Alberta's Future Energy Mix: Exploring the Potential for Renewables

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

Issue: 3 February 2014 kpmg.ca

© 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. 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.

Summary findings

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.

Combination of significant load partly being driven by oil sands growth and retirements creating developments in the northern parts of new generation requirements the province and from the addition of new generation planned to come into Alberta’s oil sands industry continues service in transmission constrained to drive new electricity demand. The areas, both of which require an Alberta Electric System Operator upgraded system to connect to the (AESO) estimates that peak demand grid. will hit 18,194 MW by 2032, a significant increase on the 10,599 MW Gas to plug capacity gap in the peak demand in 2012. This represents a next five years compound annual growth rate (CAGR) of almost 3% without considering New combined cycle natural gas-fired coal-fired plant retirements in excess power plants, and to a lesser extent of 4,500 MW.1 This is significantly some simple cycle peaking facilities, more than the forecast US load CAGR are expected to be the preferred mode of 0.8% during the same period.2 The of generation built to meet Alberta’s AESO estimates that 6,190 MW of new supply gap in the next five years. effective electricity capacity will need Gas plants currently remain attractive to be built in Alberta by 2022 to meet due to the current and expected demand and that 12,965 MW will need future low price of natural gas and to be installed by 2032.3 the comparatively fewer restrictions on site selection compared to other Generation and load growth jurisdictions. The AESO estimates that driving transmission development gas-fired installed capacity will reach over 11,000 MW in 2022, representing needs 53% of Alberta’s energy mix. In 2012 It has been estimated that 5,359 MW (representing about 40% approximately $13-$15 billion will be of the overall energy mix) of gas-fired invested in transmission assets in generating capacity was operational.4 Alberta in the next five to 10 years. The AESO predicts that new wind This investment requirement is capacity will make up the balance.

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

Economics for new wind projects framework that will encourage are challenging investment in renewable energy projects. New provincial policies are Despite the recent rise in natural gas expected to be announced in 2014. prices, depressed pricing challenges the economic case for wind energy. Natural gas prices are expected to Solar an option in Alberta average $3.48/GJ in 2014 and $3.50/ The solar industry feels that it is often GJ in 2015, an increase on the 2012 given short shrift when considering average price ($2.28/GJ) but in line Alberta’s future energy mix. However, with the average price in 2011 ($3.48/ the province’s solar resource is 25% GJ), according to Gas Alberta.5 Despite better than Ontario’s and 30% better a challenging pricing environment, than Germany’s, according to the //Given Alberta’s some major wind farms in Alberta have Canadian Solar Industries Association made considerable progress in the (CanSIA).6 Despite this, virtually no economic growth past 18 months by realizing value from solar capacity is currently operating a California Renewable Energy Credit in Alberta. If the province adopts profile, we’re very (REC) measure. This measure, which is an attractive alternative energy no longer available, enabled some level framework, solar would certainly excited about of debt financing to be added to the complement wind as it could generate projects’ capital structure. electricity during the intervals when new generation wind farms are not operating. This is New policies could mobilize especially true given that the average opportunities in the renewables investment peak price is close to grid parity. The bulk of a solar photovoltaic (PV) Both the Alberta and Federal generator’s margin will be made when province.// government are considering a series the power price moves above $80 per of policy initiatives relating to carbon MWh. Craig Walter emissions. The Federal government Partner and GTA Energy Leader released its Reduction of Carbon Debt financing KPMG LLP Dioxide Emissions from Coal-fired Generation of Electricity Regulations The lack of offtake agreements in 2012, which is expected to be provides a challenge to debt financing effective in 2015. Provincially, while of projects. While some debt providers the Alberta government has not yet have financed power projects in announced any formal policies, it Alberta without any offtake agreement, is expected to bolster the current these have typically been smaller hydro Specified Gas Emitters Regulation plants. Providing debt financing to a in a way that will incentivize oil and wind farm or a Combined Cycle Gas gas companies to offset their carbon Turbine (CCGT) plant will continue to emissions through renewable energy be challenging unless some market investments. In addition, the Alberta mechanism can be introduced to government has committed to manage downside risk, or some level implementing an alternative energy of contracting can be arranged.

