Power & Utilities April 21, 2016 Industry Report - Changes

Transcription

1 Canada Research Published by Raymond James Ltd. April 21, 2016 Industry Report - Changes : 5 Ways to Play The Renewable Revolution With the specter of climate change, the renewable power sector has long been the beneficiary of supportive government policies geared towards reducing greenhouse gas emissions. While this continues to be the case (perhaps more so than ever), we believe the industry is also now approaching grid parity: the point where the cost of producing electricity from renewable energy sources becomes competitive with traditional fossil fuels. What s more, as evidenced by the unprecedented engagement of world leaders at the recent Paris Climate Conference, the political will behind mitigating climate change has never been greater. Therefore, we see the renewable-weighted independent power producers (IPP) in our coverage universe as at the threshold of a significant opportunity. Starting with stable, long-term contracted cash flows and sporting robust pipelines of attractive growth projects, we believe the IPPs discussed herein are poised to outperform as significant free cash flow growth fuels rising dividends. David Quezada CFA david.quezada@raymondjames.ca Analysis Boralex Inc. (BLX-TSX, Outperform, $20.00 target): With a high proportion of stable, contracted revenues, an attractive pipeline of growth projects, and robust expected free cash flow growth, we are initiating coverage of Boralex with an Outperform rating. We take a positive view of the company s significant presence and expected growth in France, an attractive region for the development of renewable power projects, and see rising free cash flow associated with these projects driving a dividend hike in 2017E. Capital Power Corp. (CPX-TSX, Market Perform, $18.00 target): While we hold a positive view of Capital Power s modern fleet of power assets, attractive dividend, and inexpensive relative valuation, we regard the potential risks posed by the Alberta Government s Climate Leadership Plan (a potential coal phase-out by 2030) and weak Alberta power prices as presenting sufficient uncertainty to prompt a neutral rating on the stock. We point to additional clarity on compensation for the early retirement of Capital Power s coal assets, as well as a potential improvement in Alberta power pricing as possible catalysts. Innergex Renewable Energy Inc. (INE-TSX, Strong Buy, $16.25 target): We highlight renewable pure play Innergex as our top pick among the IPPs discussed in this report. Our bullish stance is a product of the company s high quality, long-life, hydro-weighted asset base, robust expected free cash flow growth, and potential expansion in France where the company recently acquired a foothold. We also take a positive view of management s hydro development expertise, deal sourcing abilities, and track record of delivering projects on time and budget. Northland Power Inc. (NPI-TSX, Outperform, $25.00 target): We rate Northland Outperform due largely to strong growth associated with the company s 2 worldclass offshore wind projects: Gemini and Nordsee One. We see these 2 projects, each slated for commercial operations in 2017E, as transformational in shifting Northland s asset mix more toward renewable power while also driving significant EBITDA, free cash flow, and potential dividend growth between 2015A and 2018E. TransAlta Renewables Inc. (RNW-TSX, Outperform, $13.50 target): Our Outperform rating on TransAlta Renewables reflects good growth visibility via drop-down transactions from sponsor TransAlta Corp., and the company s highly diversified, long-term contracted asset base and good positioning for participation in a large expected renewable power procurement in Alberta. We also highlight the company s attractive 7.0% dividend yield, with potential upside in 2017E. Please read domestic and foreign disclosure/risk information beginning on page 106 and Analyst Certification on page 105.

2 Canada Research Page 2 of 115 Company Ticker(s) Current Target Price Dividend Total Return Suitability Rating Primary Secondary Price (6-12 months) Yield To Target Boralex, Inc. BLX-TSX $16.17 $ % 27% M/INC OP2 Capital Power Corporation CPX-TSX $17.87 $ % 9% M/GRW MP3 Innergex Renewable Energy, Inc. INE-TSX $13.60 $ % 24% M/GRW SB1 Northland Power Inc. NPI-TSX $21.00 $ % 24% M/GRW OP2 TransAlta Renewables Inc. RNW-TSX $12.52 $ % 15% M/GRW OP2 Note: M/INC - Medium Risk/Income, M/GRW - Medium Risk/Growth, H/GRW - High Risk/Growth, H/INC - High Risk/Income, H/SPEC - High Risk/Speculation; SB1 - Strong Buy, OP2 - Outperform, MP3 - Market Perform, UP4 - Underperform, UR - Under Review, R - Restricted. Raymond James Ltd.

3 Canada Research Page 3 of 115 Table of Contents INDUSTRY OVERVIEW TSX-listed Independent Power Producers (IPPs) Ideally Positioned to Benefit from the Push toward Renewable Power... 4 Global Temperature Change... 4 Renewable Power Trends by Source... 5 Rapid Growth of Renewable Power and Elevated Expected Investment... 9 Government Support for Renewable Power Domestic Policies in Canada and the US Promote Renewable Energy Potential Impact of Persistently Low Oil & Gas Prices Impact of Rising Interest Rates on Independent Power Producers Joining the Grid Parity Party COMPANY REPORTS Boralex, Inc. (BLX-TSX) Capital Power Corporation (CPX-TSX) Innergex Renewable Energy, Inc. (INE-TSX) Northland Power Inc. (NPI-TSX) TransAlta Renewables Inc. (RNW-TSX)... 88

4 Canada Research Page 4 of 115 Industry Overview TSX-listed Independent Power Producers (IPPs) Ideally Positioned to Benefit from the Push toward Renewable Power Punching above their weight From a global perspective, we believe the Canadian independent power producers are among the largest, best capitalized companies currently operating in the renewable power sector. We highlight that the scale, technological sophistication, and cost basis of projects being undertaken by these companies is world class positioning them to benefit from the global shift away from fossil fuels. As discussed throughout this report, we believe the overarching long-term trends impacting the global and North American power and utilities sector generally favour companies weighted towards renewable power. Importantly, as illustrated by the attendance at the recent climate change conference in Paris where 150 global Presidents or Primate Ministers attended (the largest ever such gathering of heads of state), climate change is now an accepted reality globally, with large scale efforts aimed at mitigating it now underway. Accordingly, the political will and supportive policies towards the development of renewable power represent a durable investment theme, in our view. Meanwhile, significant reductions in the cost of electricity generated by renewables (most notably solar photovoltaic (PV), onshore wind, and hydro) mean the industry has reached a juncture where political will (and corresponding policies) are supportive, while its various technologies are simultaneously reaching competitive economic footing. We believe this scenario brings renewable power producers into uncharted territory and gives rise to the potential for significant expansion for the foreseeable future. Furthermore, we see this favourable outlook, and what are generally robust forecast growth plans, as counteracting the risk to the sector of rising interest rates. Accordingly, we highlight key industry trends as follows: Climate change and the need to dramatically reduce greenhouse gas (GHG) emissions; The global proliferation of renewable power over the past decade; Going forward, the broad-based political will behind implementing policies that will limit climate change and carbon emissions which are promoting continued rapid expansion and investment in renewable power; The potential for low current fossil fuel prices to inhibit the motivation for the expansion of renewable power (we do not believe it will); The continuing material reduction in the cost of certain renewable energy sources; The decline of coal based power production; and The need for a long-term solution in energy storage to compensate for the variability of renewable power sources. Global Temperature Change Global political will behind limiting GHG emissions is greater than ever Now largely accepted among the scientific community, we note a 2014 study by the Intergovernmental Panel on Climate Change (IPCC) reported that scientists are now 95% certain that global warming is due to greenhouse gas emissions stemming from anthropogenic (human) activities. Quantifying this impact, Exhibit 1 illustrates how annual average temperatures worldwide have changed since Compiled by the Environmental Protection Agency (EPA), this data set uses the average as a baseline for depicting change (using a different baseline period would not change the shape of the data over time). Of note, since 1901 the average global temperature has increased at an average of 0.15 F per decade and, since 1970, the warming trend has accelerated to a rate of 0.26 F to 0.43 F per decade. In addition, 2015 was the warmest year on record and was the warmest decade on record. Looking forward, climate models used by the IPCC suggest that over the 21st century the global temperature is expected to rise 0.3 C to 1.7 C (0.5 F to 3.1 F) for their most optimistic (lowest emissions) scenario (which assumes stringent mitigation) and 2.6 C to 4.8 C (4.7 F to 8.6 F) for their worst case scenario. Differing from region to region, the anticipated effects of global warning include: rising sea levels, changing precipitation, the

