Issue: 3 February 2014 · 2020. 8. 14. · average $3.48/GJ in 2014 and $3.50/ GJ in 2015, an...

© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

Issue: 3

February 2014

kpmg.ca

Alberta’s future energy mix: exploring the potential for renewables


KPMG invests in the industry through thought leadership papers and journals, share forums and whitepapers on trends, opportunities and challenges affecting the Canadian Power & Utilities sector.

Issue one, A New Era for Clean Energy in Canada, provided an update on project finance market trends and commented on the prospects of new power generation developments in British Columbia and the rest of Canada.

Issue two, Wind Energy in Canada: Realizing the Opportunity, examined wind financing activities given the significant activity in the sector in the last 18 months and highlighted the next wave of wind opportunities in the province of Québec.

In this issue we focus on Alberta’s future energy mix, by discussing the opportunities that will arise for new electricity generation in Alberta, the energy sources that will feature most prominently and assess the potential for renewable energy projects. We also analyze the complexities of the Alberta market, the impact that power policy revisions may have on investment in renewable energy and the issues related to project financing in the province.



Combination of significant load growth and retirements creating new generation requirementsAlberta’s oil sands industry continues to drive new electricity demand. The Alberta Electric System Operator (AESO) estimates that peak demand will hit 18,194 MW by 2032, a significant increase on the 10,599 MW peak demand in 2012. This represents a compound annual growth rate (CAGR) of almost 3% without considering coal-fired plant retirements in excess of 4,500 MW.1 This is significantly more than the forecast US load CAGR of 0.8% during the same period.2 The AESO estimates that 6,190 MW of new effective electricity capacity will need to be built in Alberta by 2022 to meet demand and that 12,965 MW will need to be installed by 2032.3

Generation and load growth driving transmission development needsIt has been estimated that approximately $13-$15 billion will be invested in transmission assets in Alberta in the next five to 10 years. This investment requirement is

partly being driven by oil sands developments in the northern parts of the province and from the addition of new generation planned to come into service in transmission constrained areas, both of which require an upgraded system to connect to the grid.

Gas to plug capacity gap in the next five years New combined cycle natural gas-fired power plants, and to a lesser extent some simple cycle peaking facilities, are expected to be the preferred mode of generation built to meet Alberta’s supply gap in the next five years. Gas plants currently remain attractive due to the current and expected future low price of natural gas and the comparatively fewer restrictions on site selection compared to other jurisdictions. The AESO estimates that gas-fired installed capacity will reach over 11,000 MW in 2022, representing 53% of Alberta’s energy mix. In 2012 5,359 MW (representing about 40% of the overall energy mix) of gas-fired generating capacity was operational.4 The AESO predicts that new wind capacity will make up the balance.

Summary findings

1, 3, 4 Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)2 US Energy Information Administration, Annual Energy Outlook 2013

Alberta is one of the few jurisdictions in Canada with significant new generation requirements. However, with limited opportunities for long-term contracts to support developments, new projects need to rely on merchant prices to provide sufficient returns and debt coverage. There is a growing consensus in industry that increased demand and pending changes to existing policies are converging to support significant generation investments in Alberta, including new renewables.

Clean Energy Report | 01


Economics for new wind projects are challengingDespite the recent rise in natural gas prices, depressed pricing challenges the economic case for wind energy. Natural gas prices are expected to average $3.48/GJ in 2014 and $3.50/GJ in 2015, an increase on the 2012 average price ($2.28/GJ) but in line with the average price in 2011 ($3.48/GJ), according to Gas Alberta.5 Despite a challenging pricing environment, some major wind farms in Alberta have made considerable progress in the past 18 months by realizing value from a California Renewable Energy Credit (REC) measure. This measure, which is no longer available, enabled some level of debt financing to be added to the projects’ capital structure.

New policies could mobilize renewables investmentBoth the Alberta and Federal government are considering a series of policy initiatives relating to carbon emissions. The Federal government released its Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations in 2012, which is expected to be effective in 2015. Provincially, while the Alberta government has not yet announced any formal policies, it is expected to bolster the current Specified Gas Emitters Regulation in a way that will incentivize oil and gas companies to offset their carbon emissions through renewable energy investments. In addition, the Alberta government has committed to implementing an alternative energy

framework that will encourage investment in renewable energy projects. New provincial policies are expected to be announced in 2014.

Solar an option in AlbertaThe solar industry feels that it is often given short shrift when considering Alberta’s future energy mix. However, the province’s solar resource is 25% better than Ontario’s and 30% better than Germany’s, according to the Canadian Solar Industries Association (CanSIA).6 Despite this, virtually no solar capacity is currently operating in Alberta. If the province adopts an attractive alternative energy framework, solar would certainly complement wind as it could generate electricity during the intervals when wind farms are not operating. This is especially true given that the average peak price is close to grid parity. The bulk of a solar photovoltaic (PV) generator’s margin will be made when the power price moves above $80 per MWh.

Debt financingThe lack of offtake agreements provides a challenge to debt financing of projects. While some debt providers have financed power projects in Alberta without any offtake agreement, these have typically been smaller hydro plants. Providing debt financing to a wind farm or a Combined Cycle Gas Turbine (CCGT) plant will continue to be challenging unless some market mechanism can be introduced to manage downside risk, or some level of contracting can be arranged.