5 Gas Alberta: www.gasalberta.com 6 Solar resource is expressed in terms of solar irradiance per equivalent area in different jurisdictions

Assessing the load growth challenge

There is a signifi cant need for new annually between 2012 and 2021, electricity generation capacity in before falling to 1.5% annual growth Alberta. By 2032, the AESO expects between 2021 and 2041.9 peak demand to hit 18,194 MW, a However, load growth is only part of the //With planned signifi cant increase on the 10,599 MW story. New electricity generation is also peak demand in 2012.7 required to meet the planned closure generation retirement This anticipated growth is a direct of a series of coal-fi red power plants. result of Alberta’s growing oil sands Federal government policy requires all and strong demand industry. Crude oil prices in the range coal-fi red generation to be retired at 45 of $100/barrel, combined with low years of operation or the expiration of growth, Alberta is interest rates, has led to predictions a plant’s power purchase agreement that up to $218 billion could be (PPA). Proposed regulations due to be poised to benefi t invested in Alberta’s oil sands sector enacted in 2015 also require coal-fi red in the next 25 years. Alberta’s Energy generation capacity to curb carbon from renewable Resources Conservation Board emissions to natural gas levels. This will estimates that this investment could make new coal plants relatively more lead to production almost doubling expensive from 2015. energy investments to 3.8 million barrels per day in 2022, These two factors will result in a series up from 1.9 million barrels per day in in the short and of coal plant retirements during the next 2012.8 two decades to the extent that only medium term.// The oil sands industry is also indirectly 5,906 MW of coal capacity is likely to increasing electricity demand by be operating by 2022 and 2,856 MW attracting an infl ux of workers and by 2032, a considerable reduction from Georges Arbache their associated new non-commercial the 6,242 MW that was operational Vice President demand. According to Alberta in 2012.10 Some major announced KPMG LLP Treasury Board and Finance, Alberta’s retirements are shown in Figure 1: population is projected to grow 2% Assumed coal generation retirements.

Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook (Calgary, AB: AESO, 2012) Power plant Retired Power plant Retired capacity by capacity 2022 (2022-2032) Sundance 1,2,3,4 1,344 MW Sundance 5,6 807 MW HR Milner 144 MW Battle River 5 389 MW Battle River 3,4 308 MW Sheerness 1,2 780 MW Total 1,796 MW Keephills 1,2 780 MW Total 2,756 MW

Figure 1: Assumed coal generation retirements

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)

Figure 2: Expected Alberta generation capacity requirements

18 Load outlook //$13-$15 billion 16 (winter peak) will be invested 14 Existing other generation 12 in transmission Existing effective 10 wind generation assets in Alberta 8 Existing effective in the next five to Capacity (GW) 6 hydro generation 4 Existing gas 10 years.// generation 2 Existing coal Evan Bahry 0 generation Executive Director 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 Independent Power Producers Society of Alberta Note: Effective capacity accounts for derates to intermittent renewable energy resources and is therefore less than installed capacity. Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)

As shown in Figure 2: Expected Alberta million. In 2008, the last year for about $13 billion worth of generation in generation capacity requirements, peak which data is available, the cost of line recent years, which has resulted in the load will eclipse existing generation losses totalled $220 million, according grid becoming quite constrained. You capacity (including retirements) within to Alberta Energy.12 In response, the can’t easily build a new power plant the next decade. The AESO estimates province has embarked on an extensive anywhere due to congestion. We need that 6,190 MW of new effective transmission expansion program. The another $20-$30 billion of generation generation capacity will be brought most notable transmission projects are so we need to get the transmission in online in Alberta by 2022 to meet this outlined in Figure 3: Announced Alberta place so that consumers can get power gap. By 2032, almost 13,000 MW of transmission projects. and generators can connect to the grid.” new effective capacity will need to be Evan Bahry, Executive Director at The province has decided to run a installed.11 the Independent Power Producers competitive process in selecting Society of Alberta (IPPSA) summarizes entities to construct and operate Generation and load growth the need for new transmission transmission lines. The competitive driving transmission development infrastructure. “Our bitumen is quite process introduces a new development needs remote, located up in Fort McMurray structure and has attracted the interest which is quite a long way north of of a number of non-incumbents. Load growth is also forcing the Calgary,” he said. “All of the pipelines The first project being tendered for development of new transmission across the province and the country competition is the Fort McMurray West capacity. No major new transmission require electricity transmission. Some 500 kV Transmission Project, which lines have been built in Alberta since $13-$15 billion will be invested in will transport electricity between the the 1980s, during which time the transmission assets in Alberta in the Edmonton and Fort McMurray regions. population has grown by over one next five to 10 years. We have built 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