5 Temperature Anomaly F Canada Research Page 5 of 115 expansion of deserts, the retreat of glaciers, more frequent extreme weather events, threats to food security, and the extinction of certain species. As we illustrate in the following section, concerns over this global change are now driving governments across the world to implement policies aimed at mitigating this issue. Exhibit 1: Global Climate Change Anomaly Earth's Surface Temperature (land and ocean) Linear (Earth's Surface Temperature (land and ocean)) Source: EPA, National Oceanic and Atmospheric Administration (NOAA) Renewable Power Trends by Source According to data from the International Energy Agency (IEA), renewable power represented 22% of global electricity generation in 2013 (the most recent year data is available), of which hydroelectric represented the largest component at 16% (or 3,879 TWh (terawatt hours)) followed by wind at ~3% (632 TWh) and solar at 1% (139 TWh) (see Exhibit 2). Looking to 2040, this is expected to change materially as wind grows to 9% of total global electricity generation, solar PV grows to 4%, and hydro (while growing in absolute terms) holds constant at 16%. Over this period renewables are estimated to grow from a combined 22% of electrical generation to 34% in 2040, offsetting the declining proportion of coal and oil electrical generation in the global mix. As global demand for electricity is expected to grow, we note the increased share of generation noted above equates to a 10-fold increase in solar PV generation (on a base of 177 GW total capacity) and a 5-fold increase in wind generation (on a base of 370 GW capacity) while hydro (+63%) and gas fired generation (+77%) also see large increases. We detail each of these power sources below.

6 GW Canada Research Page 6 of 115 Exhibit 2: World Electricity Generation by Source (2013 vs. 2040E) World Electricity Generation by Source World Electricity Generation by Source Other Renewables 2% Gas 22% Wind Solar PV 3% 1% Hydro 16% Nuclear 11% Gas 23% Other Renewables 5% Wind 9% Solar PV 4% Hydro 16% Coal 41% Oil 4% Coal 30% Oil 1% Nuclear 12% Source: International Energy Agency Wind Globally, wind power saw near-record capacity additions in 2014 at 48 GW, up 40% y/y and just below 2012 s record levels, according to the IEA (see Exhibit 3). China (20 GW), the EU (12 GW), and the US (5 GW) led the way making up over 75% of new capacity, while Brazil and South Africa are also increasingly utilizing wind power. As detailed later on in this report, the cost of wind power continues to decline materially thanks to advances in turbine technology and higher hub heights, which add little to total capital costs. In Europe, offshore wind projects have seen strong growth while still relying on government policies for financial support. In the US, it is widely expected that the recent renewal of production tax credits for renewable energy will result in continued strong investment in wind energy projects. Exhibit 3: Global Wind Power Capacity Wind Power Global Capacity Source: Renewable Energy Policy Network for the 21st Century (REN21) Wind power now mainstream in North America As per the Canadian Wind Energy Association (CanWEA), 2015 was another strong year for wind energy installations in Canada with 36 projects totaling just over 1,500 MW, representing approximately C$3 bln in total investments. This made Canada the 6 th leading country globally for wind capacity additions and brought total national wind capacity to over 11,000 MW. Representing roughly 5% of the country s total electricity demand, Canadian wind energy capacity has grown by an average of 23% over the past 5 years, making it the largest source of new electricity in the country. A recent round of wind project contracts awarded in Ontario, which featured an average price of 8.59 cents/kwh compared to past wind projects at 13 cents/kwh, are representative of the significant cost reductions for wind power generation. In the US, recent data from the American Wind Energy Association (AWEA)

7 GW Canada Research Page 7 of 115 indicates the US wind industry built just over 5,000 MW of new capacity in 4Q15, the second highest quarterly total ever while full year wind installations of 8,598 MW represented a 77% increase over 2014 s 4,854 MW. Now at 74.5 GW in total national capacity, cumulative US wind capacity has grown at a CAGR of 21% over the past 10 years. The cost of wind power has declined a considerable 66% since 2008, according to the AWEA, which, when combined with the extension of the industry Production Tax Credit (PTC) detailed below, augurs well for continued growth, in our view. Looking forward there is approximately 9,400 MW in the US construction pipeline and another 4,900 MW in advanced stages of development. Solar Solar photovoltaic (PV) energy has emerged over the past 10 years, rising from minimal levels to 40 GW added in Among all renewable energy sources solar PV has seen the greatest strides in cost reductions with the cost of solar panels, system design, installation labour, margins for installers, and customer acquisition each trending downward. A recent report from the Solar Energy Industries Association (SEIA) indicates that over the first 9 months of 2015, some 30% of all new electric energy coming online came from solar. What s more, we note the industry pipeline for solar power projects in the US currently stands at 18.7 GW, which represents a greater amount than the total cumulative solar PV capacity additions in the US up to GTM research estimates 2015 solar PV installations at 7.4 GW, which equates to a y/y increase of ~20%. Looking to 4Q15 specifically, SEIA expects a record 3 GW of installations, while 2016 is expected to see the 30% federal investment tax credit drive more than 15 GW of solar PV capacity essentially doubling installed capacity between 4Q15 and 4Q16 to over 40 GW (see Exhibit 4). While the recent extension of the solar ITC may result in these projects assuming a more measured build-out, we believe supportive government policies will drive unprecedented levels of industry investment in the years to come. Canada also supportive of increased solar PV capacity In Canada, solar energy has increased in prominence in recent years, most notably in Ontario. As per data from the Ontario Independent Electricity System Operator (IESO), at the end of 3Q14 there was 1,235 MW of solar PV capacity in commercial operation and a further 939 MW of capacity under development. In addition, the Ontario government has announced intentions to support the solar energy industry and is planning new procurement in coming years. Importantly, a recent round of solar project contracts awarded in Ontario featured an average price of cents/kwh, which compares to past large solar projects at 40 cents/kwh, and is representative of the significant cost reductions for solar power generation. Exhibit 4: Global Solar PV Capacity (LHS), US Cumulative Installed Solar PV Capacity with Forecast (RHS) Source: REN21 (LHS), SEIA (RHS), Raymond James Ltd Hydroelectric Hydroelectric power has long boasted the lowest cost among renewable energy sources, spurring global development which began in the US and EU (in the 70s and 80s), followed by significant expansion in Latin America (from ), before China took the lead in 2014 with 300 GW of installed capacity. Other benefits of hydro assets include long asset lives and zero GHG emissions. However, unlike wind and solar power, hydro power faces challenges in the form of environmental concerns and social issues, as well as challenges associated with transmitting hydroelectric power over long distances which limits its growth in certain regions. Nevertheless, the IEA expects rapid expansion of hydro power to continue globally, led by China with an additional 200 GW installed by 2040 and Latin America a further 100 GW, with environmental Solar PV Global Capacity

8 Canada Research Page 8 of 115 concerns driving a shift from reservoir type technologies to run of river. While only moderate hydro increases are expected in the US, in Canada hydro is more prevalent, with several largescale hydro projects coming online. In the EU, much of the potential hydro power sites have already been developed, limiting the potential for expansion in the region. As it relates to the companies in our coverage universe (Innergex, most notably), we believe the environment for hydroelectric development in Canada is supportive. Hydrological resources are plentiful in Canada, with several provinces generating the majority of their electricity needs from this source. Installed hydroelectric capacity in Canada is 77.6 GW, which equates to 63% of the country s electricity generation and makes it the third largest hydroelectric energy producer in the world. This compares to the Canadian Hydropower Association s estimates of an undeveloped, technically feasible potential at 163 GW (see Exhibit 5). As such, we see a lengthy runway of potential hydro projects in Canada. We also note as part of the Renewable Energy Standards in the US, hydro is listed as an allowed technology in 37 states. Despite its advantages, hydroelectric power often faces a greater degree of opposition from environmentalists and First Nations groups. The opposition is generally based on the negative environmental impact of damming rivers which is necessary for both large scale hydroelectric dams and run of river hydro projects (albeit on a smaller scale). Most recently, the $1.5 bln Site C Hydroelectric dam project in the Peace River, BC (which includes a one km long earth-filled dam and 83 km long reservoir) has met significant opposition from several first nations groups on largely environmental grounds. As a result of this type of opposition, many hydro projects are developed in partnership with first nations groups where project costs and revenues are shared. In fact, a recent round of renewable energy procurements by Ontario s Independent Electricity Services Operator which included wind solar and hydroelectric projects saw indigenous communities included in 13 of 16 contracts. Accordingly, we believe effective first nations relationships are a key competitive advantage for some renewable power producers, providing access to hydro and other renewable power projects. Exhibit 5: Canada Hydro Capacity and Potential (MW) Source: Canadian Hydropower Association Coal In stark contrast to robust expansion in renewables, coal demand growth has entered an era of structurally declining demand growth. Coal has been pressured in recent years not only from moderating growth in the global iron and steel industry, but also from GHG emission reduction targets and government-mandated coal capacity retirements. Importantly, with global electricity consumption expected to grow at a modest 0.8% annually through to 2040 (as per the