5 Gas Alberta: www.gasalberta.com6 Solar resource is expressed in terms of solar irradiance per equivalent area in different jurisdictions

//Given Alberta’s economic growth profile, we’re very excited about new generation opportunities in the province.//Craig Walter Partner and GTA Energy Leader KPMG LLP

02 | Clean Energy Report

© 2014 KPMG LLP, a Canadian limited liability partnership and a member fi rm of the KPMG network of independent member fi rms affi liated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

Assessing the load growth challengeThere is a signifi cant need for new electricity generation capacity in Alberta. By 2032, the AESO expects peak demand to hit 18,194 MW, a signifi cant increase on the 10,599 MW peak demand in 2012.7

This anticipated growth is a direct result of Alberta’s growing oil sands industry. Crude oil prices in the range of $100/barrel, combined with low interest rates, has led to predictions that up to $218 billion could be invested in Alberta’s oil sands sector in the next 25 years. Alberta’s Energy Resources Conservation Board estimates that this investment could lead to production almost doubling to 3.8 million barrels per day in 2022, up from 1.9 million barrels per day in 2012.8

The oil sands industry is also indirectly increasing electricity demand by attracting an infl ux of workers and their associated new non-commercial demand. According to Alberta Treasury Board and Finance, Alberta’s population is projected to grow 2%

annually between 2012 and 2021, before falling to 1.5% annual growth between 2021 and 2041.9

However, load growth is only part of the story. New electricity generation is also required to meet the planned closure of a series of coal-fi red power plants. Federal government policy requires all coal-fi red generation to be retired at 45 years of operation or the expiration of a plant’s power purchase agreement (PPA). Proposed regulations due to be enacted in 2015 also require coal-fi red generation capacity to curb carbon emissions to natural gas levels. This will make new coal plants relatively more expensive from 2015.

These two factors will result in a series of coal plant retirements during the next two decades to the extent that only 5,906 MW of coal capacity is likely to be operating by 2022 and 2,856 MW by 2032, a considerable reduction from the 6,242 MW that was operational in 2012.10 Some major announced retirements are shown in Figure 1: Assumed coal generation retirements.

Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook (Calgary, AB: AESO, 2012)

7, 10 Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)8 Alberta Energy Resources Conservation Board, Alberta’s Energy Reserves 2012 and Supply/Demand Outlook 2013–2022 (Calgary, AB: ERCB, 2013)9 Alberta Treasury Board and Finance, Alberta Population Projection (Edmonton, AB: 2013)

Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012)Long-term Outlook (Calgary, AB: AESO, 2012) Power plant Retired capacity by

2022

Sundance 1,2,3,4 1,344 MW

HR Milner 144 MW

Battle River 3,4 308 MW

Total 1,796 MW

Power plant Retired capacity

(2022-2032)

Sundance 5,6 807 MW

Battle River 5 389 MW

Sheerness 1,2 780 MW

Keephills 1,2 780 MW

Total 2,756 MW

Figure 1: Assumed coal generation retirements

//With planned generation retirement and strong demand growth, Alberta is poised to benefi t from renewable energy investments in the short and medium term.//Georges ArbacheVice PresidentKPMG LLP



As shown in Figure 2: Expected Alberta generation capacity requirements, peak load will eclipse existing generation capacity (including retirements) within the next decade. The AESO estimates that 6,190 MW of new effective generation capacity will be brought online in Alberta by 2022 to meet this gap. By 2032, almost 13,000 MW of new effective capacity will need to be installed.11

Generation and load growth driving transmission development needs Load growth is also forcing the development of new transmission capacity. No major new transmission lines have been built in Alberta since the 1980s, during which time the population has grown by over one

Figure 2: Expected Alberta generation capacity requirements

Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)

Note: Effective capacity accounts for derates to intermittent renewable energy resources and is therefore less than installed capacity.

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million. In 2008, the last year for which data is available, the cost of line losses totalled $220 million, according to Alberta Energy.12 In response, the province has embarked on an extensive transmission expansion program. The most notable transmission projects are outlined in Figure 3: Announced Alberta transmission projects.

Evan Bahry, Executive Director at the Independent Power Producers Society of Alberta (IPPSA) summarizes the need for new transmission infrastructure. “Our bitumen is quite remote, located up in Fort McMurray which is quite a long way north of Calgary,” he said. “All of the pipelines across the province and the country require electricity transmission. Some $13-$15 billion will be invested in transmission assets in Alberta in the next five to 10 years. We have built

about $13 billion worth of generation in recent years, which has resulted in the grid becoming quite constrained. You can’t easily build a new power plant anywhere due to congestion. We need another $20-$30 billion of generation so we need to get the transmission in place so that consumers can get power and generators can connect to the grid.”

The province has decided to run a competitive process in selecting entities to construct and operate transmission lines. The competitive process introduces a new development structure and has attracted the interest of a number of non-incumbents. The first project being tendered for competition is the Fort McMurray West 500 kV Transmission Project, which will transport electricity between the Edmonton and Fort McMurray regions. In January 2014 the AESO revealed

11 Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013) 12 Alberta Energy: www.energy.alberta.ca/Electricity/1773.asp

//$13-$15 billion will be invested in transmission assets in Alberta in the next five to 10 years.//Evan Bahry Executive Director Independent Power Producers Society of Alberta



Figure 3: Announced Alberta transmission projects

Source: Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)

the five consortia selected to enter the request for qualification (RFQ) stage. The winning bid will be announced in December 2014.

