstration project by the development company, JW Lindsay Enterprises Limited, and the federal government. Reports of the costs vary, but there is a general agreement that the cooling system paid for itself in a little over two years. Currently, the cooling system saves the complex over $100,000 in energy costs and maintenance costs. The largest expense is the pumping cost, plus the minor expense of copper anodes.
Toronto Deep Lake Water Cooling
The Toronto deep lake water cooling project was a major project with initial expenditures near the $200 million range (Canadian Press, 2003). Capital costs continue as the urban pipeline network expands. The project was a public-private partnership: $33 million was funded by the City of Toronto’s pipe repair fund (Moloney, 2004), the federal government provided low-interest loans, and Toronto Hydro provided incentives to companies to hook their buildings up to the system in order to overcome the high initial capital cost. Kevin Loughburough of Enwave commented on the up-front costs:
“The pay back on the project requires a patient investor. It can be compared to a hydroelectric dam project in that it is capital intensive at the front end, but costs very little to operate over the long-term. The return on the project is competitive with other investments.” (Loughborough, per. comm.)
This case study involved interviews and a literature search. It reveals that deep water cooling projects deliver impressive energy savings, but that initial investment is high and serves as a barrier to development. The case studies suggest that large-scale installations of this technology are better positioned to overcome the inertia of the high start-up cost and high payback time. An intermediate agency that bears the infrastructure costs and the initial risk can be useful in encouraging developers to use the technology. Sites with year-round access to deep water cooling might be preferable, and support for start-up costs is a major factor in the success of these projects.
Detailed Background Case Description
This case study involved a background literature search and the investigation of two deep water cooling projects in Canada. The first project is the Purdy’s Wharf project on the waterfront of Halifax, Nova Scotia, which was constructed in 1986 and expanded in 1989. The second project is the Enwave Corporation’s Toronto Deep Lake Water Cooling Project, which began to provide cooling to buildings in 2004 and continues to expand.
The two projects are both public-private partnerships, but represent vastly different scales of application of the technology. The cooling media is also different. Purdy’s Wharf draws upon seawater and Toronto’s project uses fresh water.
The Purdy’s Wharf office complex sits on the waterfront of Halifax, and buildings extend out over the harbour on pilings. Cold seawater is drawn from the bottom of the harbour through a pipe to a titanium heat exchanger in the basement of the complex where the closed loop of water, cooled by the sea water, is then pumped to each floor of the building where fans blow air over the cooling pipes to cool the air. The seawater is returned to the harbour floor. The project was jointly funded by the Government of Canada and the building’s developer, and was intended to serve as a demonstration of the technology. The project was constructed from 1983 to 1989 and consists of an 18-story tower, a 22-story tower, and a four-story retail centre. The total area cooled by the system is 65,000 sq. meters.
The Purdy's Wharf Deep Water Chiller
Purdy’s Wharf required innovative technologies in order to mitigate the corrosive power of seawater. Piping is corrosion-resistant polyvinyl and polystyrene. The pumps are made of stainless steel. One of the challenges to this project was to control marine growth. Initially, chlorine was used to prevent marine growth in the system, but this was both costly and potentially environmentally damaging. The chlorine system was replaced by cathodic protection provided by copper plates.
To provide proper cooling, the water temperature must be below ten degrees Celsius. The intake for the pumping system is located less than two hundred meters offshore at a depth of 18 meters where conditions are appropriate for cooling for ten and a half months a year. Purdy’s Wharf operates conventional chillers in the late summer when harbour temperatures are too high. Mapping of the harbour water temperature column was provided by the Bedford Institute of Oceanography and the Fisheries and Oceans Research Lab.
Toronto Deep Lake Water Cooling
The Enwave Corporation’s deep lake water cooling project is a much larger project than the Purdy’s Wharf initiative. Pipes extend five kilometers into Lake Ontario and draw water from a depth of 83 meters to the John Street pumping station where heat exchangers cool Enwave’s closed cooling loop that snakes through downtown Toronto. Lake water, slightly warmed, then goes on to supply Toronto with drinking water. This sharing of drinking and cooling water saves pumping water out of the lake twice, and the new deeper water intake solved the problem of algae blooms tainting Toronto’s water in the summer. The idea of providing cooling to Toronto using lake water had been considered at various times, but the project began in earnest in 2002 (Deverell, 2002). As of June 2006, 46 buildings were signed onto the system of which 27 were already connected (City of Toronto, 2006). As the system nears capacity, energy savings will be 85 million kWh, for a CO2 reduction of 79,000 tonnes annually, or the equivalent of 15,800 cars. The total cooling load will be 3,200,000 square meters, or fifty times the area of the Purdy’s Wharf complex. 61% of this capacity has been sold. (City of Toronto, 2006). There is some discussion to expand the system once capacity is reached. Energy savings are about 90%, and as the required cold water is available year-round, the need for supplementary chilling is eliminated. The Toronto project is jointly-owned: 57% by the municipal pension fund and 43% by the City of Toronto, and is thus an example of a public-private partnership.
Does the outfall of warm water cause ecological damage in a Halifax-style project?
What mechanisms could best encourage this sort of project? An end to energy subsidies, a carbon tax, grants, or further public-private partnerships?
- Would more demonstrations projects help to speed the diffusion of innovative infrastructure choices?
Resources and References
Boyce, F, Hamblin, P, Harvey, L, Scherzer, W, & R. McCrimmon. 1993. 'Response of the Thermal Structure of Lake Ontario to Deep Cooling Water Withdrawals and to Global Warming.' Journal of Great Lakes Research 19(3) 603-616.
Candian Press, 2003. “Lake Water to Cool Downtown” Toronto Star. Feb 28, E11.
City of Toronto “Deep Lake Water Cooling and the City”
Cox, Stan 2006. Air Conditioning: Our Cross to Bear. AlterNet.
Deverell, J. 2002. “Enwave Launches Deep-Lake Cooling Project” Toronto Star. June 20, B02.
Lennard, D. 1995. 'The Viability and Best Locations for Ocean Thermal Energy Conversion Systems Around the World.' Renewable Energy 6(3) 359-365.
Molony, P. 2004. “Pipe Funds Diverted” Toronto Star, May 24, B02.
Unruh, G. 2000. 'Understanding Carbon Lock-in.' Energy Policy 28, 817-830.
Energy Efficiency for HomeownersEnergy Efficiency for Homeowners
Josh McLean and Chris Ling
Published February 28, 2007
As a Kyoto Protocol signatory, Canada initiated some programs to reduce greenhouse gas emissions. The federal government's EnerGuide for Houses (EGH) program provided financial incentives to encourage homeowners to increase the energy efficiency of their homes (related to heating and cooling). Despite the government grants and the financial benefits to be gained from energy savings, the number of homeowners following through with upgrades in the EGH program was relatively low. This case study examines why homeowners took part in the EGH program and what types of barriers they encountered during, or prior to, renovations. 75 participating homeowners in Halifax Regional Municipality (HRM) were surveyed, and eight experts interviewed. Financial reasons was the main reason given by the participants for taking part in the program, but financial reasons was also cited as the principal barrier to completing the recommended upgrades. The case analysis also provides recommendations for any successors to the EGH program.
Sustainable Development Characteristics
The frequency and intensity of extreme weather events will continue to increase (leading to environmental, economic and social impacts) unless atmospheric greenhouse gas (GHG) levels are reduced. There is “a very high confidence” that natural ecosystems are already changing due to the impacts of climate change (Parmesan and Yohe, 2003). Examples of potential climate change impacts include more droughts, melting of mountain glaciers (Hyder (ed.), 2005), human health impacts from disease and air pollution, rising sea levels from melting polar ice, impacts to ecosystems and forests from changing weather patterns, and the associated economic impacts resulting from these changes (David Suzuki Foundation, 2006).
Reducing the use of fossil fuels will help reduce the severity of climate change impacts (Office of Energy Efficiency [OEE], 2005). Relative to its GDP, Canada produces 25% more GHG emissions than the average for the industrialized world (Bramley, 2005). On a per capita level, Canada is the second highest user of energy compared to other International Energy Agency countries (Luxembourg is the highest and the United States is the third highest) (Natural Resources Canada [NRCan], 2005a). Under the Kyoto Protocol, Canada agreed to reduce its GHG emissions, between 2008 and 2012, by 6% below 1990 levels (Government of Canada [GOC], 2005). In November 2002, Canada developed a Climate Change Action Plan with goals of reducing GHG emissions by 240 megatonnes per year. The federal government later ratified the protocol on December 17, 2002 (Canadian Broadcasting Corporation [CBC], 2006).
In April 2004, Environment Canada reported that Canada’s 2002 GHG emissions were 28% higher (731 million tonnes of GHG emissions) than the Kyoto target to be reached by 2012 (572 million tonnes). In 2005, the federal government increased its original reduction targets to 270 megatonnes per year by 2008-2012. Following the federal election in the spring of 2006, the Conservative party formed the new government and announced it would halt Canada's participation in the Kyoto Protocol to satisfy one of its election platform promises. Subsequently, Natural Resources Canada announced cuts to many climate change projects and, in October 2006, the federal government unveiled its new Clean Air Act, a ‘made in Canada’ approach that did not include the Kyoto Protocol (CBC, 2006).
Whether or not the federal government honours it, the Kyoto Protocol is not a final solution to the climate change problem. In fact, by 2050 global GHG levels should be 50-60% lower than 1990 levels in order to stabilize the GHG levels at twice that of the pre-industrialized area (GOC, 2005). Other groups, including the Pembina Institute and the David Suzuki Foundation, recommend even greater levels of reductions, 80% by the year 2050 (Bramley, 2005).