9 US$ blns Canada Research Page 9 of 115 IEA) the expansion of renewable power (and natural gas for that matter) necessitates the retirement of coal, particularly within North America. Under the IEA s base case scenario, coal demand will see growth from the power sector in non-oecd countries, offsetting declining demand from OECD countries. Despite this outlook, coal is expected to maintain an important role in global power generation at 30% of worldwide electricity output by The IEA also expects global trade patterns to shift, with Chinese imports declining significantly while India consumes a greater proportion of the commodity globally. While investment in coal will continue in order to maintain existing output, the aforementioned government carbon emission policies will clearly have a negative impact on demand. The IEA s base scenario of coal demand from OECD nations declines to 1,042 Mtce in 2040, from 1,361 Mtce in 2013, partially offset by increased production in non-oecd nations over this period. Natural Gas Natural gas is expected to post the strongest growth among the fossil fuels, with the IEA forecasting a 1.4% annual growth rate through to 2030, by which time it is expected to approach coal and oil in its share of global energy demand. Increased output from North America, Australia, Africa, Latin America and eventually Russia is expected to meet this growing demand. Given more than adequate supply, North American usage of natural gas is also expected to grow. However, there also remains the potential for a persistent low price environment to result in deferred investment in natural gas production, potentially curbing supply longer term. Nevertheless, US production of natural gas has grown significantly of late, rising 6% in 2014 to 730 bcm and a further ~8% y/y for the first half of Meanwhile, in China, where demand has grown by an average of 15% y/y from , demand slowed in 2014 to below 10% due to moderating economic growth and the rapid rise of renewable power sources. Rapid Growth of Renewable Power and Elevated Expected Investment Renewables hit the mainstream; will dominate investment in power generation for the foreseeable future Indicative of the global shift, renewable energy has represented 36% of new power generation capacity, 16% of incremental demand for road transport, and 21% of incremental demand for heat globally over the past decade. Playing an increasingly central role, wind power and more recently solar PV power sources have seen a rapid expansion in recent years, something we expect will continue going forward. According to data from the IEA, as of 2014 renewable energy was the second largest source of electricity globally, after coal, and accounted for 85% of the total increase in generation capacity over the year. Spurred by supportive government policies, a record 130 GW of renewable energy was added in 2014 (US$270 bln in investment see Exhibit 6). More recently, a study by Bloomberg New Energy Finance found that global investment in clean energy totaled US$329 bln in 2015, suggesting continued robust growth despite a weak fossil fuel pricing environment. In the US, 16 GW of renewable power capacity was installed, including 8.5 GW of wind power and 7.3 GW of solar, which represented 68% of all energy capacity additions in Reflecting the significant global push for increased deployment of renewable energy, the IEA expects 3,600 GW of capacity to be added by 2040, representing US$7 trillion in total investment (an average of US$270 bln/year). Exhibit 6: Global Investment in Renewable Power Capacity (LHS) and Global New Investment in Renewable Energy by Technology (RHS), Solar Wind Global Investment in Renewable Power Capacity Biomass & Waste to Energy Biofuels Small Hydro <50MW Ocean Energy Geothermal Power US$ blns Developed Countries Developing Countries Source: REN21, Raymond James Ltd.

10 Canada Research Page 10 of 115 Government Support for Renewable Power Government support for renewable power is at unprecedented levels Government support for renewable power comes via a myriad of policies in the form of grants, fixed remuneration (feed-in tariffs or premiums), tax rebates, dedicated auctions, green certificates, and long-term fixed price contracts. As detailed below, we believe the political will behind reducing GHG emissions has never been greater and view government support for renewable energy as a durable, long-term trend. Paris France Agreement UN Climate Change Conference (COP21) Between November 30, 2015 and December 12, 2015 the 21 st session of the Conference of the Parties to the United Nations Framework Convention on Climate Change (known as COP21), was held in Paris, France. In what we regard as being illustrative of the unprecedented global political will behind this initiative, the conference was attended by 150 Presidents and Prime Ministers, the largest ever gathering of heads of state. The landmark agreement reached at COP21 provides a global framework for reducing carbon emissions and has an overall goal of limiting the global temperature increase to below 2 C (above pre-industrial levels). The product of a four year round of negotiating, the treaty reached at COP21 featured a commitment from all countries to establish nationally determined contributions (NDCs) to reducing carbon emissions with corresponding domestic policies aimed at achieving them. In addition, the agreement includes a requirement that all parties report regularly on emission and implementation efforts for international review the first time an accountability measure of this nature has been introduced. Developed countries will bear obligations to support the efforts of developing nations and developing nations are encouraged to undertake voluntary contributions. While certainly an important milestone in combating global climate change, in order for the Paris Agreement to come into force it requires ratification by 55 countries representing 55% of global emissions. Meanwhile, although the agreement features a binding procedural commitment to prepare, communicate, and maintain an NDC and pursue domestic measures to achieve it, the achievement of the NDCs is not legally binding for participating countries. As it currently stands, NDCs have been submitted by over 180 countries representing 90% of global carbon emissions (key national targets are detailed in Exhibit 7 below). While this degree of participation is encouraging, an October 2015 study by the ESRC Centre for Climate Change Economics and Policy conducted by Boyd, Turner and Ward, found that forecasted reductions in greenhouse gas emissions driven by the NDCs fall well short of levels required to prevent global climate change beyond 2 C by In fact, the study found that of NDCs submitted to that point (from 154 countries representing 85% of global emissions in 2012) only the more optimistic scenarios considered would put global emissions on a path for a greater than 50% chance of limiting climate temperate increases to 2 C. Nevertheless, this would represent progress relative to the business as usual scenario. We believe the key takeaway here is that, if anything, GHG reduction goals and policies will become more ambitious over time, bolstering our view of government support for renewable power continuing for the foreseeable future.

11 Canada Research Page 11 of 115 Exhibit 7: Global National Renewable Power/Energy Goals Region Policy Type Target US Volume target 36 bln gallons of renewable fuels by 2022 Sector share 30 state and district level renewable portfolio standards System target Reduce power emissions by 32% from 2005 levels by 2030 European Union System target 20% renewable energy in gross final consumption by 2020 China India 27% renewable energy in gross final consumption by 2030 Sector share 10% of transport energy from renewable sources by 2020 Capacity target System target 15% non-fossil fuel share of total energy supply by 2020 Capacity target South Africa Volume target 1 mln solar water heaters by % non-fossil fuel share of total energy supply by GW of solar PV, 60 GW of wind power, 10 GW of bio-energy, 5 GW of small hydro by 2022 Capacity target 17.8 GW of new renewables capacity by 2030 Brazil Sector share 27% biofuels blending mandate 350 GW of hydro plus 70 GW of pumped storage, 200 GW of wind power, 100 GW of solar PV, 30 GW of bioenergy by 2020 Korea System target 11% of primary energy from renewables by 2035 Australia Generation target 33 TWh of power from large-scale renewable plants by 2020 Mexico Sector share Less than 65% of fossil fuels in power generation by 2024 Less than 60% of fossil fuels in power generation by 2035 Less than 50% of fossil fuels in power generation by 2050 Southeast Asia System target (Indonesia) 23% of primary energy from renewable sources by % of primary energy from renewable sources by 2050 Sector share (Thailand) 20% of power generation and 20% of transport fuel use from renewables by 2036 Sector share (Malaysia) 2,080 MW of renewables capacity by ,000 MW of renewables capacity by 2030 Notes: Policies setting a minimum of non-fossil fuel share of energy supply (or a maximum fossil-fuel share) may also drive the deployment of nuclear power. Japan has support measures for renewables, particularly solar PV, but no specific targets CSP = Concentrating solar power MW = Megawatts Source: International Energy Agency, Raymond James Ltd. Domestic Policies in Canada and the US Promote Renewable Energy Alberta Climate Leadership Plan most significant of recent Canadian provincial initiatives In Canada, while some federal level policies aimed at reducing GHG emissions do exist, the driving force behind renewable power has come in the form of fixed price contracts at the provincial level, where provincial utilities such as BC Hydro and Hydro Quebec provide long-term power purchase agreements. Foremost among the federal level policies is the Canadian Capital Stock Turnover regulations, which mandate the retirement of coal-fired power plants at the end of 50 years. The impact of this is expected to be felt most significantly in Alberta, where 17% of carbon emissions come from coal-fired power. Provincially, the Alberta NDP government, as part of their Climate Leadership Plan (CLP), have announced a target of completely phasing out coal as a source of power generation by Significantly more onerous than the existing federal requirements, this plan could result in the early retirement of numerous coal-fired power plants and shortened life for roughly 40% of the province s coal capacity. The Alberta government has indicated a process to determine an appropriate method of providing compensation is underway and appears committed to not stranding capital via forced retirements. To this end, a negotiator (Terry Boston, former CEO of US power giant PJM Interconnection) has been named to negotiate a settlement between the Alberta government and the coal power producers an important milestone in reaching clarity on the potential compensation for companies with coal-fired power capacity. Meanwhile, the Alberta CLP also provides for renewables to replace 2/3 of the retired coal capacity and represent 30% of electrical generation by 2030, which implies a three-fold increase from current levels. As a result, we expect Alberta will be a key growth region for several of the IPPs in our coverage universe. Other Canadian provinces also have renewable power goals Elsewhere in Canada, Saskatchewan s power company, SaskPower, has announced plans to double the percentage of electrical renewable energy used in the province within 15 years (to 50% of total) while reducing greenhouse gas emissions by 40% (relative to 2005 levels). The province plans to reach these