Gas to meet capacity gap in the short termAll major generators believe combined cycle natural gas will meet most of the growing demand requirement through to 2020. As outlined in Figure 5:

13 Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)

Projected installed capacity in Alberta in 2022, the AESO estimates that natural gas will account for 53% (11,036 MW) of Alberta’s generation mix by 2022 (including cogeneration), up from 39% (5,359 MW) in 2012. Wind deployment is also expected to increase, but to a lesser extent. The AESO predicts that wind could account for 11% (2,206 MW) of the energy mix by 2022, almost doubling from 6% (865 MW) at the beginning of 2012.13

“The most obvious new capacity is large frame CCGT plants,” explained Etienne Snyman, Manager, Business Development at ATCO Power. “This is certainly what ATCO is currently pursuing. With Alberta being a large gas supplier it is difficult to justify anything else at this time. I can’t really see coal being a major contributor in the next 20 years due to its cost and the environmental implications.”

Project Description Bulk region CostExpected/actual commencement

date

Heartland 500 kV (CTI)

Double circuit 500 kV line from Ellerslie to a new 500/240 kV substation near Fort Saskatchewan

Northeast $537 million 2013

West HVDC (CTI) HVDC 500 kV line connecting the Wabamun area near Genesee with the Calgary area at Langdon

Edmonton $1,329 million 2014

East HVDC (CTI) HVDC 500 kV line connecting the Northeast area at Heartland with the South area near Brooks

Edmonton $1,622 million 2014

Bickerdike - Little Smoky

Double circuit 240 kV line from Bickerdike to Little Smoky

Northwest $205 million 2015

West Fort McMurray

500 kV AC line connecting Wabamun area near Genesee to the Northeast area near Fort McMurray

Northwest $1,649 million 2017

South area transmission reinforcement

Multiple 240 kV double circuit lines from and within the south to the Calgary area

South $2,287 million 2011-2017

Foothills area transmission development

240/138 kV Foothills substation near High River, two double circuit 240 kV lines from Foothills to east and west Calgary, and several local 240 kV and 138 kV enhancements

South $711 million 2014-2017



Natural gas is expected to plug the majority of the capacity gap as its current low price is expected to continue for at least the next five years, reinforcing natural gas-fired supply as the lowest cost new generation source (see Figure 6 on page 7).

Given Alberta’s market based electricity structure, the prevailing price of natural gas directly sets hourly market prices and, in turn, the economics of operating existing plants and new generation

(refer to page 8, ‘Explaining Alberta’s merchant power market’ for more information on how the province’s power market operates).

New gas fired generation is also expected to be preferred in the next five years as it is scaleable and not geographically bound to the source of the resource as with wind. This flexibility will allow natural gas facilities to locate at the sites of retired coal plants to take advantage

of existing infrastructure, transmission connectivity, available water, a local workforce and a pre-existing consent of use for the site. These existing site advantages are clearly a motivation for TransAlta Utilities to build an 800 MW CCGT power plant to replace part of its Sundance coal complex on the south shore of Wabamun Lake.

Other players have a line up of gas-fired developments. “We have a site called Saddle Brook Power that was permitted in 2008,” explained Geoff Murray, Vice President, Western Power Growth at TransCanada. “Every player in the market has one of these in the pipeline to replace coal retirements. Capital Power has talked about the Capital Energy Centre. ATCO has up to 1,500 MW of combined cycle announced in the Heartland area that they will build in tranches and TransAlta has talked about Sundance 7. This carries capacity through to the turn of the decade.”

The large build-out of gas-fired plants is already attracting the interest of new market entrants in partnering with incumbent Alberta-based owner/operators. In October 2012, TransAlta announced the formation of a new strategic partnership with MidAmerican Energy Holdings Company to develop and own new natural gas-fuelled power projects across Canada. The partnership includes TransAlta’s planned 800 MW gas-fired Sundance project, which will be owned on a 50/50 basis.

Rob Schaefer, Corporate Development at TransAlta, explains the motivations for this partnership: “Access to capital is not a significant hurdle, but what is a bit more of a challenge is accepting merchant risk and how much risk you want to put into any one project. Partnering is an option when companies want to spread the risk, and this is what we have done with MidAmerican.”

Figure 4: Installed capacity in Alberta in 2012

Figure 5: Projected installed capacity in Alberta in 2022



GAS

HYDRO

WIND

OTHER

COAL

5,359MW 6,242MW879MW

865MW314MW

GAS

HYDRO

WIND

OTHER

COAL

5,906MW11,036MW894MW

2,206MW

621MW



Figure 6: Forecast monthly natural gas prices (Intra-Alberta C$/GJ)

Brian Vaasjo, CEO of Capital Power, also shared his thoughts on the new players entering the Alberta market: “Coal plant retirements will result in very significant requirements for additional generation. This will largely be met through large combined cycle natural gas plants. This may provide an opportunity for new entrants into the market. There is a lot of talk about new entrants to the market and we are hearing of a lot of enquiries from generators such as the large North American independent power producers who want to enter the Alberta market.”