Figure 3: Announced Alberta transmission projects

Expected/actual Project Description Bulk region Cost commencement date

Heartland 500 kV Double circuit 500 kV line from Ellerslie to a new Northeast $537 million 2013 (CTI) 500/240 kV substation near Fort Saskatchewan

West HVDC (CTI) HVDC 500 kV line connecting the Wabamun Edmonton $1,329 million 2014 area near Genesee with the Calgary area at Langdon

East HVDC (CTI) HVDC 500 kV line connecting the Northeast Edmonton $1,622 million 2014 area at Heartland with the South area near Brooks

Bickerdike - Little Double circuit 240 kV line from Bickerdike to Northwest $205 million 2015 Smoky Little Smoky

West Fort 500 kV AC line connecting Wabamun area Northwest $1,649 million 2017 McMurray near Genesee to the Northeast area near Fort McMurray

South area Multiple 240 kV double circuit lines from and South $2,287 million 2011-2017 transmission within the south to the Calgary area reinforcement

Foothills area 240/138 kV Foothills substation near High River, South $711 million 2014-2017 transmission two double circuit 240 kV lines from Foothills to development east and west Calgary, and several local 240 kV and 138 kV enhancements

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

the five consortia selected to enter the Projected installed capacity in Alberta in “The most obvious new capacity is request for qualification (RFQ) stage. 2022, the AESO estimates that natural large frame CCGT plants,” explained The winning bid will be announced in gas will account for 53% (11,036 MW) Etienne Snyman, Manager, Business December 2014. of Alberta’s generation mix by 2022 Development at ATCO Power. “This (including cogeneration), up from 39% is certainly what ATCO is currently Gas to meet capacity gap in the (5,359 MW) in 2012. Wind deployment pursuing. With Alberta being a short term is also expected to increase, but to large gas supplier it is difficult to a lesser extent. The AESO predicts justify anything else at this time. I All major generators believe combined that wind could account for 11% can’t really see coal being a major cycle natural gas will meet most of the (2,206 MW) of the energy mix by 2022, contributor in the next 20 years due growing demand requirement through almost doubling from 6% (865 MW) at to its cost and the environmental to 2020. As outlined in Figure 5: the beginning of 2012.13 implications.”

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

of existing infrastructure, transmission Figure 4: Installed capacity in Alberta in 2012 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 879MW Sundance coal complex on the south 314MW 5,359MW shore of Wabamun Lake. 6,242MW 865MW HYDRO OTHER Other players have a line up of gas-fired GAS WIND developments. “We have a site called COAL Saddle Brook Power that was permitted in 2008,” explained Geoff Murray, Vice President, Western Power Growth Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013) at TransCanada. “Every player in the market has one of these in the pipeline to replace coal retirements. Capital Natural gas is expected to plug the (refer to page 8, ‘Explaining Alberta’s Power has talked about the Capital majority of the capacity gap as its merchant power market’ for more Energy Centre. ATCO has up to 1,500 current low price is expected to information on how the province’s MW of combined cycle announced in continue for at least the next five years, power market operates). the Heartland area that they will build reinforcing natural gas-fired supply as in tranches and TransAlta has talked New gas fired generation is also the lowest cost new generation source about Sundance 7. This carries capacity expected to be preferred in the next (see Figure 6 on page 7). through to the turn of the decade.” five years as it is scaleable and not Given Alberta’s market based electricity geographically bound to the source The large build-out of gas-fired plants structure, the prevailing price of natural of the resource as with wind. This is already attracting the interest of gas directly sets hourly market prices flexibility will allow natural gas new market entrants in partnering and, in turn, the economics of operating facilities to locate at the sites of with incumbent Alberta-based owner/ existing plants and new generation retired coal plants to take advantage operators. In October 2012, TransAlta announced the formation of a new strategic partnership with MidAmerican Energy Holdings Company to develop Figure 5: Projected installed capacity in Alberta in 2022 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. 621MW 894MW Rob Schaefer, Corporate Development 11,036MW 5,906MW OTHER at TransAlta, explains the motivations HYDRO 2,206MW for this partnership: “Access to capital is not a significant hurdle, but what is COAL a bit more of a challenge is accepting GAS WIND merchant risk and how much risk you want to put into any one project. Partnering is an option when companies Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013) want to spread the risk, and this is what we have done with MidAmerican.”