Approximately 17% of Canada’s energy use comes from the residential sector (NRCan, 2005b). This sector includes four types of housing: apartments, mobile homes, single attached homes (duplexes and row houses), and single detached homes (GOC, 2004). The majority (64.5%) of the residential buildings in Canada are single detached homes (7,191,540), followed by apartment buildings (18.5% - 2,061,257), single attached homes (15.5% - 1,721,416), and mobile homes (1.5% - 195,176) (NRCan, 2005c).
Critical Success Factors
Promotion of the federal EGH program was crucial to recruiting homeowners, however, in Nova Scotia many applicants to the EGH program were unaware of the matching grants program available from the provincial government, which affected the take-up rate of the federal program. If applicants had been made aware of the additional funds available from the province, this may have also resulted in more upgrades being implemented.
The key component of the EGH scheme was not only the grant available to homeowners, but included access to the audit opportunity and the specific recommendations and advice for homeowners for improvements in energy efficiences. Although the financial aspects of energy efficiency are the most important motivation, this related to cheaper energy bills in the long term, rather than the grant in the short term.
Community Contact Information
- The energy audits were a popular component of the program, with many respondents saying they would consider paying for an audit even if it was not part of a wider grant program.
- The advice and the recommendations are more important than the grant, as the majority of homeowners responded that they would have upgraded their homes with or without the grant – the audit and advice were key.
What Didn’t Work?
- Loss of support from the federal government was clearly a major problem, and most of those surveyed felt it was a poor decision.
- There was a lower number of homeowners conducting a ‘B’ audit and thus accessing the grant funding. This was due to planned upgrades not completed, or homeowners thinking there was little prospect of having achieved significant energy savings to be awarded a large enough grant to cover their costs, making the second audit unnecessary.
- Some homeowners felt that there was not enough time allowed under the program to complete the upgrades to qualify for the grant.
- Most homeowners felt that many upgrades were prohibitively expensive.
- Many homeowners were not aware of the availability of matching funding from the Government of Nova Scotia to complement the federal EGH grant.
- The grant process was confusing to applicants as it was difficult to predict how much grant the homeowner would receive after paying for the renovations.
Financial Costs and Funding Sources
Under the EGH program interested homeowners paid a fee (typically $150) to receive an energy audit on their home. The actual value of the audit was approximately $300; with the federal government subsidizing half of the upfront cost.
A federal grant of up to $4,580 was then awarded based on the change between the first audit (A) and the follow-up audit (B) ratings. The average grant awarded under the program was $780 (2005 figures).
Originally, funds were available for a homeowner’s principal residence. In July 2005, the individual grant level was increased (from $3,348 to $4,580) to include landlords' low-rise residential buildings meeting the criteria for the program (NRCan, 2005d). In the 2004-2005 fiscal year, over 77,000 homes in Canada received an EGH evaluation, and over 17,000 grants were awarded, worth over $10 million (NRCan, 2005a).
Additional energy efficiency incentives were available to Canadians participating in the EGH program. For example, $100 grants were automatically available for homeowners who replaced older gas or oil-fired heating systems with Energy Star rated systems. The Canadian Mortgage and Housing Corporation (CMHC) offered a 10% rebate on CMHC mortgage loan insurance premiums if buying a house with an EGH-rating of 80 or higher, or if renovating an existing home and increasing the EGH rating by at least 5 points (and having a minimum rating of 40) (CMHC, 2005). Some organizations offered zero or low interest loans to help finance the cost of the renovations. For example, the VanCity Credit Union in British Columbia offered low interest loans when borrowing money to pay for upgrades recommended by the EGH program (VanCity, 2006). The Government of New Brunswick, in addition to a $50 rebate on the cost of the EGH visit, also offered either a zero interest loan up to $10,000 to help pay for EGH-related renovations, or an HST rebate on the cost of renovations of up to $1,500 (Efficiency NB, 2006). Other financial incentives, as reported by Green Communities Canada [GCC] (2006c), existed for most provinces and some territories, and were normally offered through the provincial/territorial governments, utilities, gas providers, banks or credit unions.
The Government of Nova Scotia provided $4.5 million to support the EGH program incorporating:
- matching the federal grant up to $1,000;
- providing a rebate on the cost of the EGH A audit ($150) and an additional $400 to the available federal and provincial grants, for single seniors with incomes of less than $25,000 or to seniors with family incomes less than $40,000 (Nova Scotia Department of Energy [NSDE], 2005a); and,
- an energy savings kit (valued at $50) that contained products and materials to reduce energy use up to $100 per year.
Following the cancellation of the federal program the Government of Nova Scotia implemented the following:
- a provincial EGH-type of grant of up to $2000;
- any low to modest income citizens, with single net incomes of less than $25,000 or family incomes of less than $40,000, were provided a rebate on the cost of their EGH audit, and an additional $400 was added to the EGH provincial grant; and,
- an energy savings kit (valued at $50) to all EGH participants (NSDE, 2006a).
As of November 2006, the province also offered the following:
- a $200 rebate when purchasing an efficient wood burning appliance (pellet stove or an Environmental Protection Agency (EPA) certified wood stove);
- a 10% discount on the installation cost of a solar hot water heating system;
- up to a $750 rebate for buying an energy efficient oil burning furnace or boiler and indirect hot water tank;
- rebates on high efficiency natural gas heating equipment (although natural gas was only available in a small geographical area); and,
- either a full or partial subsidy to pay for EnerGuide for New Houses (EGNH) evaluations (NSDE, 2006b).
The average income of homeowners taking part in the EGH program was higher than the average for HRM, $78,000 as opposed to $46,946 (Statistics Canada, 2006) suggesting a potential financial barrier for applicants – suggestions to remove this financial barrier has ranged from upfront, interest-free loans to larger grants and other financial support.
- As the prime motivation of applicants taking part in any EGH or equivalent program is to reduce energy bills, it seems essential to stress the link between energy efficiency and saving money in any education or publicity program for energy efficiency – rather than the environmental benefits that these programs can provide.
- The federal EGH program suffered from a lack of partnerships between the three levels of government, utilities and other energy providers.
- There is a disconnect for homeowners between high energy bills and programs perceived as ‘environmental’ that espouse energy efficiency. A stronger link needs to be made in the publicity between these two perspectives.
- Other problems in achieving upgrades is the time to complete them and the lack of available contractors – any EGH administration could link homeowners to contractors able to carry out the relevant improvements.
A summary of the recommendations drawn from the case study research on the federal EGH program follows:
More funders allows for additional incentives (eg. zero interest loan).
Promote upgrades as an investment
Overcomes financial barriers (help it make financial sense).
Make zero interest loans available
Overcomes financial barriers (up front money to pay for renovations).
Conduct schedules follow up calls
Reduces information and knowledge barriers that occur after the A visit.
Replace the word ‘grant’
Reduce confusion about how program works (keep simple and easy).
Investigate options for contractor certification or education
Determines whether contractor certification is feasible in relation to government programs.
Research how grant amounts affect level of upgrades completed
Determines how program funds are most effectively used.
Target other groups
Allows more of the population to benefit from energy efficiency upgrades.
Detailed Background Case Description
The federal context
EnerGuide for Houses (EGH) is a residential energy efficiency program developed in the 1990’s and initiated in 1998 (GOC, 2006b). In August 2003, NRCan initiated the EGH Grants for Homeowners program in an effort to further reduce energy use (and associated GHG emissions) in the residential sector (GOC, 2006a). Under the EGH program, interested homeowners received an energy audit (‘A’ audit) on their home. A certified auditor evaluated the home for areas of inefficiency relating to heating and cooling. This included an investigation of the levels of insulation throughout the house, measurement and documentation of all windows, doors, heating, hot water, cooling and ventilation systems, and a blower door test that determined the level of drafts in the home. The house received an initial energy rating between 0 and 100. Typically, the older the home the less efficient it would be, and therefore the lower the rating. Upgrade options were modeled in a software program to determine the level of potential energy savings. A report was given to the homeowner with recommendations and advice on how to improve the energy efficiency of the home, presenting upgrade options in terms of their level of anticipated energy savings. Homeowners then had up to 18 months to complete the desired upgrades, after which a second evaluation (‘B’ audit) determined the new EGH rating.
A federal grant of up to $4,580 was awarded based on the improvement between the A audit and B audit ratings. The grant was based on the margin of improvement in the energy efficiency of the home rather than the amount spent on upgrades. By 2005, the average grant awarded to homeowners was $780 (NRCan, 2005d). Upgrades which could improve the space heating or cooling energy demands of the house, and thus the rating, included adding insulation, draft proofing, upgrading old windows and doors, and upgrading heating, cooling, ventilation and domestic hot water systems. On average, upgrades could help houses older than 25 years save 35% of energy use (OEE, 2005).
The Nova Scotia experience
From 1990 to 2001, the total emissions from the Nova Scotia residential sector grew by 8.2% (Hughes et al., 2005). The NSDE (NSDE, 2005b) provides similar results, with GHG emissions increasing by 10.5% between 1990 and 2003; a rate of increase that was identified to be less than many other provinces. Average energy use in homes in NS includes: space heating (64%), water heating (20%), appliances (12%) and lighting (4%) (NSDE, 2005c). By 2005, only 1% of the homes in Nova Scotia had received an EGH evaluation (Lipp and Cain, 2005).
In an effort to further reduce energy use, Nova Scotia ‘piggybacked’ onto the federal EGH program to promote energy efficiency upgrades in the province. On October 12, 2005, the NSDE announced its Smart Energy Choices program. Part of this program included an energy savings kit containing:
- Lighting: 2 LED night lights and 3 compact fluorescent light bulbs (CFLs);
- Water conservation: 2 faucet aerators and 1 low-flow showerhead;
- Draft proofing: 1 package of foam gaskets for outlets, child safety caps, a roll of v-strip weather stripping and a storm window kit (NSDE, 2006c).