Cogeneration will have a role to playWhile CCGT facilities will likely fill the majority of the supply gap, behind-the-meter cogeneration projects will also play a part in meeting power demand in the oil sands industry. Rob Schaefer explains some of the opportunities and challenges of cogeneration investments. “Cogeneration is attractive as it can provide generation behind-the-fence so it avoids grid costs and is also often more efficient than a combined cycle plant. Cogeneration has these advantages although it tends to be more expensive to build. One drawback to CCGT is that it very rarely matches supply exactly. Oil sands facilities have a lot higher thermal than electric load, so getting the balance is hard. You can either build to meet the thermal load and take a lot of excess power to the grid. Or you can build the electric load and put in boilers to meet the rest of the thermal demand.”

Source: Gas Alberta Inc (Calgary, AB: 2013)

//Cogeneration is attractive as it can provide generation behind-the-fence so it avoids grid costs and is also often more efficient than a combined cycle plant.//Rob Schaefer Corporate Development TransAlta

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Explaining Alberta’s merchant power marketUnlike most other Canadian provinces, Alberta operates a deregulated electricity system whereby all electricity that is not self-supplied must be exchanged through the Alberta power pool. In contrast to most other provinces that provide long-term contracts for independent power producers, Alberta does not have organized programs for long-term contracting. The power pool functions as a spot market, matching demand and supply to establish an hourly pool price. Generators must submit their offer to supply electricity in MWh blocks for each hourly period during the next seven days.

The System Controller forms a supply schedule based on a ranking of the bids from the least to the most expensive. The electricity price is determined by taking the weighted average of the system price over an hourly basis. All power producers receive the hourly pool price for power generated. In contrast, the electricity trans-mission and distribution market is regulated and financed by ratepayers.

This deregulated market structure appears to be working in terms of encouraging investment in new generation while maintaining stable prices. As shown in Figure 7, between 2003 and 2012 Alberta’s net market generation capacity increased 25% while prices remained stable. The average hourly pool price was $64.32 per MWh in 2012, a 16% decrease on 2011 and a 2% increase on a decade ago.14

Figure 7: Average annual Alberta electricity pool prices and installed capacity

Source: Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)

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14 Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)




Wind – a viable long-term complement to gas?Current gas prices limit the business case for new wind generation While Alberta has some of Canada’s best wind resources and as such can deliver strong technical project funda-mentals, the majority of stakeholders interviewed for this report believe that the current low gas price environment limits the economic viability of new wind projects. Natural gas prices in Alberta are not forecast to increase sub-stantially in the foreseeable future.

As Mary Hemmingsen, Partner and National Power and Utilities Sector Lead at KPMG LLP, explains, wind projects are further challenged as they receive a discount to the average market price. “Wind production, being intermittent and not dispatchable, floods the market with supply and depresses the price at the time wind is able to generate. So realized prices for wind production are considerably less than the average market price. This circumstance is exacerbated by the concentration of wind farms in the southwest (of Alberta) where there is a superior wind resource that generally results in a significant volume of wind capacity coming online simultaneously.”

Rob Roberti, Senior Vice President of Power Generation at Capstone Infrastructure Corp, believes that this discount is increasing. “In 2013, the wind discount to the average power pool price was 46%,” he said. “Wind does not always generate when power prices are high. In a 10,000-12,000 MW

capacity market, 700-1,000 MW of wind coming online at the same time causes the price to decrease. Most of Alberta’s wind farms are located in south-western Alberta so wind capacity can go from 200 MW to 800 MW rather quickly. Just a few years ago this discount was in the 20%-30% range. The discount is now pushing 50% and as more wind comes online this discount will get worse. This is difficult for the wind generators, although it does show how more wind can push down energy costs.”

Another major obstacle for wind energy in Alberta is the lack of transmission capacity in the grid. With some 1,117 MW of wind concentrated around a limited number of locations, the capacity of the system to carry more wind is currently limited. However, as mentioned earlier, Alberta is currently undertaking a significant transmission expansion program, which should alleviate some of these constraints. “The reality of the situation is that jurisdictions have system capacity restrictions associated with renewable energy that is intermittent,” explained Brian Vaasjo. “You can only have so much wind in the system and Alberta already has a lot. We are getting pretty close to the technical limits of that. This doesn’t mean that more can’t be built, but the cost from a system perspective goes up pretty dramatically.”

However, gas prices may rise over time to allow wind to become competitive by the end of the decade. “There will be smaller renewable energy projects

//The reality of the situation is

that jurisdictions have system

capacity restrictions associated with renewable energy that is intermittent.//Brian Vaasjo President & CEO Capital Power Corporation



around biomass and other technologies,” explained Brian Vaasjo. “But in terms of larger scale projects, I don’t really see it happening until power prices go up. In the next few years power prices are expected to remain relatively low. When prices go up, grid parity with renewables will become reality if technology can continue to become more efficient and capital costs go down.”

Extra market support for wind projects no longer available Despite the current unfavourable economics of wind energy, two large projects moved forward in the past 12 months. In December 2012, the 150 MW Halkirk wind farm sponsored by Capital Power commenced commercial operations. Six months later construction of the 300 MW Blackspring Ridge wind farm commenced following its acquisition by EDF EN Canada and Enbridge. This project will surpass Halkirk as Alberta’s largest wind farm when it comes online in the summer of 2014.