Brian Vaasjo, CEO of Capital Power, also shared his thoughts on the new Figure 6: Forecast monthly natural gas prices players entering the Alberta market: (Intra-Alberta C$/GJ) “Coal plant retirements will result in very significant requirements for 4.0 additional generation. This will largely 3.5 be met through large combined cycle 3.0 natural gas plants. This may provide an opportunity for new entrants into 2.5 the market. There is a lot of talk 2.0 about new entrants to the market and C$/GJ 1.5 we are hearing of a lot of enquiries from generators such as the large 1.0 North American independent power 0.5 producers who want to enter the 0.0 FEB FEB FEB FEB FEB SEP SEP SEP SEP SEP JUL JUL JUL JUL JUL APR OCT DEC OCT DEC APR OCT DEC APR OCT DEC APR OCT DEC APR JAN JUN JUN JAN JUN JAN JUN JAN JUN JAN NOV NOV NOV NOV NOV AUG AUG AUG AUG AUG MAY MAY MAY MAY MAY MAR MAR MAR MAR Alberta market.” MAR 2011 2012 2013 2014 2015 Cogeneration will have Source: Gas Alberta Inc (Calgary, AB: 2013) a role to play While 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. //Cogeneration is attractive Rob Schaefer explains some of the opportunities and challenges as it can provide generation of cogeneration investments. “Cogeneration is attractive as it behind-the-fence so it can provide generation behind-the- fence so it avoids grid costs and avoids grid costs and is is also often more efficient than a combined cycle plant. Cogeneration has these advantages although it also often more efficient tends to be more expensive to build. One drawback to CCGT is that it than a combined cycle very rarely matches supply exactly. Oil sands facilities have a lot higher plant.// thermal than electric load, so getting the balance is hard. You can either Rob Schaefer build to meet the thermal load and Corporate Development take a lot of excess power to the grid. TransAlta Or you can build the electric load and put in boilers to meet the rest of the thermal demand.”

Explaining Alberta’s merchant power market

Unlike 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 transmission 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

150 15,000 Installed capacity (MW) 120 12,000

90 9,000

60 6,000

30 3,000

Average pool price (C$ per MWh) Average 0 0

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Off-peak average pool price On-peak average pool price

Average hourly pool price Installed capacity

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

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 capacity market, 700-1,000 MW of business case for new wind wind coming online at the same time generation causes the price to decrease. Most of Alberta’s wind farms are located in While Alberta has some of Canada’s south-western Alberta so wind capacity best wind resources and as such can can go from 200 MW to 800 MW deliver strong technical project funda- rather quickly. Just a few years ago this mentals, the majority of stakeholders discount was in the 20%-30% range. interviewed for this report believe that The discount is now pushing 50% the current low gas price environment and as more wind comes online this limits the economic viability of new discount will get worse. This is difficult wind projects. Natural gas prices in for the wind generators, although it Alberta are not forecast to increase sub- does show how more wind can push stantially in the foreseeable future. down energy costs.” As Mary Hemmingsen, Partner and Another major obstacle for wind energy National Power and Utilities Sector Lead in Alberta is the lack of transmission at KPMG LLP, explains, wind projects capacity in the grid. With some are further challenged as they receive 1,117 MW of wind concentrated around a discount to the average market price. a limited number of locations, the //The reality of “Wind production, being intermittent capacity of the system to carry more and not dispatchable, floods the market wind is currently limited. However, as with supply and depresses the price mentioned earlier, Alberta is currently the situation is at the time wind is able to generate. undertaking a significant transmission So realized prices for wind production expansion program, which should that jurisdictions are considerably less than the average alleviate some of these constraints. market price. This circumstance is “The reality of the situation is that have system exacerbated by the concentration jurisdictions have system capacity of wind farms in the southwest (of restrictions associated with renewable capacity restrictions Alberta) where there is a superior energy that is intermittent,” explained wind resource that generally results in Brian Vaasjo. “You can only have so associated with a significant volume of wind capacity much wind in the system and Alberta coming online simultaneously.” already has a lot. We are getting pretty close to the technical limits of that. This renewable energy Rob Roberti, Senior Vice President doesn’t mean that more can’t be built, of Power Generation at Capstone but the cost from a system perspective Infrastructure Corp, believes that this that is intermittent.// goes up pretty dramatically.” discount is increasing. “In 2013, the Brian Vaasjo wind discount to the average power However, gas prices may rise over time President & CEO pool price was 46%,” he said. “Wind to allow wind to become competitive Capital Power Corporation does not always generate when power by the end of the decade. “There will prices are high. In a 10,000-12,000 MW be smaller renewable energy projects