12 Canada Research Page 12 of 115 goals via a major expansion of wind power, as well as solar and other renewable technologies to a lesser degree. In Nova Scotia, the provincial government recently announced 26.6% of power generation came from renewables in 2015, surpassing the province s goal of 25% and making strong progress towards a goal of 40% renewables by In other Canadian provinces, power generation is already dominated by renewable sources, mostly in the form of hydropower which represents over 90% of power generated in Manitoba, British Columbia, Newfoundland, Labrador, the Yukon and Quebec while Ontario is 40% hydro and 60% nuclear. Nevertheless, these provinces also have ambitious targets for renewable power, including British Columbia (93% of total electricity from clean or renewable resources), Ontario (increase hydro energy capacity to 9,300 MW and develop 10,700 MW of wind, solar and bioenergy installed capacity by 2021) and Quebec (develop 4,000 MW of wind energy capacity by 2015 and an additional 100 MW of wind energy for every 1,000 MW of additional hydroelectric power). Overall, we believe the regulatory environment will continue to favour renewable power while presenting a headwind to coal power producers. Carbon Tax, Cap and Trade Systems to be Initiated in Canada As part of a December 2015 announcement, the province of Ontario is moving forward on a carbon cap and trade program to limit GHG emissions, in partnership with Quebec, Manitoba and California. Expected to come into effect on January 1, 2017, with a first auction for emission allowances in March 2017, the program will create limited tradable allowances in the carbon market. The goal of this system is to reduce GHG emissions by 15% below 1990 levels by the year Proceeds from this program would be deposited in a Greenhouse Gas Reduction Account which would in turn be invested in projects that reduce GHG emissions, such as public transit, clean-tech innovation for industry, electric vehicle incentives, and social housing retrofits. The proposed carbon price would equate to approximately $17/tonne, which compares to a $30/tonne carbon tax in British Columbia. The BC carbon tax initiated in 2008 at $10/tonne before rising $5/year to $30/tonne in 2012, which works out to approximately 7 cents per litre of gas. Widely regarded as highly effective, this tax resulted in a 16% reduction in the per person consumption of fuels in BC, while the remainder of the country saw a 3% increase. While perhaps it is too early to judge the potential benefits of these policies to the renewable power producers, we believe this trend merits monitoring. US Clean Power Plan First proposed by the Environmental Protection Agency (EPA) in June 2014, the US Clean Power Plan (CPP) was designed to promote clean energy production by setting state level standards for power plants and carbon reduction goals. The final version of the plan was introduced by US President Barack Obama in August 2015 and was the first of its kind to impose national limits on carbon pollution from power plants. The ultimate goal of the plan is to reduce carbon dioxide emissions by 32% relative to 2005 levels within a time period of 15 years, primarily by reducing dependence of coal-burning power plants and increasing the use of renewable energy while also promoting energy conservation. Hailed as President Obama s most ambitious climate policy to date, the EPA estimates the CPP will reduce pollutants contributing to smog and soot by 25% and it is expected to create 30% more renewable energy generation by Supported by investment and production tax credits for renewable power (detailed below), we see significant investment in renewables occurring in advance of the first set of state compliance deadlines under the CPP in While garnering support within the business community, the CPP has also generated some controversy, particularly at the state government level. In fact, 29 states have sued the EPA over the CPP claiming the EPA overstepped its legal authority and that the scope of the plan goes beyond some standards first imposed by the Clean Air Act. Currently in the US court of appeals, the legal outcome of this case is uncertain and most likely will be determined by the US Supreme Court. More recently, the US Supreme Court granted a stay, halting implementation of the CPP pending the resolution these legal challenges. As this stay will likely last towards the end of President Obama s term, it may now be decided by the next President of the US. While certainly a setback to this piece of legislation, with the recent renewal of tax credits for renewable power (detailed below) and the impetus coming from state level Renewable Portfolio Standards, we believe the expansion of renewable energy in the US will continue. Clean energy investment tax credits & production tax credits to spur investment in clean energy projects In December 2015, the US House and Senate agreed on extensions to the 30% investment tax credit (ITC) for solar energy and the 2.3 cent/kwh tax credit for wind power, at least through to Described by industry observers as the most significant stimulus policies for the renewable energy sector in the last 10 years, the wind production tax credits will remain at

13 Canada Research Page 13 of 115 full strength for 2016 with incremental reductions for before the expiry in 2020, while the ITCs for solar will continue at 30% for commercial and residential systems through to the end of 2019 then see annual reductions bringing the ITC to 10% in We believe the predictability of these policies will spur further advances in technology and cost reductions, as well as hundreds of billions of dollars in new renewable energy investments. In fact, projections from SEIA and partner GTM Research forecast approximately 72 GW of additional capacity between 2016 and 2020, bringing the country s total capacity to over 100 GW (3.5% of all electricity produced in the US) with investment in the sector rising by US$40 bln over this period. Similarly, the American Wind Energy Association noted they believe the PTC has helped facilitate a ~350% increase in US wind power since 2008 (from 16.7 GW to 74.5 GW in 2015) and expects the extension to provide the confidence to support new wind projects. Modified Accelerated Cost Recovery System Established in 1986, the Modified Accelerated Cost Recovery System (MACRS) is the current tax depreciation system in the US under which each asset is assigned a recovery period over which depreciation allowances are spread and which dictates how depreciation allowances are allocated. This system generally facilitates a more rapid write-off period than other systems such as straight line depreciation. As it relates to renewable energy, MACRS rules assign a 5-year useful life to most renewable energy assets (solar, wind, geothermal, etc.), which is among the shortest across asset classes. While the depreciation method essentially just alters the timing of tax payments, it does reduce the present value of tax expenses, thus increasing project IRRs. This enables developers of renewable energy assets to put more projects in service and enables those projects to deliver renewable energy at a lower cost to consumers. A study by the US partnership for Renewable Energy Finance estimates MACRS boosts project returns by roughly 30% (i.e. a 5.25% project return would be boosted to 7.0%). A similarly favourable depreciation system is in place in Canada. US Renewable Energy Standards (RES) Also known as a Renewable Portfolio Standards (RPS), RES are state-level requirements that utilities source a certain proportion of energy generated from renewable sources. These standards can vary significantly from state to state and in some cases include nuclear energy, or even relatively low-polluting non-renewable sources such as natural gas. Illustrating the RPS impact on US renewable power, we note a 2016 status report by the Lawrence Berkeley National Laboratory states renewable portfolio standards have contributed to more than half of all renewable power growth in the US since 2000 (see Exhibit 8, LHS). Meanwhile, RES are typically incremental targets that increase over time and will therefore continue to drive increasing demand for renewable power (see Exhibit 8, RHS). For example, in California RES were established in 2002 and feature progressively increasing targets for renewable energy over time, with the proportional requirement rising to 33% by 2020, 40% by 2024, 45% by 2027 and 50% by As of early 2016, 29 states have RES in place while a further 8 states have non-binding renewable energy goals. In most cases, states with RES in place have associated Renewable Energy Certificate (REC) trading programs whereby the amount of renewable energy being sold is tracked with the financial rewards going to the power producer (one REC is equivalent to 1 MWh of renewable electricity produced). Essentially, for each unit of renewable power produced a REC is issued which can then be sold along with the underlying power or separately to another energy supplier. By means of trading RECs, energy companies can purchase and then redeem RECs equal to their requirements under the RES in their state.