Both projects managed to secure 20-year agreements for RECs from Californian utility Pacific Gas and Electric Company, which made the projects economically viable. The REC purchase provides the projects with an additional income stream to the revenues received from selling into the Alberta power pool at the spot market price. However, as Rob Roberti explains, the sale of RECs to California is no longer an option for Alberta generators. “The bulk of the investment in wind has been two big projects that benefitted from unique financing circumstances in that they sold RECs to the California market,” he said. “We do not expect this to happen again, making these projects a one-off. California has changed

its regulations to cap the number of RECs that can go to regions outside California.”

Carbon offsets drive wind investmentWind energy projects in Alberta have been driven by the need to offset carbon emissions. In 2007, the Alberta government introduced the Specified Gas Emitters Regulation, which sets gas intensity limits for large emitters of greenhouse gases in the province. The regulation states that large emit-ters must reduce emissions intensity by 12% from an average baseline year after nine years of operation.

Should an emitter not meet these targets, it must comply by either paying $15 per tonne into the Climate Change and Emissions Management Fund for every tonne that exceeds the reduction target, or by purchasing emission offsets generated from Alberta-based projects that are not subject to the regulation, including wind farms. A third option is to purchase Emissions Performance Credits from a different Alberta facility that has exceeded its emissions reduction target.

This regulation led to a number of large oil and gas companies with significant emissions investing in wind farms in order to obtain offsets for their emissions. For example, Canadian oil and gas company Nexen, which is now owned by Chinese energy company CNOOC, invested in the 70.5 MW Soderglen wind farm that came online in 2006. Nexen owns 50% of the project but 100% of the carbon credits, which can be used to help meet its emissions reduction target. Energy companies Suncor and Enbridge have also built wind farms in Alberta in order to offset carbon emissions.

//With continued technology innovation to reduce renewable supply costs, supportive carbon policies and demand pushing market prices, wind and other renewables can have a prominent role in Alberta’s future supply mix.//Mary Hemmingsen Partner and National Power & Utilities Sector Leader KPMG LLP



New policy could redefine investment landscapeNew emissions policy could revitalize wind An increase in carbon emissions targets and the carbon price is likely to bode well for renewables generation and drive large emitters to invest in wind energy projects for their offset potential. The Alberta government is currently considering bolstering its emissions regulation to build social license for its carbon-intensive oil sands industry and multi-billion dollar pipeline projects such as Keystone XL, which will transport bitumen to the US. There has been considerable speculation that the Alberta government will introduce more aggressive benchmarks such as a “40/40 target”, which will increase the carbon emissions target for large emitters from 12% to 40% and increase the carbon price from $15 per tonne to $40 per tonne. However, it should be noted that the Alberta government has not clarified how it will change the current regulation.

An increase in carbon emissions targets and the carbon price is likely to bode well for renewables generation and drive large emitters to invest in wind energy projects for their offset potential.

“Alberta has a significant emissions challenge with the oil sands development,” explained Evan Bahry. “Next year Alberta is looking at redoing its Specified Gas Emitters Regulation. We were one of the first North American jurisdictions to put a price on carbon at $15 per tonne. The province recognizes that it needs to reduce its

emissions so it will likely increase its emissions cost to those who emit. This creates an offset potential for wind. The province has signalled that they need to do more but they haven’t offered any clarity yet. This will be important.”

Wind is also likely to become more attractive from an offset perspective regardless of policy revisions. Some large emitters have already adopted corporate policies that encourage carbon offsetting. For example, Enbridge has adopted a ‘Neutral Footprint’ commitment to generate a kilowatt of renewable energy for every kilowatt of conventional electricity that the company’s operations consume.

Oil and gas companies are most likely to be compelled to invest in wind projects for their offset potential. As depicted in Figure 8, the oil sands industry accounted for 23% of Alberta’s

greenhouse gas emissions in 2011 while the oil, gas and mining sector accounted for 18%, according to Alberta Ministry of Environment and Sustainable Resource Development.15 Electricity and heat generation companies account for 20% of greenhouse emissions but are unlikely to invest in wind farms specifically for their offset potential. This is because many power utilities are already reducing carbon emissions by replacing aged coal-fired plants with cleaner CCGT plants.

“When you look at the carbon footprint of Alberta, coal plant retirement that is required by law will lead to a dramatic reduction in carbon emissions,” confirmed Brian Vaasjo. “So from the power generation side you are replacing coal with natural gas. Replacing natural gas with wind is not that much of a step in reducing carbon emissions.”

Figure 8: Alberta greenhouse gas emissions by sector National Inventory Report 2011

Source: Alberta Ministry of Environment and Sustainable Resource Development, National Inventory Report (Edmonton, AB, 2011)

Waste

Industrial process

Manufacturing/construction

Residential/commercial

Agriculture

Transportation

Oil, gas and mining

Electricity & heat generation

Oil sands

23%

20%

18%

16%

7%

6%5%

4%

1%

15 Alberta Ministry of Environment and Sustainable Resource Development, National Inventory Report (Edmonton, AB, 2011)



New renewable energy framework could catalyze solar and windInvestment in solar and wind could be catalyzed by a new renewable energy framework the province is currently considering. Alberta Energy, the province’s energy ministry, is currently drafting a policy framework for implementation in 2014. No details on the structure have been revealed, but the government is expected to favour a clean energy standard, which will limit greenhouse gas emissions in the electricity sector. Any new policy framework is expected to be in line with Alberta’s current merchant market structure. Other options include requiring generators to produce a certain percentage of electricity from renewable sources, or the introduction of an Ontario-style feed-in tariff.