As of March 2006, despite the available grants, the number of homeowners who had followed up with their audit B was relatively low. For example, Clean Nova Scotia (CNS), a non-profit environmental organization had conducted many of the firts EGH audits in HRM. By March 2006, the level of audit B visits (homeowners applying for the grant) was approximately 20% (McKegney, pers comm., 2006). Similar observations were noted by Bird (2006), where in Waterloo Ontario, one of the EGH delivery agencies (Residential Energy Efficiency Project) had evaluated over 6,300 homes, since 1999. By October 2005, however, only 12% applicants had conducted enough upgrades to receive an audit B visit and grant. This figure of 6,300 homes includes those that had been evaluated before the grant existed, although the trend of a low level of follow-up visits was similar. Although grants existed, to fully discover how to help homeowners reduce energy use it is necessary to understand the motivations of homeowners and the barriers that exist to increasing the home’s efficiency (Dodge, pers. comm., 2006).
Post federal EGH cancellation
On May 12, 2006, the new Conservative federal government cancelled the EGH program (GOC, 2006a). The cancellation affected those who had not yet taken part in the program. Homeowners whose audit A was completed by that date were still eligible for the federal grant. The 18-month timeline, however, was shortened for many applicants, as all files were required to be submitted to NRCan by March 31, 2007. EGH participants were encouraged by NRCan to have their audit B completed by February 28, 2007 (NRCan, 2007). Since the cancellation of the program, some provinces and utilities have taken steps to reinstate similar programs at the provincial level. On October 3, 2006, the NSDE announced that it had reinstated a provincial-level EGH program at least until March 31, 2007. The NSDE also offered additional incentives for purchasing energy efficient products.
In addition to these programs, NSDE’s Smart Choices for Cleaner Energy – The Green Energy Framework report outlined plans to participate in the anticipated federal EGH for Low Income Houses program, among other efficiency initiatives (NSDE, 2005d).
Taking part in the program
According to a survey of 75 Halifax-area homeowners who participated in the EGH program, the main motivations (in order of frequency of response) for taking part in the program were:
- to help reduce energy bills;
- to gain knowledge;
- to improve the home’s energy efficiency;
- to get the government grant;
- to help the environment;
- to improve comfort within the home, and
- because it was recommended by a friend or relative.
Participants undertook and planned the following energy efficiency upgrades:
|Basement / crawlspace insulation||18||17|
|Other energy upgrades not related to EGH||11||2|
|Exposed floor insulation||2||1|
|Adding a ventilation system||2||5|
|Building an energy efficient addition||1||0|
|Solar hot water panels||0||1|
|Domestic hot water tank||0||1|
Homeowners asked to identify the barriers faced in implementing the audit A's recommended improvements, cited concerns about the cost or affordability of the renovations, lack of time to complete the upgrades, and the availability of qualified contractors.
Resources and References
Bramley, M. (2005). The case for deep reductions – Canada’s role in preventing dangerous climate change. Vancouver: David Suzuki Foundation and the Pembina Institute.
Canadian Broadcasting Corporation. (2006). In depth Kyoto and beyond: Canada-Kyoto timeline. Retrieved February 30th, 2007 from: http://www.cbc.ca/news/background/kyoto/timeline.html
David Suzuki Foundation. (2006). Climate change impacts. Vancouver. Retrieved February 30th, 2007 from: http://www.davidsuzuki.org/Climate_Change/Impacts/
Efficiency NB. (2006). NB existing homes energy efficiency upgrades program. New Brunswick Energy Efficiency and Conservation Agency.
Government of Canada. (2004). Your guide to the one tonne challenge. Quebec.
Government of Canada. (2005). Project green: moving forward on climate change – a plan for honoring our Kyoto commitment. Quebec.
Green Communities Canada. (2006a). Home retrofit incentive grant. Peterborough.
Green Communities Canada. (2006b). Ottawa urged to restore popular EnerGuide for houses programs.
Green Communities Canada. (2006c). Programs that piggyback onto NRCan’s housing programs.
Hughes, L., Bohan, K., Good, J., & Jafapur, K. (2005). Calculating residential carbon dioxide emissions – a new approach. Energy Policy, 33, 1865-1871.
Hyder, M (Ed.). (2005). Global warming impacts bring China to the table. Global Environmental Change Report, 17, 1-4.
Lipp, J., & Cain, S. (2005). The energy accounts for the Nova Scotia genuine progress index. Halifax: Genuine Progress Index for Atlantic Canada.
Natural Resources Canada. (2005a). Improving energy performance in Canada – report to parliament under the energy efficiency act for the fiscal year 2004-2005. Gatineau: Government of Canada.
Natural Resources Canada. (2005b). Energy efficiency trends in Canada, 1990 to 2003. Quebec: Government of Canada.
Natural Resources Canada. (2005c). Survey of household energy use in 2003: detailed statistical report. Ottawa: Government of Canada.
Natural Resources Canada. (2005d). Eligibility criteria for grants under the EnerGuide for houses retrofit incentive. Ottawa: Government of Canada.
Natural Resources Canada (2007). Home improvement – important notice. Ottawa: Government of Canada.
Nova Scotia Department of Energy. (2005a). Energy plan will provide relief and savings - news release. Nova Scotia.
Nova Scotia Department of Energy. (2005b). Nova Scotia Power.
Nova Scotia Department of Energy. (2005c). Quick tips – that will save you money this winter and all year long. Halifax.
Nova Scotia Department of Energy. (2005d). Smart choices for cleaner energy – the green energy framework. Nova Scotia.
Office of Energy Efficiency. (2005). The EnerGuide for houses service.
Parmesan, C., & Yohe, G. (2003). A globally coherent fingerprint of climate change impacts across natural systems. Nature, 421, 37-42.
Statistics Canada. (2006). 2001 Community profiles – Halifax regional municipality. Ottawa: Statistics Canada.
VanCity. (2006). Bright ideas home financing.
- John Brennan, former Chief of the Federal Buildings Initiative, Natural Resources Canada;
- Donald Dodge, Program Administration Officer, Conserve Nova Scotia (formed by the Nova Scotia Department of Energy);
- Carl Duivenvoorden, Residential Sector Manager, Efficiency New Brunswick;
- Gary McKegney, EGH Advisor, Clean Nova Scotia;
- Kai Millyard, Special Projects Consultant to Green Communities Canada, Evaluation Manager;
- Paula Steele, Energy Efficiency Program Coordinator, City Green (Victoria);
- Peter Sundberg, Executive Director, City Green (Victoria);
- Bruce Young, Certified Energy Manager, Atlantic Coastal Action Program Cape Breton.
Energy Performance ContractingEnergy Performance Contracting
Published October 18, 2006
The City of Toronto supports the use of energy performance contracting (involving comprehensive energy and water retrofits and building renewal initiatives) with respect to both private and public buildings located within the City of Toronto through the Better Buildings Partnership (BBP) located within its Office of Energy Efficiency (OEE). BBP and OEE form an integral part of the city's efforts to contribute to global climate change. (Please refer to the Governance case study entitled “Mid-term Objectives: An Urban Experience, Toronto, Ontario”.)
Energy performance contracts (EPCs) provide a comprehensive turnkey service to retrofit facilities. In essence, they offer "one-stop shopping" for building owners and managers to upgrade facilities to make them more energy efficient. Typically, contracts include replacement/upgrading of HVAC systems, window replacements, upgraded lighting systems, etc. and are all inclusive in that they encompass capital investment and financing, engineering and design, project management, energy maintenance, specialized employee training, construction, commissioning of improvements, and so on. A major feature of EPCs is that building owners and managers use private-sector funding to finance the energy improvements in their facilities.
Costs for comprehensive building retrofitting, when combining short- and long-term investment opportunities, typically pay back over an eight- to ten-year period. To date, the BBP has produced up to $100 million in energy savings investments involving 155 buildings spread across Toronto. The investments have created approximately 3,000 jobs, mainly within the construction trades and the engineering sectors, and reduced building operating costs by $6 million, and CO2 emissions by approximately 72,000 tonnes per year, ongoing.
The majority of the money invested has come from the private sector through the firms contracted to undertake the energy/water retrofits. One estimate suggests that extending the program to all larger buildings within the Toronto metropolitan area would require an investment in the neighbourhood of $3 billion. Evidence suggests that the BBP presently has the capacity and momentum to increase energy savings investments by 400 to 800% with a concomitant 572,000 tonne reduction in CO2 constituting upwards of 30% of the City of Toronto’s CO2 target.
Major buildings included within the program include: the Toronto Community Housing Corporation, the Toronto Public Library, the Canadian Broadcasting Corporation’s Toronto headquarters, First Canadian Place Tower, Ryerson University, Toronto City Hall, and others.
Experience demonstrates that BBP sponsorship of energy performance contracting is indeed successful, but use tends towards larger buildings as well as favoring the institutional and large multi-residential sectors with significant exceptions such as the First Canadian Place Tower. To counteract this, BBP has put in place other programs focusing on smaller commercial and residential structures. While successful, their results are less than those of the energy performance contracting initiative.
Sustainable Development Characteristics
Municipal sponsorship of financial techniques such as energy performance contracting provides ready and large-scale financing for widespread implementation of energy efficiency and water conservation projects. Such projects, in turn, reduce ‘smog’ creating chemicals, thus making down town areas more livable.
In terms of sustainable development in its broadest sense, municipal support of energy performance contracting provides a necessary financing tool to achieving sustainable development through the implementation of energy and water saving equipment and processes. The tool, however, is based on investors finding positive financial returns using new, but well understood technologies.
Critical Success Factors
Critical success factors include:
an initial target set by the City of Toronto in 1990 to reduce the city’s net carbon dioxide levels by 20%;
continual support of Toronto’s City Council through sustained political support by elected municipal officials;
widespread and ongoing community involvement that has included city council, the citizens of Toronto, the utility companies, building owners, and suppliers (in this case essentially energy management companies that provide energy/water retrofit services to building owners). In some instances, Toronto’s Office of Energy Efficiency created the linkages; in others, the office coordinates these relationships; and,
the presence within Toronto of an energy management industry capable of delivering requisite energy management services such as engineering studies, planning, building reconstruction, product delivery (e.g. HVACs, windows, lighting fixtures), and energy monitoring services.