14 GW (Cumulative) Canada Research Page 14 of 115 Exhibit 8: US RPS Impact on Renewable Power Development Source: Lawrence Berkeley National Laboratory US Carbon Pollution Standards The US Environmental Protection Agency issued final rules for Carbon Pollution Standards in August These standards will apply to new, modified, and reconstructed power plants and place limits reflecting the degree of emission limitation achievable through the application of best system of emission reduction as determined by the EPA for each type of unit. Coal is being phased out in North America In the US, the retirement of an estimated 13 GW of coal-fired power generation was reported in 2015, driven by the EPA s Mercury & Air Toxic Standards (MATS). Implemented in April 2015, MATS requires large coal and oil fired electric generators to meet stricter emissions standards by incorporating emissions control technologies in existing facilities. These technologies include desulfurization equipment which cost in the hundreds of millions of dollars each, depending on the size of the power plant. This prompted some plant operators to retire units as opposed to implementing what, in some cases, would be costly retrofitting. The EPA has also written new carbon emissions rules aimed at reducing carbon emissions from future coal-fired power plants. In terms of generating capacity, the EIA expects 90 GW of coal capacity to be retired by the year 2040 due to the US Clean Power Plan, well above the reference case without CPP-related retirements (see Exhibit 9) with this amount front-loaded as an estimated 60 GW is expected to be retired between Meanwhile, in Canada the Capital Stock Turnover, which limits the life of coal-fired power plants to years, is also expected to result in retirements as plants reach the end of this life span. Exhibit 9: Projected US Electric Capacity Additions and Retirements E - 2 Scenarios Capacity Additions Capacity Retirements -200 Reference Case Clean Power Plan Base Policy Other Natural Gas Solar Wind Nuclear Natural Gas - Retirement Coal Source: Energy Information Administration

15 Canada Research Page 15 of 115 Potential Impact of Persistently Low Oil & Gas Prices We do not expect the low oil price environment to derail the push for renewable energy As discussed throughout this report, we believe the now widely acknowledged need to curb greenhouse gas emissions and the increasing cost-competitiveness of renewables like wind and solar will result in continued rapid expansion of renewable power sources, regardless of the oil and gas price environment. In fact, we note data from Bloomberg New Energy Finance (BNEF) indicated that, despite low pricing for fossil fuels, investment in the renewable energy sector totaled a record US$329 bln in 2015 which exceeded the prior record total in 2011 of US$318 bln. Furthermore, as detailed by BNEF, while 2015 investment in renewable power was up a modest 4% from 2014 s US$316 bln, the y/y growth in capacity was an impressive 30%, signaling a significant reduction in the cost of these technologies. Meanwhile, roughly half of the total new electricity generating capacity installed in 2015 came in the form of solar and wind, further cementing these two technologies in the mainstream of global power. A low oil price scenario, as forecasted by the IEA (which assumes a new oil price equilibrium at US$50-US$60/bbl range through to 2020), suggests that relative to their baseline scenario, would result in only 1 Mtoe (million tons of oil equivalent) less of renewable power by 2020 vs. the estimated Mtoe of primary energy demand expected to be comprised of renewables (see Exhibit 10). By 2030E and 2040E the reduced demand for renewables at 6 Mtoe and 12 Mtoe, respectively, is again minimal relative to the 585 Mtoe and 926 Mtoe of renewables expected to be in place by then. Under this scenario, the IEA assumes much of the increased demand for oil would come from transport as opposed to electricity generation. While natural gas prices are also low, the US Alternative Energy Group at accounting firm Deloitte recent noted solar and wind accounted for 60% of new generation capacity in the US, with this figure expected to grow to 70% for We also note commentary from the IEA suggests that the low current natural gas price environment has the potential to curb investment in the sector, leading to reduced supply in coming years. Exhibit 10: World Primary Energy Demand by Fuel - Low Oil & Gas Price Scenario Low Oil Price Scenario Chg. vs. Baseline Scenario All figures in Mtoe E 2030E 2040E 2020E 2030E 2040E Coal 2,343 3,929 3,986 4,117 4,248 (47) (102) (166) Oil 3,669 4,219 4,513 4,762 4, Gas 2,067 2,901 3,223 3,703 4, (81) Nuclear ,042 1, Hydro Bio-Energy 1,023 1,376 1,531 1,698 1,821 (10) (29) (56) Other Renewables (1) (6) (12) Total 10,063 13,559 14,782 16,373 17, (90) Source: International Energy Agency Impact of Rising Interest Rates on Independent Power Producers Historically a headwind, but something we expect to moderate going forward With reliable cash flows and what are generally stable dividend yields in the 4-7% range, there has been a historical relationship between power producer equities and fluctuations in interest rates, with fund flows into sector equities when rates are falling (bonds are less attractive) and the reverse when rates are rising. This is evident over the short- and long-term time frames (see Exhibit 11). Meanwhile, with generally elevated debt levels (average debt to cap of 50%-70%) power producers with a greater proportion of variable rate debt also feel a negative impact from increased interest rates, while IRRs on projects implemented in a low rate environment are more attractive (power projects tend to be capital intensive and financed over long periods with high loan to value ratios of 75%-80%). Thus, we believe the run of historically low rates has provided a significant lift to the equities in our coverage universe. Looking ahead, while it seems likely interest rates will rise both in Canada and the US at some point, we believe the impact to the companies in our coverage universe will be mitigated for several reasons. First, power plants typically have fixed rate project-level debt in place, thus rendering the potential for increased interest expenses modest. Moreover, we believe government support for renewable energy will result in increased rates reflected in power purchase agreement (PPA) pricing, thus insulating IRRs to a large degree (note: due to falling costs of production for renewable power, PPA pricing is

16 Feb-15 Mar-15 May-15 Jun-15 Aug-15 Sep-15 Oct-15 Dec-15 Jan-16 Mar-16 Index Level Index Level Jan-15 Mar-15 Mar-15 May-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 Feb-16 Mar-16 Jan-06 Jun-06 Nov-06 Apr-07 Aug-07 Jan-08 Jun-08 Oct-08 Mar-09 Aug-09 Dec-09 May-10 Oct-10 Mar-11 Jul-11 Dec-11 May-12 Sep-12 Feb-13 Jul-13 Nov-13 Apr-14 Sep-14 Feb-15 Jun-15 Nov-15 Index Level % Index Level % Canada Research Page 16 of 115 generally trending downward as the power prices necessary to incentivize these projects fall in concert. However, we expect IRRs will remain attractive and see PPA terms reflecting trends in both costs of production and interest rates). Lastly, and perhaps more importantly, each of the renewable power producers in our universe currently boasts an attractive growth pipeline of projects either under construction or at an advanced stage. Thus, while current contracted cash flows may represent a steady cash flow stream that could theoretically be devalued by higher interest rates, we believe robust forecasted free cash flow growth materially reduces this relationship. As such, we see potential for the IPPs discussed herein to see strong share price appreciation, even in a rising interest rate environment. Exhibit 11: TSX Renewable Power Index vs. Canadian 10-Year Bond Rate, 1 Year Chart (LHS) and 10 Year Chart (RHS) 110 Renewable Power Index Canada Government Debt - 10 Yr (RT Axis) Renewable Power Index Canada Government Debt - 10 Yr (RT Axis) Source: Capital IQ, Raymond James Ltd. Power producers as a safe haven While the amplitude of relative change is obviously much smaller, we note the index of TSX-listed renewable power producers tends to move opposite the CBOE volatility index (see Exhibit 12). In fact, the two indices have exhibited a negative correlation of greater than 65% over the past year. Thus, while rising rates depicted above may result in some multiple compression for sector equities (whether warranted or not), we believe the safe haven status of the sector provides an offset to this risk. Exhibit 12: TSX Renewable Power Index vs. CBOE Volatility Index Renewable Power Index CBOE Volatility S&P 500 Index Source: Capital IQ, Raymond James Ltd.