“Alberta’s push to green its electricity grid is not being driven by the renewable industry alone,” explained John Gorman, President of CanSIA. “The Premier and her cabinet ministers are actively talking about the need for Alberta to establish the social licence nationally and internationally so that it may drive ahead with projects like Keystone XL and continue to develop its oil and gas resources. This is a signifi cant factor in what is driving them to come forward with the Alternative Renewable Energy Framework. There is a perfect storm in Alberta right now and renewables may end up a safe harbour for the long term.”



Tapping Alberta’s solar resourceSolar is often left out of the debate when it comes to Alberta’s energy mix despite the province having the best solar resource in Canada. According to CanSIA, Alberta’s solar resource is 25% better than Ontario’s and 30% better than Germany’s, both of which have seen signifi cant solar installation driven by subsidies. In the absence of mechanisms to stimulate solar development, Alberta has virtually no installed solar capacity at present.

As is the case with wind energy, solar PV could be more heavily deployed in the next fi ve years if, as is widely anticipated, the government introduces policy that puts more pressure on industry to reduce carbon emissions and, in turn, incentivizes investment in renewables. Solar may also prove compelling due to its improving cost profi le and superior output profi le.

“Solar could make sense for moments when wind output is generally low on hot summer days when air conditioning is ramping up,” explained Rob Roberti. “Given the decrease in solar costs, solar is close to being at grid parity at these times of day. Southeast Alberta has some of the best solar resource in Canada. If you just look at the average price then solar is not at grid parity in Alberta. That said, when you take into consideration that the average peak price is close to grid parity and that you are going to make the bulk of your margin when the power price spikes to over $80 per MWh, solar might make sense.”

One of the main challenges for utility-scale solar projects in Alberta is that the market price differentials for solar are not close relative to conventional resources. “On the utility scale front, the market mechanism does not provide for power purchase agreements,” explains John Gorman. “The government will have to come up with a policy or program that addresses this as we move forward with replacing coal assets. We are discussing a strategy with the provincial government for both utility-scale and distributed solar generation and there is certainly potential for both. We haven’t looked at how much solar PV could be installed in Alberta but our recommendation to the Ontario government is that solar could account for 5% of electricity demand at any one time.”

As Ron Seftel, Senior Vice President, Operations at Bullfrog Power explains, the initial adopters of solar PV will be municipal organizations. “As with all renewable energy installations, these are long term projects. From a fi nancial perspective, if you are in a position to consider the long term return, maybe over 15 or 20 years, then solar is very attractive. Solar is nearing grid or socket parity now, so will likely be extremely competitive in as little as fi ve or six years as conventional electricity prices are expected to rise in Alberta. Not everyone can take this long-term view but certainly municipalities and school boards who know they are going to be around for 20 years can, so they will likely be the initial adopters of solar and will help to kick-start the local industry.”

//Solar is nearing grid or

socket parity now, so will likely

be extremely competitive in as little as fi ve or six years as conventional electricity prices are expected to rise in Alberta.//Ron SeftelSenior Vice PresidentBullfrog Power



Bringing financing into Alberta’s merchant market – an issue of growing importanceIncumbent generators in Alberta are sufficiently capitalized to fund their pipeline of CCGT projects earmarked to replace retired coal capacity from 2017. Major generators such as TransCanada and ATCO both have large balance sheets. TransAlta has established a partnership with MidAmerican to share financing its pipeline of gas-fired generation projects, while Capital Power has already structured financing for its planned Shepard Energy Centre. However there is a growing interest in alternative financing mechanisms for new market entrants to finance power assets.

These new participants will be keen to explore alternatives to balance sheet financing, including project debt financing and equity co-investment. Alberta’s merchant market structure and limited liquidity due to the islanded nature of the power market, exacerbated by self supply, means that project financing will prove challenging.

“The lack of offtake agreements makes it very difficult to bring debt finance into contracts,” confirms Etienne Snyman. “With PPAs, lenders have some cash flow stability and a basis upon which they can lend to. There are some creative mechanisms that can be used to secure debt financing, particularly when it comes to cogeneration. One of the mechanisms would be to sell some of the power from cogeneration behind the fence

and as such get a long-term contract, enabling project financing. It will continue to be very hard for large stand-alone CCGT projects to secure project financing unless you can get a contract over the transmission system.”

As John Vincent, Senior Managing Director, Head of Project Finance at Sun Life Financial explains, some debt providers have financed power projects in Alberta without an offtake contract, although these have typically been hydro projects. “We have done merchant financing but the leverage has always been much lower than what you would get with a contractual cashflow. We have only done this for hydro projects that have very low operating costs so are always going to be running. This desensitizes them to low power prices at certain times of the day. There are some nuances with hydro that are quite interesting in that it can be peaked depending on the situation to ensure you are producing when power prices are the highest.”