around biomass and other technologies,” its regulations to cap the number of //With continued explained Brian Vaasjo. “But in terms of RECs that can go to regions outside larger scale projects, I don’t really see California.” technology it happening until power prices go up. In the next few years power prices are Carbon offsets drive wind innovation to reduce expected to remain relatively low. When investment prices go up, grid parity with renewables will become reality if technology can Wind energy projects in Alberta have renewable supply continue to become more efficient and been driven by the need to offset capital costs go down.” carbon emissions. In 2007, the Alberta costs, supportive government introduced the Specified carbon policies and Extra market support for wind Gas Emitters Regulation, which sets projects no longer available gas intensity limits for large emitters of greenhouse gases in the province. demand pushing Despite the current unfavourable The regulation states that large emit- economics of wind energy, two ters must reduce emissions intensity market prices, large projects moved forward in by 12% from an average baseline year the past 12 months. In December after nine years of operation. 2012, the 150 MW Halkirk wind wind and other Should an emitter not meet these farm sponsored by Capital Power targets, it must comply by either paying commenced commercial operations. $15 per tonne into the Climate Change renewables can have Six months later construction of the and Emissions Management Fund for 300 MW Blackspring Ridge wind farm every tonne that exceeds the reduction a prominent role commenced following its acquisition target, or by purchasing emission by EDF EN Canada and Enbridge. This offsets generated from Alberta-based in Alberta’s future project will surpass Halkirk as Alberta’s projects that are not subject to the largest wind farm when it comes online regulation, including wind farms. A in the summer of 2014. supply mix.// third option is to purchase Emissions Both projects managed to secure Performance Credits from a different Mary Hemmingsen 20-year agreements for RECs from Alberta facility that has exceeded its Partner and National Power & Utilities Californian utility Pacific Gas and emissions reduction target. Sector Leader Electric Company, which made the This regulation led to a number of large KPMG LLP projects economically viable. The oil and gas companies with significant REC purchase provides the projects emissions investing in wind farms with an additional income stream to in order to obtain offsets for their the revenues received from selling emissions. For example, Canadian oil into the Alberta power pool at the and gas company Nexen, which is now spot market price. However, as Rob owned by Chinese energy company Roberti explains, the sale of RECs to CNOOC, invested in the 70.5 MW California is no longer an option for Soderglen wind farm that came online Alberta generators. “The bulk of the in 2006. Nexen owns 50% of the investment in wind has been two big project but 100% of the carbon credits, projects that benefitted from unique which can be used to help meet its financing circumstances in that they emissions reduction target. Energy sold RECs to the California market,” companies Suncor and Enbridge have he said. “We do not expect this to also built wind farms in Alberta in order happen again, making these projects to offset carbon emissions. a one-off. California has changed

New policy could redefine investment landscape

New emissions policy could emissions so it will likely increase its greenhouse gas emissions in 2011 revitalize wind emissions cost to those who emit. This while the oil, gas and mining sector creates an offset potential for wind. The accounted for 18%, according to Alberta An increase in carbon emissions province has signalled that they need Ministry of Environment and Sustainable targets and the carbon price is likely to to do more but they haven’t offered any Resource Development.15 Electricity bode well for renewables generation clarity yet. This will be important.” and heat generation companies account and drive large emitters to invest in for 20% of greenhouse emissions but Wind is also likely to become more wind energy projects for their offset are unlikely to invest in wind farms attractive from an offset perspective potential. The Alberta government is specifically for their offset potential. regardless of policy revisions. Some currently considering bolstering its This is because many power utilities large emitters have already adopted emissions regulation to build social are already reducing carbon emissions corporate policies that encourage license for its carbon-intensive oil sands by replacing aged coal-fired plants with carbon offsetting. For example, industry and multi-billion dollar pipeline cleaner CCGT plants. projects such as Keystone XL, which Enbridge has adopted a ‘Neutral will transport bitumen to the US. There Footprint’ commitment to generate a “When you look at the carbon footprint has been considerable speculation that kilowatt of renewable energy for every of Alberta, coal plant retirement that is the Alberta government will introduce kilowatt of conventional electricity that required by law will lead to a dramatic more aggressive benchmarks such as the company’s operations consume. reduction in carbon emissions,” confirmed Brian Vaasjo. “So from the a “40/40 target”, which will increase Oil and gas companies are most likely power generation side you are replacing the carbon emissions target for large to be compelled to invest in wind coal with natural gas. Replacing natural emitters from 12% to 40% and increase projects for their offset potential. As gas with wind is not that much of a step the carbon price from $15 per tonne depicted in Figure 8, the oil sands in reducing carbon emissions.” to $40 per tonne. However, it should industry accounted for 23% of Alberta’s be noted that the Alberta government has not clarified how it will change the current regulation. An increase in carbon emissions Figure 8: Alberta greenhouse gas emissions by sector targets and the carbon price is likely to National Inventory Report 2011 bode well for renewables generation Oil sands Residential/commercial and drive large emitters to invest in 4% wind energy projects for their offset 5% 6% 23% Electricity & heat Manufacturing/ potential. 1% generation construction 7% “Alberta has a significant emissions Oil, gas and mining Industrial process challenge with the oil sands 16% development,” explained Evan Bahry. 20% Transportation Waste “Next year Alberta is looking at redoing its Specified Gas Emitters Regulation. 18% Agriculture We were one of the first North American jurisdictions to put a price on Source: Alberta Ministry of Environment and Sustainable Resource Development, National Inventory Report carbon at $15 per tonne. The province (Edmonton, AB, 2011) recognizes that it needs to reduce its