17 USD/MWh Canada Research Page 17 of 115 Joining the Grid Parity Party Levelized cost of renewable power approaching fossil fuels Historically, hydroelectric power has been the only renewable source of electricity comparable to fossil fuels in terms of cost. However, given significant reductions in the cost of installing and operating wind and solar power the IEA expects the fully competitive share of non-hydro renewables to double to one-third by Meanwhile, the IEA also expects government subsidies to continue despite these expected cost improvements, further supporting investment in the sector and reduced average costs. In comparing various types of power generation, the term Levelized Cost of Electricity (LCOE) is often used. This measure represents the net present value of the unit cost of electricity over the lifetime of a generating asset, or alternatively, the average price the generating asset must receive in a market to break even over its lifetime. We highlight data from the National Renewable Energy Laboratory (NREL) Open EI database which suggests that with an LCOE of US$40-US$80/MWh, onshore wind energy is already on par in terms of cost with conventional power sources such as coal and natural gas in some cases (see Exhibit 13). Solar s LCOE range is from US$60- US$250/MWh; however, a recent study by investment bank Lazard suggests this technology is closer to the low end of this range at US$50-US$70/MWh. While anecdotal, we also highlight a recent report from industry journal UtilityDIVE cites a recommendation from city council that the municipal utility in Palo Alto, CA enter into a 25 year contract to purchase power from a 26 MW solar PV system owned by Hecate Energy for $37/MWh. This would represent the lowest priced PPA in the US and we believe is representative of the potential of solar PV generation. In addition, data from the International Renewable Energy Agency indicates the cost of solar PV fell by half between 2010 and Going forward, we believe solar PV will be the source of increased focus as it appears poised to become the lowest cost source of electricity over time. Exhibit 13: Levelized Cost of Electricity by Source Solar PV Natural Gas Plants Coal Nuclear Wind - Onshore Wind - Offshore Biomass Hydro Source: The International Renewable Energy Agency (IRENA), Raymond James Ltd.

18 Coal NG Combined Cycle Nuclear Wind - Onshore Wind-Offshore Solar PV Solar CSP USD/MWh Canada Research Page 18 of 115 Exhibit 14: Projected LCOE by Source Technology % Change Y/y - RT Axis 10% 0% -10% -20% % -40% -50% -60% -70% 0-80% Source: International Energy Agency, Raymond James Ltd. Energy storage could be a long-term challenge for renewables Due to the intermittent nature of most renewable energy sources (solar, wind, hydro), the challenge is the ability to deliver electricity at key periods, such as in the night (when the sun doesn t shine), when the wind isn t blowing, or when seasonal reductions in water flow impact the availability of hydro power. A recent report by consulting group Frost and Sullivan predicted dynamic growth for the battery storage industry, with commercialization accelerating after 2017 and utility scale grid-connected battery storage reaching 12 GW by 2024, from 430 MW currently. Frost and Sullivan predict lithium-ion technology will continue to dominate. While advantages include distributed, variable renewable energy firming and energy time shift, there are significant hurdles to the wide spread adoption of battery storage, including: high costs, lack of a clear business case, low technology maturity, and inadequate incentives, targets and supporting policies. Another report from GTM Research highlights that while technological advances in batteries are expected to represent a potential short-term solution, questions exist as to whether battery storage at the scale required once renewable energy sources continue to grow in advanced economies will be too great, as will the cost. While no consensus exists as to the final solution to this challenge, other potential energy storage technologies include chemical energy storage (the application of electrolysis to turn excess output from wind and solar into hydrogen and methane), compressed air storage (ambient air is compressed and stored under pressure and then heated and expanded in an expansion turbine when needed), and pumped hydro (pumping water uphill at time of peak wind/solar output which is then used to run a hydro facility when the water is later released downhill).

19 Canada Research Page 19 of 115 Boralex, Inc. April 21, 2016 BLX-TSX David Quezada CFA Independent Power Producers Robust Growth Runway for French Wind Leader Recommendation We are initiating coverage of Boralex (BLX) with an Outperform rating and a $20.00 target price. Our constructive stance is a product of the company s stable existing operations and growth potential in France where it boasts an attractive pipeline of projects that we expect will drive strong EBITDA and FFO growth in coming years. We expect this cash flow growth will enable BLX to increase its dividend in Analysis France fertile land for wind power growth With ambitious renewable power expansion targets we believe France will remain a supportive jurisdiction for wind power development for the foreseeable future. As Boralex is now the third largest wind power producer in France (and the largest private producer) we believe the company is poised to benefit from this durable trend. In fact, with a 700 MW prospective project pipeline of largely wind projects we see Boralex s growth being concentrated in France in the coming years. Longer term, we also take a positive view of potential near-shore wind opportunities in Denmark. Focus on contracted renewable assets The product of a concerted strategic shift by management, Boralex now boasts a 98% contracted capacity of which 95% is made up of wind and hydroelectric facilities. This compares to 2009 when 51% of the company s installed capacity was contracted and 57% of its capacity was thermal (biomass and gas-fired) facilities. As a result, the current version of the company enjoys significantly more stable cash flows and higher margins. We also take a positive view of BLX s geographical diversification with capacity which is roughly evenly distributed between North America and France. Rising capacity to drive strong EBITDA growth Boralex has indicated a short term target of reaching $275 mln EBITDA in 2017, and a longer term strategic goal of reaching 1,650 MW by Our estimates currently reflect strong EBITDA growth in 2016 rising 22% to $258 mln on the back of 156 MW of new capacity commissioned in 2015, the majority of which came on line late in the year. Turning to 2017 we expect more modest 2016 capacity additions will drive EBITDA a further 7% higher to $277 mln roughly in-line with management guidance. FFO growth points to dividend increase in 2017 We forecast Boralex generating strong FFO growth of 16% in 2016 to $149 mln and a further 9% in 2017 to $163 mln. Accordingly, we believe the company will meet its stated target of $70 mln in discretionary cash flows by 2017 which equates to $1.08/share, supporting our forecasted dividend of $0.60/share which represents a 56% payout ratio within the company s 40-60% targeted range. Valuation Our $20.00 target is based on our DCF model which assumes a 7.25% WACC. Alternatively, this equates to a 10.5x 2017E EV/EBITDA, in-line with the independent power producer average of 10.6x (see Exhibit 10). EPS 1Q 2Q 3Q 4Q Full Revenues EBITDA Mar Jun Sep Dec Year (mln) (mln) 2015A C$0.10 C$(0.10) C$(0.29) C$0.09 C$(0.21) C$324 C$ E (0.10) E (0.09) Source: Raymond James Ltd., Thomson One Company Report - Initiation of Coverage Outperform 2 C$20.00 target price Current Price ( Apr ) C$16.17 Total Return to Target 27% 52-Week Range C$ C$11.79 Suitability Medium Risk/Income Market Data Market Capitalization (mln) C$1,053 Current Net Debt (mln) C$1,528 Enterprise Value (mil.) C$2,578 Shares Outstanding (mln, f.d.) Day Avg Daily Volume (000s) 105 Dividend/Yield C$0.56/3.5% Key Financial Metrics 2015A 2016E 2017E P/E EV/EBITDA NA 37.0x 30.5x 12.2x 10.0x 9.3x FCF/Share C$2.50 C$2.30 C$2.52 Net Debt (%) 59% Company Description Boralex is a Canadian independent power producer with assets located in Canada, France, and the US. The company has total net capacity of 1,094 MW compoused of wind (80%), hydroelectric (15%), thermal (4%) and solar (1%).