Community Contact Information
Energy Efficiency Office
City of Toronto
Phone: 1 416 392 1454
What Worked and What Didn’t Work?
The contracting and financial techniques tend to favor larger institutional and multi-residential buildings due to economies of scale and a preference for shorter investment horizons than those provided for with EPCs. Also, the use of EPCs often requires the carrying of additional debt for extended periods of time which many commercial and smaller businesses find difficult or unable to manage. As well, commercial enterprises can often earn a higher rate of return by investing in other endeavors such as enhanced marketing. The Office of Energy Efficiency provides other techniques to support smaller building s as well as the commercial and residential sectors. The impact of these alternative techniques has yet to be fully assessed.
Financial Costs and Funding Sources
The BBP has sponsored energy performance contracts valued at $100 million. The EPCs provide a comprehensive turnkey service for energy efficiency improvement within a facility or group of facilities. Elements of the contracts encompass capital investment, engineering and design, project management, energy maintenance, specialized employee training, construction, commissioning of improvements, and so on.
With an energy performance contract, external private-sector funding is usually used to finance improvements, although in-house funding can be used. Typically, the owner of a facility enters into a formal agreement with what is known as an Energy Service Company (ESCO) where the ESCO in turn borrows money from the private sector on its own behalf to finance the energy improvements. The ESCO repays the money from the savings accruing from the reduced energy consumption. Once the borrowed funds have been repaid and the ESCO has earned an agreed-upon profit, the energy-efficiency investments become the property of the facility owner, and all future energy savings from that date are credited to it. The ESCO also provides a guarantee that should energy savings not equal the initial borrowing plus accrued interest by the end of the contract, the ESCO must make up the difference. With the BBP, facility owners have both taken advantage of ESCO-supplied funding, and self-financing using proceeds from City of Toronto debentures.
The BBP also has a Loan Recourse Fund to finance energy-efficiency improvements in smaller commercial facilities and the residential sector. Historically, these sectors have tended not to take advantage of energy performance contracting either because they lack a capacity to attract funding or because expected savings are not large enough to warrant the engineering expertise normally associated with energy performance contracting. The Loan Recourse Fund provides financing through Enbridge Gas Distribution Inc. Loan repayments are made through charging an additional amount on monthly gas bills, which in essence treats these loans as a lien on property, hence transferable should ownership of the property change.
Analysis of this case study leads to six key observations:
BBP support of energy performance contracting is undoubtedly a success in that $100 million of energy savings investments have been made.
While the program has had unqualified success with respect to larger and institutional facilities, success in the commercial field and residential sectors has not been as great due to a lessor capacity to attract funding and/or to take on debt. This phenomenon, however, is not untypical.
The innovative Loan Recourse Fund, operated through Enbridge Gas Distribution Inc, needs careful monitoring to assess both its potential impact on energy/water savings within the commercial and residential sectors and its transferability to other communities.
BBP objectives, and those of the City of Toronto’s Office of Energy Efficiency derive more from a concern for climate change and energy/water savings than from arriving at a sustainable community. Nevertheless, success with respect to municipal support of energy performance contracting undoubtedly serves both sets of objectives.
EPCs are financially based. They must provide a positive rate of return and as such will tend towards well-tested and reliable “off-the-shelf” technologies.
Plans for EPCs are normally comprehensive, but can lend themselves to 'cherry picking’ as a means to enhance returns on investments and, therefore, limit the full degree of possible energy savings. The degree to which cherry picking occurs depends primarily on how early building owners/operators want to use energy savings to finance other operating expenditures.
Detailed Background Case Description
The Better Buildings Partnership
In 1990, the City of Toronto committed to reducing the city’s net carbon dioxide emissions by 20%, by 2005, relative to 1988 levels. To aide in this, the city, inter alia, put in place the Better Buildings Partnership (BBP) to assist building owners and managers to contribute towards the city’s objectives. In establishing the BBP and its objectives, the city consulted with a wide range of key stakeholders including: Enbridge Gas Distribution Inc, the Toronto Atmospheric Fund, Toronto Hydro and Ontario Hydro Energy ltd. Also consulted were financial institutions, building owners and managers, the environmental community, trade unions, community groups, equipment manufacturers, and the construction energy/water efficiency service delivery industries.
Key to the BBP is the sponsorship of energy performance contracting through the Large Office Building Program, which focuses mainly on larger institutional structures. The BBP also, however, provides programs aimed at assisting other types of facilities. These include:
the Residential Energy Awareness Program designed to increase the public's general knowledge of energy efficiency and conservation in the residential sector;
the Small/Medium Commercial Buildings Program, which provides planning and other tools to assist participants of this sector to realize energy and expanding cost savings;
the Multi-Residential Non-Profit Buildings Program to assist non-profit organizations providing housing assistance to Torontonians;
the In-House Energy Efficiency Program to retrofit municipally-owned buildings; and,
The BBP Loan Recourse Fund to assist the financing of energy retrofits in the smaller commercial and multi-residential sectors.
Energy Performance Contracting Defined
Energy performance contracting (EPC) is a key element of the BBP’s success to date. EPCs provide a comprehensive turnkey service to retrofit facilities. In essence, they offer "one-stop shopping" for building owners and managers to upgrade their facilities to improve energy efficiency. EPCs are typically all inclusive in that they encompass capital investment and financing, engineering and design, project management, energy maintenance, specialized employee training, construction, commissioning of improvements, and so on.
One of the more attractive features of EPC is that building owners and managers can use private-sector funding to finance energy improvements in their facilities. Under a typical energy performance contract, a department or agency enters into a formal agreement with what is known as an Energy Service Company (ESCO). The ESCO then borrows money on its own behalf from the private sector to finance the energy improvements, and repays it from the savings attained through reduced energy consumption. Once the loan has been paid off and the ESCO earns an agreed-upon profit, the energy efficiency investments become the property of the building owner, and all future energy savings accrue to the building owner. The ESCO undertakes this while at the same time guaranteeing that the savings will indeed occur. If not, the ESCO must make up the difference over the period of the contract as well as surrender the energy efficiency investments to the building owner.
Alternatively, building owners can directly finance energy retrofits. An ESCO would then provide a similar turn-key service less financing.
Typical Savings from Energy Retrofits
A Natural Resources Canada survey of ESCOs suggests that the benefits of energy retrofits can be substantial. Studies of projects using only commercially available energy efficient equipment and processes indicate:
energy costs can be reduced by as much as 25% and, in some cases, as much as 40% in existing general purpose buildings such as offices or classroom facilities, 40% in laboratory complexes, and 10% in central heating plants;
energy costs can be reduced by up to 40% by modifying standard practices in designing and constructing new buildings;
savings are ongoing, and contribute directly to sustainable development; and,
an overall improvement of indoor working environments through enhancements such as the installation of modern lighting systems, the removal of drafts, better lighting through the installation of modern windows, improved air circulation, etc.
The survey results also point out that substantial improvements can be achieved through renovation of facilities that have already been retrofitted for energy efficiencies in the past five to ten years. This occurs as commercially available energy efficiency technology tends to remain current for only seven to eight years, after which an additional 10% energy reduction can be achieved due to improved technology.
Description of a Typical Project
Municipal Facilities Including Toronto City Hall
Municipal facilities within Toronto were retrofitted taking advantage of an energy performance contract, the details of which follow:
Annual Energy Savings: 6.6 million ekWh
Project Cost: $4 million
Annual Cost Savings: $570,000
Payback Period: 7 years
Annual Carbon Dioxide (CO2) Reduction: 6,598 tonnes
7 city buildings
788,779 square feet
Municipal buildings/facilities, including City Hall, St. Lawrence Market, and Allen Gardens
Features: natural gas and electric heating, central air conditioning, district heating system for City Hall.
Lighting retrofit (City Hall - 1st and 2nd floor)
Asbestos remediation (City Hall - 1st and 2nd floor)
Water-efficient technologies and measures
Building automation system upgrades (City Hall)
Heating, ventilation and air conditioning (HVAC) system upgrades
High efficiency chiller replacement (City Hall)
Condensate heat recovery (City Hall)
Conversion from electric heating to natural gas.
Toronto City Hall (source: Wikipedia Commons)
Major BBP Projects Undertaken
The BBP has sponsored over 150 projects. Major ones include:
- The Toronto Community Housing Corporation at 25 Mutual Street
- The Toronto Public Library at 789 Young Street
- The Canadian Broadcasting Corporation at 250 Front Street
- The First Canada Place Tower
- Ryerson University at 350 Victoria Street
- St Ignatius of Loyola Catholic School
- St Patrick Catholic School
- John Ross Robertson Junior Public School
- The Ellesmere Yard at 1076 Ellkesmere Road
- Toronto City Hall
- Nisbet Lodge at 740 Pape Avenue
- The York Condominium Corporation at 301 Prudential Drive
- The Metropolitan United Church at 56 Queen Street East
Retrofits include items such as:
- indoor lighting replacement and upgrades,
- lamp and PCB ballast recycling,
- building automation systems upgrade,
- boiler upgrades,
- air sealing,
- heating, ventilation and air conditioning (HVAC) retrofits,
- washroom renovations,
- water-efficient technologies and measures.
Detailed information on these projects and others is available at http://www.toronto.ca/bbp/projects/.
Natural Resources Canada, Office of Energy Efficiency, Federal Buildings Program
What financial models can be put in place to assist the retrofitting of individual homes?
What lessons can be learned from the experience of the BBP’s Loan Recourse Fund, and are these lessons transferable to other communities?