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

New renewable energy framework could catalyze solar and wind Investment 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 resource

Solar is often left out of the debate One of the main challenges for when it comes to Alberta’s energy mix utility-scale solar projects in Alberta despite the province having the best is that the market price differentials solar resource in Canada. According for solar are not close relative to to CanSIA, Alberta’s solar resource is conventional resources. “On the utility 25% better than Ontario’s and 30% scale front, the market mechanism better than Germany’s, both of which does not provide for power purchase have seen signifi cant solar installation agreements,” explains John Gorman. driven by subsidies. In the absence “The government will have to come up of mechanisms to stimulate solar with a policy or program that addresses //Solar is development, Alberta has virtually no this as we move forward with replacing installed solar capacity at present. coal assets. We are discussing a strategy with the provincial government nearing grid or As is the case with wind energy, solar for both utility-scale and distributed PV could be more heavily deployed solar generation and there is certainly socket parity in the next fi ve years if, as is widely potential for both. We haven’t looked at anticipated, the government introduces how much solar PV could be installed in policy that puts more pressure on now, so will likely Alberta but our recommendation to the industry to reduce carbon emissions Ontario government is that solar could and, in turn, incentivizes investment be extremely account for 5% of electricity demand at in renewables. Solar may also prove any one time.” competitive in compelling due to its improving cost profi le and superior output profi le. As Ron Seftel, Senior Vice President, Operations at Bullfrog Power explains, “Solar could make sense for moments as little as fi ve the initial adopters of solar PV will be when wind output is generally municipal organizations. “As with all low on hot summer days when air or six years as renewable energy installations, these conditioning is ramping up,” explained are long term projects. From a fi nancial Rob Roberti. “Given the decrease conventional perspective, if you are in a position to in solar costs, solar is close to being consider the long term return, maybe at grid parity at these times of day. over 15 or 20 years, then solar is very electricity prices Southeast Alberta has some of the attractive. Solar is nearing grid or socket best solar resource in Canada. If parity now, so will likely be extremely are expected to you just look at the average price competitive in as little as fi ve or six years then solar is not at grid parity in as conventional electricity prices are rise in Alberta.// Alberta. That said, when you take into expected to rise in Alberta. Not everyone consideration that the average peak can take this long-term view but certainly Ron Seftel price is close to grid parity and that municipalities and school boards who Senior Vice President you are going to make the bulk of your know they are going to be around for 20 Bullfrog Power margin when the power price spikes years can, so they will likely be the initial to over $80 per MWh, solar might adopters of solar and will help to kick- make sense.” start the local industry.”

Bringing financing into Alberta’s merchant market – an issue of growing importance