20 Canada Research Page 20 of 115 Table of Contents Investment Overview Company Overview Growth Strategy Financial Analysis & Outlook Valuation & Recommendation Appendix I: Financial Statements Appendix II: Management Team Risks... 35

21 Canada Research Page 21 of 115 Investment Overview Growth in French wind sector While the company is currently roughly balanced between North America and France, we believe Boralex intends to prioritize growth in French wind power going forward. With acquisition of Enel Green Power France and, more recently, a 350 MW development portfolio from Ecotera, Boralex now has an attractive 1,000+ MW prospective pipeline of projects at various stages of development, 700 MW of which is in France a favourable jurisdiction for wind power development, in our view, given the government s focus on renewable power expansion and wind specifically. In fact, we note that, given a long term goal of reaching 40% renewable power by 2030, the required investment in wind power projects will be significant estimated by some industry groups at 1,600 MW/year until 2020 and 3,000 MW per year after that. Boralex s management estimates that each 100 MW of French wind power added to the company s portfolio equates to $25 mln in EBITDA for the company. Now the country s third largest wind power producer (and the largest independent wind power producer), we believe BLX is very well positioned for an attractive long term runway of growth in France. Longer term we also see attractive opportunities for the company to develop offshore wind projects elsewhere in Europe as BLX is currently in the process of bidding on a 350 MW near-shore wind project in Denmark with a partner. Attractive renewable power footprint with good diversification and highly contracted revenue base With assets located across Canada (45% of capacity) as well as France (47%) and the US (8%) Boralex maintains good geographical diversification across its renewable power portfolio which is primarily composed of wind assets (80% of capacity) as well as hydroelectric (15%). In addition, 98% of the company s revenues are contracted via long term PPAs with credit-worthy counterparties, such as Électricité de France (PA-EDF) and Hydro Quebec, with an average remaining contract term of 15 years. We note a well-defined strategy of pursuing high margin, long life renewable power assets has resulted in the proportion of BLX s contracted assets rising to 98% from 51% in 2009 while the proportion of thermal assets in the company s portfolio has declined to 5% in 2015 from 57% in 2009 reducing exposure to the costs of fuel including gas and wood fibre residue. Growing capacity to drive strong EBITDA growth Boralex has indicated a short term target of reaching $275 mln EBITDA in 2017, and a longer term strategic goal of reaching 1,650 MW of capacity by Our estimates currently reflect strong EBITDA growth in 2016 rising 22% to $258 mln on the back of 156 MW of new capacity commissioned in 2015 (the majority of which came on line late in the year) which will make a full year contribution in Turning to 2017 we expect more modest 2016 capacity additions will drive EBITDA a further 7% higher to $277 mln roughly in-line with management guidance of $275 mln. Longer term Boralex is targeting capacity growth to 1,650 MW by 2020, which implies a CAGR of 10% over this period. We note, Boralex easily exceeded a prior growth target of reaching 950 MW of capacity by the end of 2016 over a year ahead of schedule with 1,094 MW of capacity by the end of Given this, as well as the company s strong pipeline, we believe the company is capable of achieving this goal. FFO growth points to dividend increase in 2017 Consistent with the EBITDA growth detailed above we forecast Boralex generating strong FFO growth of 16% in 2016 to $149 mln and a further 9% in 2017 to $163 mln. Accordingly, we believe the company can meet its stated target of $70 mln in discretionary cash flows by 2017 which equates to $1.08/share (Note: discretionary cash flows are equal to FFO less dividends to non-controlling interests, maintenance capex, and debt principal repayments). Thus, our forecasted dividend of $0.60/share represents a 56% payout ratio within the company s 40-60% targeted range. Alternatively, we believe these cash flows could also be used to fund accretive growth which would also result in a positive return to shareholders, in our view.

22 Canada Research Page 22 of 115 Company Overview Headquartered in Kingsey Falls, Quebec, Boralex is a developer, builder, and operator of renewable power facilities with approximately 300 employees and operations in Canada, France, and the US. With a focus on wind energy, Boralex also operates hydroelectric, thermal and solar power facilities. Geographically, 45% of the company s installed capacity is located in Canada with a further 47% in France and 8% in the US (see Exhibit 1 & 2). The company currently maintains 1,264 MW of power capacity in operation (of which it controls 1,094 MW) with a further 140 MW under construction. 98% of the company s capacity is contracted under long term PPAs with an average remaining length of 15 years. In France, BLX s assets consist of 491 MW of wind power capacity, 12 MW of thermal electricity, and 15 MW of solar, while in Canada, the company s assets are comprised of 383 MW of wind, 75 MW of hydro and 35 MW of thermal electrical capacity. In the US, BLX maintains 83 MW of hydroelectric generating capacity. Looking ahead, Boralex s management team has indicated a goal of $275 mln in EBITDA by 2017 which would equate to a CAGR of 14% over the next 2 years. With 156 MW of new capacity commissioned in Canada and France in 2015 (much of it late in the year) we believe the company has already made significant progress towards this goal. Longer term, the company is targeting net capacity of 1,650 MW by 2020, which equates to a 10% CAGR over this period. Exhibit 1: Boralex Geographical Footprint CANADA U.S. FRANCE Source: Boralex, Inc.

23 Canada Research Page 23 of 115 Exhibit 2: Boralex by Segment & Region 15% Capacity by Sector 4% 1% Capacity by Country 8% Contracted Capacity 2% 47% 45% 80% 98% Wind Hydroelectric Thermal Solar Canada France United States Under Contract Market Prices Source: Boralex, Inc., Raymond James Ltd. Share Ownership As of Apr there were 64.8 mln shares outstanding of Boralex trading on the Toronto Stock Exchange. Of these, ~13 mln (20%) are owned by Cascades Inc., a product of the historical relationship between the two companies which began when Cascades acquired 82.5% of the company in 1995, at which time Boralex operated as a member of the Cascades group of companies. Private equity company Kernwood owns a further 8% of the company while large institutional shareholders including CI Investments, RBC Global Asset Management and Fidelity each own significant stakes at 4.5%, 3.6% and 3.0% respectively. Shares of BLX have a three month average trading volume of 110K shares/day. Exhibit 3: Boralex Shareholder Summary Table (as at Apr-15-16) Shareholder Summary Largest Institutional Holders # Shares (mlns) % Outstanding CI Investments % RBC Global Asset Mgmt % Fidelity Investments % Dimensional Fund Advisors % AGF Management Ltd % Mackenzie Financial % Other Institutional % Total Institutional % Insiders Largest Insider Holders # Shares (mlns) % Outstanding Cascades Inc % Kernwood Ltd % Beniot Germain (Director) % Michelle Samson-Doel % Total Insider + VC/PE Firms + Corporations % Total Common Shares O/S Source: Capital IQ, Raymond James Ltd. Public & Other 47% Venture/PE Firms 8% Institutional 24% Insiders <1% Corporations (Cascades Inc.) 20%

24 Canada Research Page 24 of 115 Growth Strategy Growth strategy; low business risk of existing ops + growth in select regions From a high level, Boralex s stated growth strategy features the acquisition and/or development of renewable energy assets with stable revenues supported by long term fixed price energy sales contracts. The company also intends to focus on renewable energy assets (primarily wind, as well as hydroelectric and solar) with strong profit margins located primarily in France and Canada. First articulated in 2009, Boralex has maintained strict adherence to this growth strategy, exclusively acquiring assets with fixed rate agreements in place while aggressively expanding its footprint in the wind and hydroelectric segments and divesting assets exposed to market prices. Notably, since Dec-2012 BLX s installed wind capacity has grown from 286 MW to 874 MW currently, while the company s hydro capacity has also increased significantly over this period and its weighting to lower-margin thermal energy has declined. We take a positive view of BLX s steady growth and disciplined M&A track record. Acquisition of Enel Green Power France bolstered footprint in France In Dec-2014 BLX acquired 100% of Enel Green Power France SAS shares for C$400 mln which the company subsequently renamed Boralex Énergie Verte (BEV). These assets included 11 operational wind farms with a total of 186 MW of capacity with energy sales contracted over an average remaining life of 12 years at the time of acquisition. The Enel acquisition also included one 10 MW wind farm under construction which has since begun operations after commissioning in 2Q15. Growing BLX s existing footprint in the region, the BEV assets made Boralex the largest independent wind producer in France and the third largest overall, while also contributing a significant runway of power projects at various stages of development, some of which could be commissioned within the next 3 years. The BEV assets generated $35 mln in EBITDA in the first year following the acquisition while providing operating synergies, and provide improved purchasing power in terms of key elements such as wind turbines and replacement parts. In addition to BEV, Boralex also added to its French pipeline with the Dec-2015 acquisition of a 350 MW development portfolio from private wind developer Ecotera. This portfolio includes 79 MW of ready to build projects and will contribute to growth in 2017 and We believe Boralex has carved out a very attractive growth avenue in France, a favourable jurisdiction, and has a pipeline of attractive growth projects in the region that will further cement the company s position as a leader of wind expansion in the country. As highlighted in the table below Boralex commissioned a total of 156 MW new capacity in 2015 which is expected to make a $46 mln contribution to EBITDA according to company estimates. In addition, BLX paid $5 mln for the option to buy a 25% interest in the 230 MW Niagara wind farm from French turbine maker Enercon with a total expected project cost of $ mln. Under the partnership agreement with Enercon BLX is responsible for coordination of the project construction (which is expected to commission in late 2016) and would assume operating the site upon exercise of the option. We understand the exercising of this option will depend on the project meeting the company s IRR targets and see a strong probability of it moving ahead.