Resources and References
Natural Resources Canada “Energy Performance Contracting Primer”
Natural Resources Canada “The Federal Buildings Initiative”
City of Toronto “Better Buildings Partnership: Program Information”
City of Toronto “Toronto Atmospheric Fund”
City of Toronto “Energy Efficiency Office”
Renewable Energy on Prince Edward IslandRenewable Energy on Prince Edward Island
Published November 29, 2006
Despite its population of just 138,000, Prince Edward Island (PEI) has undertaken an ambitious renewable energy strategy that has delivered innovative policies, public engagement strategies and economic benefits. PEI was the first province in Canada to adopt renewable energy tariffs as a policy mechanism to encourage wind development. The tariff is balanced with a renewable energy portfolio standard goal of 15 percent of electricity generation from renewable sources by 2010; but because this goal will be met by 2007, the Minister increased the target to 30 percent of all of Prince Edward Island’s energy requirements by 2016. In order to initiate wind energy development, the provincial government, through the PEI Energy Corporation, constructed the first two wind farms and in so doing set the bar in terms of public consultation and financial benefits for future private developments.
Another component of the strategy involves innovation such as the Hydrogen Village, a project that builds on the island-based Atlantic Wind Testing Station’s expertise in hybrid wind-diesel generator systems to use only clean fuels. PEI is also developing a biofuels strategy to offset fossil fuel consumption resulting from transportation.
Sustainable Development Characteristics
Prince Edward Island’s approach to renewable energy is multi-faceted with social, ecological, and economic dimensions. The province’s energy goals are as follows (PEI Energy Corporation, 2003):
Ensure security of supply
Improve price equity for citizens and businesses
Encourage diversity of supply
Achieve minimal environmental impact
Promote efficient energy usage
Support economic development
Prince Edward Island is highly dependent on fossil fuels; approximately 80 percent of PEI’s energy needs are met using fossil fuels (PEIDEE, 2004). As a result, PEI’s greenhouse gas emissions totaled 2090 kilotonnes of C02 in 2003 (Environment Canada, 2006).
Table 1: Source of PEI’s Energy, 2004
Imported and oil-fired electricity
Electricity from on-island wind power
Source: PEIDEE, 2004
While these emissions include transport-related emissions, Prince Edward Island’s electricity is also primarily dependent on fossil fuel. Since the installation of two submarine energy supply cables, Nova Scotia Power (NS Power) and New Brunswick Power (NB Power) have provided the majority of PEI’s electricity, 94 percent in 2004 (PEIDEE, 2004). Both NS Power and NB Power are highly dependent on fossil fuels for electricity generation, to the tune of 88 percent (Nova Scotia Power, 2005) and 85 percent (New Brunswick Natural Resources and Energy, 2001) respectively.
The only on-island power generation is an oil-fired power plant run by Maritime Electric, and the North Cape Wind Farm with eight wind turbines rated at 5.28 MW (PEI Energy Corporation, 2003).
As a result, PEI’s initiative to shift to wind energy has significant environmental benefits. For example, the eight wind turbines at North Cape reduced greenhouse gas emissions by 13,000 tonnes per year (Natural Resources Canada, 2001).
In announcing the renewable energy strategy, Premier Pat Binns highlighted the local economic development aspects of renewable energy, "Each year, some $440 million leaves Prince Edward Island, as fossil fuels are imported to heat and power our homes and fuel our vehicles. This target is about keeping more of those dollars in PEI to strengthen our economy. And it is about creating new opportunities for Island farmers and a healthier environment today and for future generations" (Renewable Energy Access, 2006).
The wind energy project has attracted significant investment. Ventus Energy has two wind farm projects underway in the province with a total rated capacity of 108 MW. Both projects are funded entirely through private financing from venture capital firms such as Wellington Financial LP (Ventus, 2006). The total investment for the two wind farms is $230 million (City of Summerside, 2006).
PEI Energy Corporation also took measures to maximize the economic benefit to islanders, setting the standard for future private developments. Two and a half percent of gross revenue from the turbines is distributed to local people in a revenue sharing agreement- the person whose land the turbine is on receives 70 percent, those who are directly impacted receive 20 percent and those who are impacted but are further away receive 10 percent. The corporation ensured that all the turbines were placed on private property even when publicly owned property was available and had a comparable wind resource (Interview with PEI Energy Corporation official).
The province decided on an alternative ownership model in the development of a new 30 MW wind farm near Kings County, with a "government and co-op" approach. A PEI Energy subsidiary will own the wind farm, and a "wind-energy cooperative" will become a shareholder in the PEI Energy subsidiary. Prince Edward Island residents can then become members of the co-op by investing in it and the government intends to make investments in the wind co-op project qualify as a "Registered Retirement Savings Plan" under Canadian law (Global Power Report, 2005).
On December 1st, 2006, the PEI Government will begin marketing a new $56 million bond issue called the Eastern Kings Wind Farm Bond. Listed as five-year bonds with a five percent return, they will be available only to PEI residents up to a maximum purchase of $10,000 per year. The bond issue ensures that islanders have the opportunity to benefit financially from the wind turbines (Interview with PEI Energy Corporation official). The money raised will be used either to pay down the debt on the turbines or to finance new developments.
A two percent royalty paid from one two-megawatt turbine in one of the windiest locations on PEI could generate a long-term annual royalty of $10,000. Given that the average 100 acre farm could handle two to three of these windturbines with minimal impact to existing land use, the potential annual royalty payments add up to $30,000 (Douglas, 2005).
Tourism is an ancillary benefit. The Wind Energy Institute has become a major tourist destination with 60,000 people visiting each year (CanWEA, 2006).
Critical Success Factors
History of Innovation
Prince Edward Island has a long history of innovative environmental initiatives. The Institute of Man and Resources was born in the midst of the 1970s energy crisis. In 1975 with the support of then Premier Alex Campbell, the institute’s program included ‘analysis, invention, adaptation and application of appropriate energy, food and crop production and living and shelter systems,' however, it quickly narrowed down to a focus on energy. In 1978, the institute published a paper titled the Prince Edward Island Wind Energy Program, which detailed a program involving wind speed testing, the integration of wind energy conversion systems, applications for farms and testing of machines at the Atlantic Wind test site (Lodge, 1978). Another famous venture, the Prince Edward Island Ark, was conceived in cooperation with the New England-based New Alchemy Institute. The Ark was an experimental building that was heated with passive solar and tested indoor agriculture. An unfavourable political climate in the early 1980s resulted in the conclusion of the Institute of Man and Resources, but its legacy continued in the Atlantic Wind Testing Station (Varty, 2004).
The Atlantic Wind Testing Station (AWTS) was formed in 1981 by the institute and was designated the Government of Canada’s wind energy research station. In 1983, the world’s largest vertical axis wind turbine, a 500 kW machine, was installed for testing purposes. In 1984, Natural Resources Canada assumed responsibility for the site and AWTS became involved in international projects around integrated wind and diesel systems. In 1994, the University of New Brunswick established its Renewable Energy Research facility at the site, and in 2001 AWTS was involved in the development of Atlantic Canada’s first commercial wind plant, the North Cape Wind Plant. In 2003, Vestas selected North Cape for testing its V90, with a 90 MW rating, the largest wind turbine in North America, and in 2005, the AWTS was announced as the site of a wind-hydrogen village. In 2006, the name was changed to the Wind Energy Institute and a research building was constructed.
AWTS’s work focuses on four key areas:
Technical innovation: AWTS helped develop a vertical axis wind turbine, was instrumental in the development and deployment of wind-diesel systems and helped improve smaller wind turbines
Testing: AWTS has tested a wide range of turbines from 0.05 kW to 500 kW, both for performance and for long-term operation.
Developing collaborative relationships: AWTS works with industry, researchers and government agencies.
Information transfer: AWTS has become the point of reference for inquiries regarding wind across Canada, as well as hosting nearly 100,000 visitors each year.
The 20-year history of experimentation with wind energy, both at the AWTS and by the population in general, resulted in a pool of technical skills and a public familiarity with the technology that has provided a solid foundation for a major expansion of wind generation capacity.
The general population has supported and even driven the development of wind energy on PEI, support that is derived from an awareness of environmental issues. This awareness has manifested itself in other innovative policies such as the Conservation Strategy for Prince Edward Island. In 1987, the provincial government initiated a public consultation process that brought together government officials, industry, business leaders, local community groups, leaders of indigenous groups, and churches, to demonstrate that economic development can proceed in harmony with environmental goals. The plan spanned 20 years and sought to demonstrate that conservation and economic development need not conflict, but can proceed in harmony (Co-ordinating Committee for Conservation, 1987).
In 2004, Premier Binns had sparked a storm of controversy with his suggestion that the Island become free of genetically modified organisms (GMOs) (Government of Prince Edward Island, 2004). While the idea has yet to become law, PEI residents debated the idea at length, and the question ultimately arrived at the floor of the provincial legislature.
Unlike other provincial jurisdictions in Canada, PEI doesn’t have extensive natural sources of energy such as hydro or petroleum; the province has historically been dependent on imported energy. The insecurity of this system was highlighted when one of the two submarine electricity cables was severed in 1997.
The island does, however, have extensive indigenous resources of wind energy (Natural Resources Canada, 2001).
Because PEI is a small province with a population of 138,000, it is difficult to mobilize the financial resources required to undertake major capital-intensive projects such as wind energy from the private sector. The provincial government has, therefore, played a key role in initiating the development of wind energy, firstly through creating a policy environment and secondly by initiating wind energy development by constructing two wind farms through the PEI Energy Corporation. These initial wind farms also set the bar in terms of public expectations for future developments, and ensured that wind energy has widespread support amongst both islanders and politicians.
In 2001, when the PEI Energy Corporation approached the federal government to increase its support for the Atlantic Wind Testing Station, they instead responded that they would support the development of a wind farm.