Incumbent generators in Alberta are and as such get a long-term contract, arrangements of sorts. We are certainly sufficiently capitalized to fund their enabling project financing. It will open to solutions like this.” pipeline of CCGT projects earmarked to continue to be very hard for large One way to attract debt project replace retired coal capacity from 2017. stand-alone CCGT projects to secure financing is to introduce a degree of Major generators such as TransCanada project financing unless you can get contracting into the market structure. and ATCO both have large balance a contract over the transmission This would provide debt providers sheets. TransAlta has established system.” with the long term revenue certainty a partnership with MidAmerican to As John Vincent, Senior Managing needed to invest. How this could be share financing its pipeline of gas- Director, Head of Project Finance at incorporated into Alberta’s merchant fired generation projects, while Capital Sun Life Financial explains, some market structure is an outstanding Power has already structured financing debt providers have financed power issue. Nevertheless, this is something for its planned Shepard Energy Centre. projects in Alberta without an offtake that some of Alberta’s leading However there is a growing interest in contract, although these have typically generators believe should be given alternative financing mechanisms for been hydro projects. “We have done some consideration given the sizeable new market entrants to finance power merchant financing but the leverage need for new capacity. assets. has always been much lower than “It is important that government These new participants will be keen what you would get with a contractual think carefully about whether we to explore alternatives to balance cashflow. We have only done this need structural change post 2020,” sheet financing, including project debt for hydro projects that have very low explained Geoff Murray. “Deregulation financing and equity co-investment. operating costs so are always going was a long time in the making. If Alberta’s merchant market structure to be running. This desensitizes them we are going to reverse this or even and limited liquidity due to the to low power prices at certain times nibble around the edges we need islanded nature of the power market, of the day. There are some nuances time to really think about this. I don’t exacerbated by self supply, means that with hydro that are quite interesting in think there needs to be a wholesale project financing will prove challenging. that it can be peaked depending on the philosophical change but I do think situation to ensure you are producing “The lack of offtake agreements actions will need to be taken to move when power prices are the highest.” makes it very difficult to bring debt things along towards some sort of finance into contracts,” confirms “But providing debt financing into a mid to long-term contracting. This Etienne Snyman. “With PPAs, lenders wind farm or a CCGT plant will be could take the form of incentivizing or have some cash flow stability and a pretty hard in Alberta unless someone requiring contracting for some players. basis upon which they can lend to. is willing to protect against a downside This would enable low-cost capital on There are some creative mechanisms case, which could be in the form of the debt and equity side to be brought that can be used to secure debt a PPA or another vehicle,” continued into the market. Contracts also enable financing, particularly when it comes to Vincent. “Some organizations such as companies to invest the huge sums cogeneration. One of the mechanisms local utilities and cities are looking at over long periods of time that are would be to sell some of the power stepping in and making arrangements required to develop large baseload from cogeneration behind the fence to backstop a power purchase capacity.”

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

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

South Kent Wind Farm (270 MW) March 2013 Ontario Owners Pattern Energy Group LP / Samsung Debt Nord LB / Union Bank / Natixis / Societe Generale / Manulife Renewable Energy Inc. providers 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. / Debt Nord LB / Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ Samsung Renewable Energy Inc.. providers / 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 Scotia Capital Inc. providers Financing volume C$450 million Financing type Bond refinancing Tenor (years) 17.75 years Rate (%) 5.13%

Borealis Solar Portfolio (108 MW) December 2013 Advised by KPMG Ontario Owners Metropolitan Life Insurance Company / Debt Sun Life Assurance Company of Canada / National Bank Fiera Axium Infrastructure Inc. providers 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 Debt Manulife Financial Corp. / Caisse de dépôt et placement du Infrastructure Inc. providers Québec / KfW IPEX Bank Financing volume C$300 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D

Walpole, Belmont & Amherstburg Solar Plants (20 MW) August 2013 Ontario Owners Alterra Power Corp. / GE Energy Debt Manulife Financial Corp. / Sun Life Assurance Company Financial Services providers 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 Tenor (years) N/D Rate (%) N/D

Fort St. James Biomass Plant (33 MW) November 2013 British Columbia Owners Dalkia plc / Fengate Capital Debt Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / Canadian Management providers Imperial Bank of Commerce / National Bank of Canada Financing volume C$175 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D

FieStar Solar Portfolio (42 MW) June 2013 Ontario Owners Starwood Energy Group Global LLC / Debt Nord LB / Natixis / Bank of Tokyo-Mitsubishi UFJ Fiera Axium Infrastructure Inc. providers Financing volume C$175 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D

Seigneurie de Beaupre phase II Wind Farm (68 MW) October 2013 Québec Owners Gaz Metro LP / Valener Inc. Debt Sun Life Assurance Company of Canada / Industrial Alliance providers 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 Debt Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services LP providers Ltd. / Laurentian Bank of Canada Financing volume C$150 million Financing type Refinancing Tenor (years) N/D Rate (%) N/D

Gosfield Wind Farm (50.6 MW) March 2013 Ontario Owners Brookfield Renewable Energy Partners Debt Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services LP providers Ltd. / Laurentian Bank of Canada Financing volume C$130 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D Continued >