“But providing debt financing into a wind farm or a CCGT plant will be pretty hard in Alberta unless someone is willing to protect against a downside case, which could be in the form of a PPA or another vehicle,” continued Vincent. “Some organizations such as local utilities and cities are looking at stepping in and making arrangements to backstop a power purchase

arrangements of sorts. We are certainly open to solutions like this.”

One way to attract debt project financing is to introduce a degree of contracting into the market structure. This would provide debt providers with the long term revenue certainty needed to invest. How this could be incorporated into Alberta’s merchant market structure is an outstanding issue. Nevertheless, this is something that some of Alberta’s leading generators believe should be given some consideration given the sizeable need for new capacity.

“It is important that government think carefully about whether we need structural change post 2020,” explained Geoff Murray. “Deregulation was a long time in the making. If we are going to reverse this or even nibble around the edges we need time to really think about this. I don’t think there needs to be a wholesale philosophical change but I do think actions will need to be taken to move things along towards some sort of mid to long-term contracting. This could take the form of incentivizing or requiring contracting for some players. This would enable low-cost capital on the debt and equity side to be brought into the market. Contracts also enable companies to invest the huge sums over long periods of time that are required to develop large baseload capacity.”



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AppendixNotable renewable energy asset/project debt finance deals in Canada (2013)

South Kent Wind Farm (270 MW) March 2013 Ontario

Owners Pattern Energy Group LP / Samsung Renewable Energy Inc.

Debt providers

Nord LB / Union Bank / Natixis / Societe Generale / Manulife Financial Corp. / Bank of Tokyo-Mitsubishi UFJ / Mizuho Corporate Bank Ltd. / Royal Bank of Scotland Group plc / KeyBank / Bayern LB / CIBC World Markets Inc. / Credit Agricole Corporate and Investment Bank / Siemens Bank GmbH / BMO Financial Group / Royal Bank of Canada

Financing volume C$700 million Financing type Construction & term loan

Tenor (years) Construction + 7 years Rate (%) N/D

Grand Renewable Solar Energy Park (100 MW) October 2013 Ontario

Owners Connor, Clark & Lunn Infrastructure Ltd. / Samsung Renewable Energy Inc..

Debt providers

Nord LB / Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / KeyBank / Canadian Imperial Bank of Commerce / National Bank of Canada / Caisse centrale Desjardins / Royal Bank of Canada

Financing volume C$525 million Financing type Construction & term loan

Tenor (years) N/D Rate (%) N/D

Comber Wind Farm (166 MW) February 2013 Ontario

Owners Brookfield Renewable Energy Partners LP Debt providers

Scotia Capital Inc.

Financing volume C$450 million Financing type Bond refinancing

Tenor (years) 17.75 years Rate (%) 5.13%

Borealis Solar Portfolio (108 MW) December 2013 Ontario

Owners Metropolitan Life Insurance Company / Fiera Axium Infrastructure Inc.

Debt providers

Sun Life Assurance Company of Canada / National Bank Financial Inc.

Financing volume C$390 million Financing type Construction and term loan

Tenor (years) Construction + 19 years Rate (%) N/D

Vents du Kempt Wind Farm (101 MW) June 2013 Québec

Owners Eolectric Inc. / Fiera Axium Infrastructure Inc.

Debt providers

Manulife Financial Corp. / Caisse de dépôt et placement du Québec / KfW IPEX Bank



Note: This table only includes deals over C$100 million for which the volume of debt financing is disclosed

Advised by KPMG



Walpole, Belmont & Amherstburg Solar Plants (20 MW) August 2013 Ontario

Owners Alterra Power Corp. / GE Energy Financial Services

Debt providers

Manulife Financial Corp. / Sun Life Assurance Company of Canada / Canada Life Assurance Company / Caisse de dépôt et placement du Québec / Great-West Life Assurance Company

Financing volume C$200 million Financing type Acquisition finance


Fort St. James Biomass Plant (33 MW) November 2013 British Columbia

Owners Dalkia plc / Fengate Capital Management

Debt providers

Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / Canadian Imperial Bank of Commerce / National Bank of Canada



FieStar Solar Portfolio (42 MW) June 2013 Ontario

Owners Starwood Energy Group Global LLC / Fiera Axium Infrastructure Inc.

Debt providers

Nord LB / Natixis / Bank of Tokyo-Mitsubishi UFJ



Seigneurie de Beaupre phase II Wind Farm (68 MW) October 2013 Québec

Owners Gaz Metro LP / Valener Inc. Debt providers

Sun Life Assurance Company of Canada / Industrial Alliance Insurance and Financial Services Inc. / KfW IPEX Bank

Financing volume C$166 million Financing type Construction term loan, bridge financing, letter of credit facility

Tenor (years) Construction + 19.5 years Rate (%) N/D

Essex County Solar Plant (51 MW) March 2013 Ontario

Owners Brookfield Renewable Energy Partners LP

Debt providers

Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services Ltd. / Laurentian Bank of Canada

Financing volume C$150 million Financing type Refinancing


Gosfield Wind Farm (50.6 MW) March 2013 Ontario


Debt providers




Continued >



Walpole, Belmont & Amherstburg Solar Plants (20 MW) August 2013 Ontario

Owners Alterra Power Corp. / GE Energy Financial Services

Debt providers

Manulife Financial Corp. / Sun Life Assurance Company of Canada / Canada Life Assurance Company / Caisse de dépôt et placement du Québec / Great-West Life Assurance Company

Financing volume C$200 million Financing type Acquisition finance


Fort St. James Biomass Plant (33 MW) November 2013 British Columbia

Owners Dalkia plc / Fengate Capital Management

Debt providers

Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / Canadian Imperial Bank of Commerce / National Bank of Canada



FieStar Solar Portfolio (42 MW) June 2013 Ontario

Owners Starwood Energy Group Global LLC / Fiera Axium Infrastructure Inc.