Thus, the ability of PEI Energy Corporation to pursue the initial wind farm at North Cape was, in part, due to the Government of Canada's commitment to purchase electricity from emerging renewable sources. The federal and provincial governments committed funding over a ten-year period toward the purchase of electricity generated by the wind turbines (Ibid).
Financial Costs and Funding Sources
Wind energy on Prince Edward Island is being funded by a mix of private sector, community and public investment.
The two wind farms owned by the PEI Energy Corporation are financed using a mix of federal and provincial government money - the federal government and the PEI Government committed $4.5 million and $1.1 million respectively, over a 10-year period toward the purchase of electricity generated by the wind turbines (Natural Resources Canada, 2001). This will be supplemented through private investment collected through the issuance of bonds available to PEI residents.
Ventus Energy has two wind farm projects underway with a rated capacity of 108 MW, funded entirely through private financing from venture capital firms such as Wellington Financial LP (Ventus, 2006). The total cost is estimated at $230 million (City of Summerside, 2006). Summerside Electric, a subsidiary of the City of Summerside, committed to purchase nine MW a year over 20 years from Ventus Energy.
Maritime Electric, PEI’s utility, signed a twenty year agreement with Ventus to purchase the power from its nine MW Norway Wind Farm at the rate of $0.0775 per KWh. At $18 million total cost, the wind farm will generate 31,000 kWh of green power for approximately 5000 homes and offset 30,000 tonnes of emissions each year (Ventus Energy, 2006). Ventus’ West Cape Wind Farm, rated at 99 MW, is being built in two stages, with a completion date in 2007-2008. The power generated by this farm will be marketed off-island.
The PEI Government took a highly proactive and cautionary approach to wind energy development. Careful research ensured that the province learnt from other jurisdictions with extensive experience in wind development, in particular Europe. As a result, PEI’s approach includes a range of features innovative in the North American landscape including:
No development zones
The combination of the portfolio standard with the renewable energy tariff
Extensive public consultations
Issue of public bonds
Payment scheme for impacted residents
Ownership of carbon offsets
Because PEI Energy Corporation was able to construct the first two wind farms on the Island, it was able to set a high bar in terms of public expectations for revenue generation and public consultation. Future private wind energy developments will have to meet this standard, thus ensuring that wind energy on Prince Edward Island benefits local residents.
In the case of Prince Edward Island, the utility was a major roadblock (interview with PEI Energy Corporation official) and continues to present challenges. For example, the utility charges a penalty against wind developers for incorrectly forecasting wind output, called an energy imbalance charge. Each day the wind company predicts how much power will be generated the next day; if the wind is not as strong as anticipated, in the case of Prince Edward Island, the utility has to phone NB Power to request additional power. Similarly, if there is too much power, the utility has to request a reduction. The intermittency of wind energy means that a power plant somewhere must be on standby to compensate for the variation, and from the perspective of a utility, this is a stranded asset which could otherwise be generating power for sale.
These challenges are being overcome through inter-utility cooperation, both between Atlantic province utilities, and between New England States and Atlantic provinces. The Minister of Energy on Prince Edward Island chairs an inter-provincial council of Atlantic energy producers and has hosted a meeting on PEI for New England producers.
The PEI Government's commitment to ensure that the economic benefits of wind energy accrue directly to PEI residents is innovative. The three key aspects of this strategy include issuing public ‘wind farm’ bonds, committing 2.5 percent of total revenue to residents impacted by the development, and retaining ownership of the carbon offsets that result from wind developments.
While wind farm developments typically attract backlash focused on the issues of noise, bird kill and visual impact, PEI has not yet encountered resistance due to the following factors:
High level of public understanding of wind power, due to PEI’s history of experimenting with wind
Careful public consultation around new developments
Opportunity for PEI residents to receive economic benefits
Use of designated areas restrictions to ensure wind developments occur in areas with low population density and high wind regime
Maximizing the benefit of each wind turbine by selecting a few larger rather then many smaller wind turbines
Detailed Background Case Description
Historically, PEI has been dependent on importing electricity. Increasing petroleum prices, recognition that PEI has significant wind resources, and the need to reduce greenhouse gas emissions all contributed to the island's focus on wind energy.
Efforts to promote renewable energy on PEI consist of a mix of policy instruments, including the province's Renewable Energy Act, innovative pilot projects such as the Hydrogen Village, and an established research program called the Wind Energy Institute.
PEI's Renewable Energy Act, which was passed during the fall 2004 session of the Legislative Assembly and came into effect December 31, 2005, requires utilities to acquire at least 15 percent of electrical energy from renewable sources by 2010. Initially, the policy included a section that committed the province to a target of 100 percent of electricity from renewable sources by 2015, but in recognition of the technological challenge stemming from intermittency of wind power, this section was withdrawn. In the near future, the PEI Government will announce a new target of 30 percent of PEI’s total energy needs – including transport and heating - be supplied by renewable energy by 2016. The increased scope is intended to stimulate biofuels such as ethanol (Interview with PEI Energy Corporate official, 2006).
Other elements of the policy include:
Minimum Purchase Price Regulations establish the price utilities must pay for power produced by large-scale renewable energy generators (those capable of producing more than 100 kilowatts of energy). The PEI Government has set this rate at 7.75 cents per kilowatt-hour, with 5.75 cents of that a fixed rate and 2.0 cents a variable rate that may be adjusted annually to reflect changes in operating costs. The variable rate will be tied to the Consumer Price Index.
The Designated Areas Regulations are designed to ensure that large-scale (more than 100 kilowatts) wind farm projects take place in areas where development is economically viable. The criterion for identifying the zones of inclusion – areas where development may occur – is an average wind speed of 7.5 metres per second. The regulations do not mean that any development may proceed; proposed projects must receive all necessary approvals and are subject to any existing development restrictions and the Environmental Impact Assessment process. They must also comply with requirements under the Planning Act Subdivision and Development Regulations, for setbacks from buildings and other structures.
The Net-Metering System Regulations make it more economically feasible for Island homeowners, small businesses, or farmers who have an interest in generating their own electricity, to install small-scale generating systems – those that produce 100 kilowatts of energy or less. Under the regulations, any excess energy that small-scale generators supply to the electrical grid will be credited at the same price paid for power purchased from the utility.
The PEI Government maintains ownership of the environmental attributes of any wind energy development. Any carbon credits or ‘offsets’ that are generated are treated in the same manner as oil and gas royalties, on the basis that the wind is owned by the people of Prince Edward Island, and therefore any greenhouse gas mitigation benefits that result from its use also belong to the people of Prince Edward Island.
Renewable energy projects and appliances receive a provincial sales tax exemption.
At the time it was introduced, PEI’s Renewable Energy Act was considered the most progressive policy measure in North America (Gipe, 2006-1). Renewable energy technologies need financial incentives because they have three limitations: higher costs due to commercial immaturity; capital intensiveness relative to long-term costs; and, potentially intermittent production.
The PEI Government used a combination of policy mechanisms to stimulate investment in wind energy, including the first implementation of a renewable energy tariff in Canada. While the renewable energy portfolio has been the policy of choice in North America, renewable energy tariffs have been used extensively in Europe. The portfolio approach addresses the problem in a linear fashion: X amount of generating capacity is required, therefore, issue a Request for Proposals (RFP) for X, and build X. A Renewable Tariff mechanism is less prescriptive: problem X requires so much generating capacity, therefore, what is the price that will stimulate the rate of development desired (Gipe, 2006)?
PEI elected to use a portfolio standard, 15 percent by 2010, in concert with a renewable energy tariff; this policy in combination with other factors has meant that the 15 percent target will be met three years early. While the portfolio standard ensures the utility has a standard, the renewable energy tariff ensures that the wind farms will be economically viable and prevents the utility from ‘squeezing’ the developer post construction (Interview with PEI Energy Corporation official).
Renewable Energy Tariffs
One of the most innovative aspects of PEI’s strategy is the renewable energy tariff (RET). RETs are determined from the cost of developing the resource plus a reasonable or “prudent” profit. While this approach was the norm in North America from the 1920s until the 1990s, neo-liberal induced deregulation attempted to sweep aside the cost-based determination of tariffs, favouring an unregulated market instead (Gipe, 2006).
Advantages of RETs include:
Prices sufficient to drive development
Lengths sufficient for profitability
Prices differentiated by technology
Prices differentiated by resource
Because PEI’s RET is used in concert with other policy measures, it is considered non-standard. When it was introduced, the only other jurisdictions in North America that employed this measure were Minnesota, Washington State and recently, Ontario. There are serious discussions regarding renewable energy tariffs in British Columbia, Manitoba and Nova Scotia.
On a number of fronts, Ontario’s new Standard Offer Program, a standard RET, is more innovative then PEI’s mechanism (Gipe, 2006-1). While only wind energy is viable at PEI’s tariff rate, Ontario’s tariffs vary according to the technology. Ontario’s Standard Offer Program is also limited in size to 10 MW, thus ensuring that one or two companies don’t come to dominate the market. PEI’s tariffs are available for any project.
Gipe (2006-2) states that RETs generate more capacity more quickly and more equitably. They are effective because they grant high financial support, while minimizing the costs of transaction for the developers in relation with their obliged purchases, and by limiting quantity risk and price risks for them. Guaranteed over the long term with sufficiently high prices to generate a profit, banks easily agree to lend (Sawin, 2004). The transaction costs between purchaser and developer of the energy in this arrangement are also minimal, since the rate is set at a constant amount for an extended period with possible small adjustments. It is also possible to avoid a contract between developers and purchasers.