Walpole, Belmont & Amherstburg Solar Plants (20 MW) August 2013 White River - Gitchi Animki Hydro Plant (19 MW) August 2013 Ontario Ontario Owners Alterra Power Corp. / GE Energy Debt Manulife Financial Corp. / Sun Life Assurance Company Owners Regional Power / Pic Mobert First Debt Manulife Financial Corp. Financial Services providers of Canada / Canada Life Assurance Company / Caisse de Nation providers dépôt et placement du Québec / Great-West Life Assurance Financing volume C$126 million Financing type Construction and term loan Company Tenor (years) N/D Rate (%) N/D Financing volume C$200 million Financing type Acquisition finance Tenor (years) N/D Rate (%) N/D Glen Dhu Wind Farm (62.1 MW) July 2013 Nova Scotia Fort St. James Biomass Plant (33 MW) November 2013 Owners Glen Dhu Wind Energy LP Debt Stonebridge Financial Corp. British Columbia providers Owners Debt Dalkia plc / Fengate Capital Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / Canadian Financing volume C$115 million Financing type Refinancing Management providers Imperial Bank of Commerce / National Bank of Canada Tenor (years) 17.5 years Rate (%) 5.33% Financing volume C$175 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D CSI Solar Project 3 (30 MW) October 2013 Ontario FieStar Solar Portfolio (42 MW) June 2013 Owners Canadian Solar Inc. Debt Deutsche Bank AG Ontario providers Owners Starwood Energy Group Global LLC / Debt Nord LB / Natixis / Bank of Tokyo-Mitsubishi UFJ Financing volume C$105 million Financing type Construction loan Fiera Axium Infrastructure Inc. providers Tenor (years) 1.75 years Rate (%) N/D Financing volume C$175 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D Solar Portfolio (30 MW) October 2013 Ontario Seigneurie de Beaupre phase II Wind Farm (68 MW) October 2013 Québec Owners Canadian Solar Inc. Debt Deutsche Bank AG providers Owners Gaz Metro LP / Valener Inc. Debt Sun Life Assurance Company of Canada / Industrial Alliance providers Insurance and Financial Services Inc. / KfW IPEX Bank Financing volume C$104 million Financing type Construction loan Financing volume C$166 million Financing type Construction term loan, bridge financing, letter of credit facility Tenor (years) 1 year Rate (%) N/D Tenor (years) Construction + 19.5 years Rate (%) N/D Mackenzie Biomass Plant (36 MW) November 2013 British Columbia Essex County Solar Plant (51 MW) March 2013 Ontario Owners Conifex Timber Inc. Debt Canadian Imperial Bank of Commerce / Integrated Private providers Debt Corp. / Business Development Bank of Canada / Export Owners Brookfield Renewable Energy Partners Debt Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services Development Canada (EDC) LP providers Ltd. / Laurentian Bank of Canada Financing volume C$103 million Financing type Construction and term loan Financing volume C$150 million Financing type Refinancing Tenor (years) 6 years Rate (%) N/D Tenor (years) N/D Rate (%) N/D Source: Clean Energy Pipeline asset/project finance deal database Gosfield Wind Farm (50.6 MW) March 2013 Ontario Owners Brookfield Renewable Energy Partners Debt Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services LP providers Ltd. / Laurentian Bank of Canada Financing volume C$130 million Financing type Construction and term loan Tenor (years) N/D Rate (%) N/D

Global renewable energy project finance by region

60 60

50 50

Number of deals Rest of the world 40 40 Asia 30 30 North America

20 20 Europe

Deal value ($ billion) 4-Quarter moving average 10 10

0 0

1Q09 2Q09 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13

Source: Clean Energy Pipeline asset/project finance deal database

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

57% 46% 56% WIND WIND 46% SOLAR 31% 23% SOLAR WIND

12% 4% 10% SOLAR 8% BIOENERGY 3% 3% BIOENERGY BIOENERGY HYDRO OTHER OTHER OTHER 1% Source: Clean Energy Pipeline asset/project finance deal database

© 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

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

Mary Hemmingsen Trevor Hammond Partner Partner Advisory Services, National Sector Leader Audit Power and Utilities T: 403 691 7913 T: 416 777 8896 E: [email protected] E: [email protected]

Craig Walter Stephen Spooner Partner Partner GTA Energy Leader Advisory Infrastructure Advisory and Transaction Services T: 403 691 8403 T: 416 777 8342 E: [email protected] E: [email protected]

Georges Arbache Vice President Infrastructure Advisory Development M&A and Strategy T: 416 777 8170 E: [email protected]

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