Debt providers

Nord LB / Natixis / Bank of Tokyo-Mitsubishi UFJ



Seigneurie de Beaupre phase II Wind Farm (68 MW) October 2013 Québec

Owners Gaz Metro LP / Valener Inc. Debt providers

Sun Life Assurance Company of Canada / Industrial Alliance Insurance and Financial Services Inc. / KfW IPEX Bank

Financing volume C$166 million Financing type Construction term loan, bridge financing, letter of credit facility

Tenor (years) Construction + 19.5 years Rate (%) N/D

Essex County Solar Plant (51 MW) March 2013 Ontario


Debt providers




Gosfield Wind Farm (50.6 MW) March 2013 Ontario


Debt providers




White River - Gitchi Animki Hydro Plant (19 MW) August 2013 Ontario

Owners Regional Power / Pic Mobert First Nation

Debt providers

Manulife Financial Corp.



Glen Dhu Wind Farm (62.1 MW) July 2013 Nova Scotia

Owners Glen Dhu Wind Energy LP Debt providers

Stonebridge Financial Corp.


Tenor (years) 17.5 years Rate (%) 5.33%

CSI Solar Project 3 (30 MW) October 2013 Ontario

Owners Canadian Solar Inc. Debt providers

Deutsche Bank AG

Financing volume C$105 million Financing type Construction loan

Tenor (years) 1.75 years Rate (%) N/D

Solar Portfolio (30 MW) October 2013 Ontario

Owners Canadian Solar Inc. Debt providers

Deutsche Bank AG

Financing volume C$104 million Financing type Construction loan

Tenor (years) 1 year Rate (%) N/D

Mackenzie Biomass Plant (36 MW) November 2013 British Columbia

Owners Conifex Timber Inc. Debt providers

Canadian Imperial Bank of Commerce / Integrated Private Debt Corp. / Business Development Bank of Canada / Export Development Canada (EDC)


Tenor (years) 6 years Rate (%) N/D

Source: Clean Energy Pipeline asset/project finance deal database



Global renewable energy project finance by region

Europe: project finance volume by sector as a % of total debt raised - 2013

North America: project finance volume by sector as a % of total debt raised - 2013

China: project finance volume by sector as a % of total debt raised - 2013

0

10

Dea

l val

ue ($

bill

ion) N

umber of deals20

30

40

50

60

Rest of the world

Asia

North America

Europe

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

4Q11

3Q11

2Q11

1Q11

4Q10

3Q10

2Q10

1Q10

4Q09

3Q09

2Q09

1Q09

0

10

20

30

40

50

60

4-Quarter moving average



OTHERBIOENERGY

SOLAR

WIND

57%23%

12%8%

OTHER

BIOENERGY

HYDRO

SOLAR

WIND

46%

4%

3%

1%

46%WIND

OTHER

BIOENERGY

SOLAR

56%31%

10%3%


© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved. © 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.

About the research

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The information contained herein is of a general nature and is not intended to address the circumstances of any particular individual or entity. Although we endeavor to provide accurate and timely information, there can be no guarantee that such information is accurate as of the date it is received or that it will continue to be accurate in the future. No one should act on such information without appropriate professional advice after a thorough examination of the particular situation.

© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved. Printed in Canada. 2349

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Mary HemmingsenPartnerAdvisory Services, National Sector LeaderPower and UtilitiesT: 416 777 8896E: [email protected]

Trevor HammondPartner AuditT: 403 691 7913E: [email protected]

Craig WalterPartner GTA Energy LeaderInfrastructure Advisory and Transaction ServicesT: 416 777 8342E: [email protected]

Stephen SpoonerPartner AdvisoryT: 403 691 8403E: [email protected]

Georges ArbacheVice PresidentInfrastructure Advisory DevelopmentM&A and StrategyT: 416 777 8170E: [email protected]

This report provides insight into financing, investment and development trends in Canada’s clean energy sector. The research for this report was provided by Clean Energy Pipeline, a specialist provider of research, data and news on the clean energy sector.

Both articles in this report include comments from interviews conducted with the following individuals:

• Etienne Snyman, Manager, Business Development, ATCO Power Ltd• Ron Seftel, Senior Vice President, Operations, Bullfrog Power• John Gorman, President, Canadian Solar Industries Association• Brian Vaasjo, President & CEO, Capital Power Corporation• Rob Roberti, Senior Vice President of Power Generation, Capstone Infrastructure Corporation• Evan Bahry, Executive Director, Independent Power Producers Society of Alberta • John Vincent, Senior Managing Director, Head of Project Finance, Sun Life Financial• Rob Schaefer, Executive Vice President, Trading and Marketing, TransAlta Corporation• Geoff Murray, Vice President, Western Power Growth, TransCanada Corporation

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