Critiques of this measure fall into three categories (ibid): there is no market incentive to reduce development costs; high tariffs lead to an installed renewable energy capacity that is sub-optimal; and, too much rent goes to the developers. The first argument is countered by the fact that producers can increase their profit margin by reducing their costs, a powerful incentive. The issue of too much rent going to developers induces a higher learning effect, as this rent is re-invested in technical innovation. In terms of the second argument, that the capacity may be sub-optimal, this depends on the level of the pricing and the willingness of investors to invest at that level. This contrasts directly with the mandated targets system in which governments set a minimum share of capacity and let the market determine the price. In the tariff system, the share of capacity will increase with a constant price. In the mandated target system, the share will stay the same while the price per unit of energy decreases, which may be beneficial to the public, if these savings are transferred to the public.
Table 1: Renewable Energy Tariff and Quota System
Renewable Energy Tariff
Is it a market model?
The price is political, the amount is decided on a market
The amount is political, partly set by market, partly political
Does it further competition between equipment suppliers?
The equipment producers as a group can expand sales and profit by lowering production costs
Equipment producers face a 6-8 year politically set production quota. They can expand profits by lowering costs and increasing sales prices.
Can it differentiate the price between good and bad “politically desired” wind sites?
Yes, as happens in the PEI model
No, same price is paid everywhere.
Can it price differentiate between the first years and last years of the production of a given renewable energy (RE) plant?
Yes, as happens in the German model
No, same price is paid everywhere.
Can it lower the price in conjunction with RE technology improvements?
Yes, in the German model 2002 wind turbines are 1.5 percent cheaper than 2001 turbines.
No, the quota has to be set for 6-8 years and new improved wind turbines are getting the same price as older inefficient ones
Does it support neighbours and local investors?
Yes, the foreseeable prices make it possible for local communities to borrow from banks.
No, the fluctuating and politically manipulated prices make it difficult to secure loans.
Does it put a cost pressure on equipment producers?
Yes, almost the same cost pressure is put on high and low wind performance sites.
No, in general the coastal sites generate high profits and the inland sites are more marginal.
Source: Hvelplund, 2001
RETs have also incubated a whole new manufacturing sector by allowing a steady flow of manufacturing orders from many diverse project developers. In Germany, 45,000 people are employed in the wind industry alone, and this is forecasted to grow to 110,000 by 2010. This success contrasts sharply with the inherent boom and bust cycle experienced under the periodic release of project tenders (RFPs).
There is little or no cost anticipated for the provincial treasury. The prices for the power delivered using RETs are incorporated into overall system pricing and are borne by the ratepayer.
Resources and References
Canadian Wind Energy Association (2006). The Sights and Sounds of Wind.
City of Summerside (2006). Summerside Electric to Purchase Renewable Energy.
Co-ordinaring Committee for Conservation (1987). A Conservation Strategy for Prince Edward Island. Charlottetown, Prince Edward Island.
Douglas, John (2005). Wind Energy: PEI’s next cash crop. Prince Edward Island Potato News. January 2005, Volume 6, Issue 1.
Environment Canada (2006). Canada’s National Inventory Report.
Finon, Dominique (2006). The Social Efficiency of Instruments for the Promotion of Renewable Energies in the Liberalised Power Industry. Centre International de Recherche sur l’Environnement et le D´eveloppement (CIRED) EHESS & CNRS, Paris, France. Annals of Public and Cooperative Economics 77:3 2006.
Gipe, Paul and Chabot, B. (2006)-1. North America’s First Electricity Feed Law: Standard Offer Contracts in Ontario, Canada. DEWI Magazin Nr. 29, August 2006.
Gipe, Paul (2006)-2 Advanced Renewable Tariffs: Trends and Key Elements. Powerpoint presentation at the Standard Offer Contract Forum. Ontario Sustainable Energy Association.
Global Power Report (2005) Prince Edward Is. takes a co-op approach to build 30-MW wind farm in Kings County. New York: Jul 14, 2005. p. 13.
Government of Prince Edward Island (2004) Farm Net - Legislature to Debate GMOs. Government of Prince Edward Island.
Government of Prince Edward Island (2006). Renewable Energy Act. Chapter R-12.1.
Hvelplund, Frede (2001). Political Prices or Political Quantities. New Energy.
Industry Canada (2005). Government of Canada Supports Development of Alternative Energy Project. Government of Canada.
Interview with PEI Energy Corporation Official (November, 2006). By telephone.
Lodge, M. (1978). The Prince Edward Island Wind Energy Program. In Renewable alternatives; Proceedings of the Fourth Annual Conference, London, Ontario, Canada, August 20-24, 1978. Volume 1. (A79-31401 12-44) Winnipeg, Solar Energy Society of Canada, Inc., 1978. p. 13.
MacQuarrie, Wayne (2003). Presentation titled: Renewable Energy- A Prince Edward Island Perspective. At the Green Power in Canada Workshop Series, October 1, 2003, Halifax, Nova Scotia.
Natural Resources Canada (2001). The Winds of Prince Edward Island to Provide Greener Power.
New Brunswick Natural Resources and Energy (2001). White Paper: New Brunswick Energy Policy.
Nova Scotia Power (2005). Renewable Energy.
Ontario Sustainable Energy Association (2004) Advanced Renewable Tariffs for Community Power Development in Ontario.
Doncaster, Deborah; Gipe, Paul and Macleod, David (2005). Powering Ontario Communities: Proposed Policy for Projects up to 10 MW.
PEI Energy Corporation (2003). Prince Edward Island Renewable Energy Strategy: Public Discussion Document.
PEI Department of Environment and Energy (2004). PEI Energy Framework and Renewable Energy Strategy.
Renewable Energy Access (2006). PEI Canada Fueling Its Economy with Renewable Energy Target.
Sawin, Janet (2004). National Policy Instruments: Policy Lessons for the Advancement & Diffusion of Renewable Energy Technologies Around the World. Presented at the International Conference for Renewable Energies, Bonn. Worldwatch Institute.
Varty, John (2004). Review of The Institute of Man and Resources: An Environmental Fable. ALAN MACEACHERN. Charlottetown: Island Studies Press, 2003. Pp. 142, The Canadian Historical Review. University of Toronto.
Ventus (2006). Press Release titled: Wellington Financial leads $29 million financing for Ventus Energy Inc.
Ventus (2006). Press Release titled: Ventus Energy Inc. Announces Power Purchase Agreement for PEI Wind Farm.
Wind Power GenerationWind Power Generation
Published November 8, 2006
As a source of electricity, wind power has many advantages from a sustainability perspective. Aside from equipment manufacture, it carries with it little ecological impact, produces no green house gases, physically takes little room for implementation (one reference quotes 2 per cent of a farmer’s field), and substitutes for a number of environmentally problematic technologies such as the burning of coal or gas, the creation of new hydro reservoirs and/or the use of nuclear energy. Consequently, many see wind power as a potential, if not an integral part of a sustainable solution for Canadian communities.
Several initiatives have proposed that directly link wind power to the needs of nearby communities, such as the Wolfe Island Wind Project at Kingston, Ontario.
A number of planning and economic issues offset the advantages of wind power. On a kilowatt hour cost basis with today’s technologies, wind power appears twice as expensive than other power sources, and to take advantage of economies of scale typically requires a size of investment that often is beyond the means of smaller communities. In addition, wind supply can be intermittent, and there is anecdotal evidence that the maintenance costs of wind turbines may be considerably higher than initially anticipated.
The Wolfe Island proposal evolved into the Ontario Power Authority awarding a contract to the Canadian Hydro Developers Inc on November 21, 2005 for 86 wind turbines to be located on Wolfe Island just east of Kingston, Ontario. This investment, valued at approximately $410 million, is sufficient to power 75,000 homes, a population base more or less equivalent to the larger Kingston area. The investment can be seen as a major step in creating a sustainable community in Kingston and the surrounding islands; however, the investment also requires the “deep pockets” of the Ontario Power Authority to proceed and the ready availability of a grid-based alternative to provide continuity when the wind stops blowing. An environmental assessment is now underway to assess the proposal.
Sustainable Development Characteristics
Wind power undoubtedly supports environmental sustainability, and hence as a tool can play an integral part in the development of a sustainable community. As noted above, it produces no greenhouse gases, physically takes little room for implementation, and substitutes for a number of environmentally problematic technologies such as the burning of coal or gas, the creation of new hydro reservoirs and/or the use of nuclear energy. Intermittency is a problem. Nevertheless, within a larger grid-system, when not intermittent wind power does directly substitute for less sustainable technologies such as oil/gas generation.
Critical Success Factors
Critical success factors include:
a significant upfront investment to take advantage of economies of scale, especially with respect to linking into electricity grids so as to have an alternative in intermittent conditions;
a “deep pocket” to finance the additional costs of wind power investments at least until per unit costs begin to approach those of other power sources;
proximity to a wind-strewn area. This of course presumes that the investment will be undertaken as an integral part of a community’s sustainability plan. It can be maintained that wind power should more properly be considered a provincial-wide matter; and,
linkage to a long-term plan. Wind power requires significant investment with returns spread over 20 to 25 years and planning horizon should reflect this.
Financial Costs and Funding Sources
Natural Resources Canada notes that modern wind turbine generators cost between $1,500 and $2,000 per kilowatt for multi-turbine wind farms. Smaller individual units cost up to $3,000 per kilowatt. The Wolfe Island Wind Project (referred to above) will put down 86, 2.3 megawatt turbines with an estimated total cost of $410 million or very slightly over $2,000 per kilowatt. Financing for the project will be through Canadian Hydro Developers Inc on the basis of a long-term contract with the Ontario Power Authority.
The Clean Air Renewable Energy Coalition estimates that wind power costs range from 8 cents to 10.2 cents per kilowatt hour, exceeding the 2002 average actual wholesale prices of electricity in Canada by 1.2 to 7.8 cents per kilowatt hour depending on province. If costs for administration, distribution, marketing, etc. are included, the additional costs increase to 3.2 to 11.8 cents, implying that provincial energy agencies are paying a considerable premium for wind power. To partially offset these differences, the Government of Canada's Wind Power Production Incentive offers a financial subsidy of one cent per kilowatt hour to suppliers of electricity generated through the use of wind power.
In remote areas, the cost of generating electricity using diesel generators can range from $0.25 to $1.00 per kilowatt hour as opposed to $0 .10 to $0.12 for wind power, making wind power clearly cost effective in these sorts of situations where and when good wind is available.
Analysis of this case study presents leads to four key observations:
As a technique, wind power provides a renewable and sustainable energy source, but is problematic as to cost with today’s technologies.
Wind power is only one of several renewable technologies leading to electricity generation and/or effecti ve energy management.
For wind power, it is not clear whether the appropriate planning/implementation authority should be at the community or at the provincial level due to the intermittent nature of wind power.
Detailed Background Case Description
The Environmental Impact of Wind Power
As a source of electricity, wind power provides many advantages from a sustainability perspective. Aside from equipment manufacture, it has little ecological impact, produces no green house gases, physically takes little room for implementation (one reference quotes 2 per cent of a farmer’s field), and substitutes for a number of environmentally problematic technologies such as the burning of coal or gas, the creation of new hydro reservoirs, and/or the use of nuclear energy.
The following, largely taken from the Canadian Electricity Association’s publication entitled Power Generation in Canada, compares the environmental impacts of electricity generation options:
Impact of Electricity Generation Options
|Technology||Air Pollutants||GHG(1)||Water Use (2)||Extraction||Waste||Other|
|Demand side Management||None||None||None||No||Disposal of replaced equipment||Reduce demand results in reduced emissions|
|Reservoir hydro||None||Low||Flow pattern changed||No||No||Fish migration, flooding|
|Run-of-river hydro||None||None||Minimal||No||No||Can interfere with recreational activity|
|Nuclear||None||None||Thermal discharge||Yes||Radioactive||High water cooling required|
|Natural gas||Low||Medium||Thermal discharge||Yes||No||Moderate water cooling required|
|Oil-fired generation||High||High||Thermal discharge||Yes||Yes (3)||Moderate water cooling required|
|Conventional coal||High||High||Thermal discharge||Yes||Yes (3)||Moderate to high water cooling required|
|“Clean coal” with CO2 capture||Low||Medium||Thermal discharge||Yes||Yes3||Increased coal consumption per MWh|
|Energy recovery generation||None||None||Low||No||No|
|Wind power||None||None||None||No||No||Bird/bat kills|
|Solar PV||None||None||Low||For manufacturer, only||Yes||High energy consumption during manufacture|
|Tidal power||None||None||Non-consumptive||No||No||Other impacts unknown|
|Wave power||None||None||Non-consumptive||No||No||Other impacts unknown|
Greenhouse gas emissions from energy conversion process only, not as a result of equipment manufacture or construction.
Difficult to compare for different technologies.
From ash management and/or flue gas treatment.
Comparative Technological Features
Wind power is considered an intermittent technology for generatng electricity in that its production of power can be variable. Nevertheless, the output of wind power can be integrated into long-term power planning if the technology can be twinned with more controllable technologies such as reservoir-based hydro or oil/gas plants as outputs can be varied to compensate for wind power down-times as well as service peak load situations. To put this into context, electricity usage in Ontario on July 16, 2006 typically varied from just over 14,000 megawatts at 6:00 am EDT to almost 23,000 megawatts at 6:00 pm.
The Wolfe Island project is an example of a wind-power based renewable energy project. The Ontario Power Authority cites other examples within the Province of Ontario including:
|Wind Power Project||Capacity||Status|
|Melancthon Grey Wind Project Phase 1, Canadian Hydro Developers, Inc. (Shelburne)||67.5 megawatts||Complete|
|Melancthon Grey Wind Project Phase 2, Canadian Hydro Developers, Inc. (Shelburne)||132 megawatts||In progress|
|Erie Shores Wind Farm, Erie Shores Wind Farm L.P. (Port Burwell)||99 megawatts||Operating|
|Prince I Wind Farm, Superior Wind Energy Inc. (Prince Township)||99 megawatts||In progress|
|Prince II Wind Power Project, Brascan Power (Prince Township)||90 megawatts||In progress|
|Blue Highlands Wind Farm, Superior Wind Energy Inc. (Blue Mountains)||49.5 megawatts||In progress|
|Kingsbridge I Wind Power Project EPCOR (Goderich)||39.6 megawatts||Operating|
|Kingbridge II Wind Power Project, EPCOR (Goderich)||158.7 megawatts||In progress|
|Kruger Energy Port Alma Ltd. Partnership, (Port Alma)||101.2 megawatts||In progress|
|Enbridge's Leader Wind Project A Leader Wind Corp., (Kincardine)||100.65 megawatts||In progress|
|Enbridge's Leader Wind Project B Leader Wind Corp., (Kincardine)||99 megawatts||In progress|
|Ripley Wind Power Project, Suncor Energy Products Inc. and EHN Windpower Canada Inc. Accione Energia, (Ripley)||76 megawatts||In progress|
The following is derived mainly from Power Generation in Canada and compares a few major technological features of various wind power technologies, particularly with respect to responding to changes in demand and to seasonal variability.
|Technology||Ability to Deliver Base and Peak Loads||Amenability to Seasonal Variation|
|Demand-side management||Will generally reduce peak load demand and/or shift load. Some measures reduce year-round energy use (or base load).||Little variation. Some measures may save more energy in the summer months while others in the winter months.|
|Reservoir hydro||Can change output rapidly thus serves both peak and base loads.||Little as storage generally buffers variability.|
|Run-of-river hydro||Case specific. Plants are subject to changes in seasonal flows which can be significant for smaller facilities.||Generally low or little production in winter months due to freezing.|
|Nuclear||Limited ability to change output (or base load).||No variability|
|Natural gas||Can rapidly change output, especially to serve needle peaks; generally too expensive to serve base loads.||No variability|
|Oil-fired generation||Can rapidly change output, therefore ideal to serve peak loads.||Output can be limited during SMOG days.|
|Conventional coal||Mainly used for base load, but can be used to serve peak loads.||Output can be limited during SMOG days.|
|“Clean coal” with CO2 capture||Mainly used for base load, but can be used to serve peak loads.|
|Biomass||Biomass systems can change output somewhat, but are generally not as flexible as oil/gas systems.||None, as long as there is a sufficient storage of biomass.|
|Energy recovery generation||Usually used only for base load as applications normally run at a high capacity level providing little opportunity to increase output to serve peak loads.||Depends on fluctuations of heat source.|
|Geothermal power||High capital cost requires continuous high output leaving little opportunity to increase output to serve peak loads.||No variability|
|Wind power||Reduces output of peaking plants when running, but requires backup power for periods of low production.||Average seasonal capacity varies between 20 percent in the summer to 40 percent in the winter.|
|Solar PV||Has a daylight hour base, thus mainly supplies peak consumption.||There is less light in the winter, which reduces output.|
|Tidal power||Output should be regular and predicted very accurately.||None|
|Wave power||Intermittent (see wind power above)||See comments on wind power.|
Comparative Costs of Electricity Generation
The Clean Air Renewable Energy Coalition estimated in 2002 that wind power costs range from 8 cents to 10.2 cents per kilowatt hour, exceeding the 2002 average actual wholesale prices of electricity in Canada by a cost premium of 1.2 to 7.8 cents per kilowatt hour depending on province. If costs for administration, distribution, marketing, etc. are included as well, the cost premium increases to 3.2 to 11.8 cents. For comparison, the following table presents comparative estimates of actual wholesale prices of electricity disaggregated by province.
|Province||Estimated Average Cost per KWh for Base Power|
|Prince Edward Island||6.9|
The Canadian Electricity Association published a similar assessment in 2004, whereby it approximated wholesale costs for generating electricity in Canada using various technologies, and compared these to the current costs of producing electricity, which range from 4.7 cents per kilowatt hour in some provinces to more than 7 cents in others. It must be noted that these estimates are at best approximations and will vary from project to project. The following table presents the comparisons.
Approximate Wholesale Costs of Producing Electricity in New Projects*
Approximate Cost Range (cents per kilowatt hour)
|Current Average Production Costs||4.7 to7|
|New reservoirs||5.5 to 12|
|Capacity increase in reservoir hydro||2.5 to 4.5|
|Run-of-river hydro||3.0 to no limit|
|Nuclear||5.5 to 7.0|
|Natural gas||6.0 to 7.5|
|Oil-fired generation||7.0 to 13|
|Conventional coal||5 to 6.5|
|“Clean coal” with CO2 capture||5 to 6.5|
|Biomass||5.5 to 18|
|Energy recovery generation||7.0 to 9.0|
|Geothermal power||6.5 to 9.5|
|Wind power||6.0 to 14|
|Solar PV||8.0 to 25 and more|
|Tidal power||8.0 to 12|
|Wave power||8.0 to 11.5|
The Government of Canada's Wind Power Production Incentive offers a financial subsidy of one cent per kilowatt hour to suppliers of electricity generated through the use of wind power.
Will new technologies make wind power an economically viable alternative?
Are provincial and/or federal subsidies necessary for the economical production of wind power?
Should communities with available wind-strewn areas considerable power sharing agreements with provincial power authorities as part of long-term sustainability plans?
Resources and References
Major references for this case study include:
Canadian Electricity Association, Power Generation in Canada: A Guide.
Natural Resources Canada, Wind Energy Production Incentive.
Natural Resources Canada, Technologies and Applications.
Canadian Hydro Developers Wolfe Island Wind Project.
City of Kingston, Local Wind Power.
Ontario Power Authority, Generation Development.
Queen’s Journal, Winds of change blowing on Wolfe Island.
Clean Air Renewable Energy Coalition, Enhancing Sustainable Economic Development in Canada with Renewable Energy.