25 Canada Research Page 25 of 115 Exhibit 4: Boralex Project Commissioning Track Record Projects Commissioned Project Energy Source Capacity (MW) Location Length of Sales Contract Counterparty Ownership Stake Commissioning Timing Est. EBITDA (BLX share - C$ mlns) Jamie Creek Hydro 22 Canada - BC 40 BC Hydro 100% 2Q Fortel-Bonniéres Wind 23 France 15 EDF 100% 4Q Seigneurie de Beaupré Wind Farms Phase 2 Wind 68 Canada - Québec 20 Hydro-Québec 50% 4Q Témiscouata I Wind 23.5 Canada - Québec 20 Hydro-Québec 100% 4Q Projects Commissioned St-François Wind Farm Wind 23 France 15 EDF 100% 1Q Cômes de l Arce Wind 10 France 15 EDF 100% 2Q Les Cigalettes Solar 10 France 20 EDF 100% 3Q Frampton Community Wind Power (Acquisition) Wind 24 Canada - Québec 20 Hydro-Québec 67% 4Q Côte de Beaupré Wind 23.5 Canada - Québec 20 Hydro-Québec 100% 4Q Témiscouata II Wind 52 Canada - Québec 20 Hydro-Québec 100% 4Q Calmont Wind 14 France 15 EDF 100% 4Q Future Contracted Development Pipeline Touvent Wind Power (Acquisition) Wind 14 France 15 EDF 100% 3Q Plateau de Savernat Wind 12 France 15 EDF 100% 2H Yellow Falls Hydro 16 Canada 40 IESO 67% Northern France Acquisition (Ready to build) Wind 35 France 15 EDF 100% Northern France Acquisition (Ready to build) Wind 44 France 15 EDF 100% Otter Creek Wind 50 Canada - Ontario 20 IESO 38.5% Source: Boralex, Inc., Raymond James Ltd. Targeting 1,650 MW of capacity and $275 mln EBITDA After a recent acquisition of a ~350 MW portfolio of wind power projects in France from Ecotera (of which 79 MW were ready to build contracted projects to be commissioned in 2017 & 2018), the total Boralex project pipeline stands at ~1,000 MW of which 700 MW are in France. Of this, the Touvent (13.8 MW) and Plateau de Savernat (12 MW) projects are expected to be commissioned by the end of 2016 bringing BLX s pro-forma capacity to 1,120 MW. Turning to 2017, Boralex indicated that 35 MW of the recently acquired Northern France portfolio could be commissioned, which is in addition to the 16 MW Yellow Falls project in Ontario, bringing total estimated capacity to 1,171 MW by the end of 2017 and rounding out the contracted project pipeline that we include in our estimates is expected to bring the remaining 44 MW of the 79 MW ready to build Northern France portfolio, bringing total capacity to 1,215 MW while in 2019 BLX expects to reach commercial operations at the 19 MW (net) Otter Creek project which was part of the recent Large Renewable Procurement (LRP) in Ontario (the total project is 50 MW of which BLX maintains a 38.5% stake). Beyond these projects Boralex sees a further MW of potential projects on tap of which would bring the company to its target of 1,650 MW of capacity by 2020 a CAGR of 10% over this period (see Exhibit 5). We note, in early 2014, BLX indicated a targeted total capacity of 950 MW by the end of 2016 a target which has already been surpassed a year ahead of schedule with 1,094 MW of capacity at the end of As such, we believe the company is fully capable of delivering on its target of 1,650 MW of capacity by Boralex has also indicated an EBITDA target of $275 mln for 2017 which, given a recent 156 MW of projects commissioned in 2015, we believe it has already made significant progress (our 2017 estimate is slightly above this at $277 mln).

26 Canada Research Page 26 of 115 Exhibit 5: Boralex Planned Growth & Targets Source: Boralex, Inc. Long term growth objectives In addition to the above noted growth projects Boralex is also involved in a potential 350 MW near-shore wind joint venture project with a Danish partner. With this partner, Boralex has prequalified for the RFP and submitted a non-binding bid in Oct-2015 which, if successful would result in a binding bid from BLX and its partner in Spring If it goes ahead, this project will be developed over the next 3-5 years. BLX also sees the potential to participate in Denmark s opendoor program (240 MW) and the Kriegers Flak offshore project (600 MW) each of which are also longer term potential projects. The company views Denmark, which already generates an elevated proportion of its energy needs via green power, as an attractive potential market. France a key area for growth with a significant 700 MW project pipeline Due to large amounts of relatively inexpensive nuclear power, which provides 75% of the country s electricity, France has lagged peers such as Germany and the UK in renewable energy investment. However, the country now has ambitious green energy goals including renewable power representing 40% of electricity by 2030 while reducing nuclear power to 50% from 75% of total electrical generation. In order to meet these goals, industry sources believe the country will need to build 1,600 MW of land based turbines per year rising to 3,000 MW/yr by 2020 well above the 1,200 MW installed in Thus, France is amenable to expansion in green power which it supports via a model based on feed in tariffs and indexed contracts for wind (15 years) and solar (20 years). The country has a system where there is legal obligation to buy power once permitting is in place. Nationally, France had 8.1 GW of wind power capacity at the end of 2013 and is targeting 19 GW by 2020 and 25 GW by 2030 (see Exhibit 7). Equally important, onshore wind projects now being installed in the country are at grid parity. BLX has 700 MW of project opportunities ranging from Greenfield to advanced stage (see Exhibit 6) and estimates every 100 MW of power capacity added in France equates to an incremental $25 mln in EBITDA. We believe a conservative estimate for conversion of this pipeline to the construction stage would be roughly 50%. With over 15 years operating experience in the country, where it is the third largest producer of wind power, and the largest independent wind power generator (see Exhibit 8), BLX has solid positioning when targeting small projects, has an in-depth knowledge of the market, and is committed to a long term presence. As evidence of this strong positioning, BLX has expanded its capacity in France from 253 MW in 2013 to 462 MW in 2014 (with the Enel acquisition) and 518 MW in 2015.

27 E* 2020 Goal 2030 Goal Installed Capacity - MW Canada Research Page 27 of 115 Exhibit 6: Boralex Growth Pipeline France Source: Boralex, Inc. Exhibit 7: Growth of French Wind Industry 30,000 25,000 20,000 Installed Wind Power Capacity - France 15,000 10,000 5,000 0 * 2015 Estimated wind power capacity by France Energie Eolienne (FEE). Source: France Energie Eolienne, Raymond James Ltd.

28 GFDS + Predicia EDF EN + MEAG/GE Boralex + EGPF EDP Renovaveis Kallista/Ardian Boralex Allianz Volkswind Innovent EGPF KKR/Sorgenia Eurowatt ABO-WIND Quadran DIF Theolia Energy Power EOS Installed capacity - MW Canada Research Page 28 of 115 Exhibit 8: France Largest Wind Power Producers by Capacity 1,400 1,200 1, Source: Company Reports, Raymond James Ltd. Still open to Canadian expansion While we believe BLX is focused on France as its key growth region, the company remains open to expansion in Canada as evidenced by the company s purchase of an option for the 230 MW Niagara wind project in Ontario. In addition BLX is also reviewing projects in BC totaling 100 MW (30-50 MW of which is at advanced stages of development). More recently, Boralex and partner RES were awarded 50 MW as part of an LRP in Ontario for the Otter Creek wind farm. Expected to reach commercial operation around the end of 2019, Boralex maintains a 38.5% ownership stake in the project. Financial Analysis & Outlook Strong EBITDA growth on tap for 2016 Driven by the commissioning of 156 MW worth of projects over 2015 (114 MW of which came on line in late 2015) we forecast strong EBITDA growth for BLX in 2016 as these projects make a full year contribution. We see power generation rising 13% in 2016 to 3,087 GWh and EBITDA improving 22% to $258 mln (on a proportional consolidation basis). Looking to 2017 we see power generation and EBITDA growing by a more modest 4% (to 3,217 GWh) and 7% (to $277 mln) respectively while noting the company s attractive 700 MW pipeline of renewable power projects in France will likely result in growth reaccelerating into late 2017/early Of a recently acquired 350 MW portfolio of projects, 79 MW were ready for construction of which 35 MW will commence by Jun-2016 and be commissioned by the end of 2017 while the remainder comes in-line in Feb-2014 dividend announcement led to an increased trading multiple for BLX Previously one of the few IPPs without one, Boralex first announced it would pay a dividend in Feb-2014 prompting a 7% share price reaction that day. By our estimates, we believe this announcement led to a 1.0x increase in Boralex s EV/NTM EBITDA and has since resulted in the company trading at a higher multiple, relative to its non-dividend paying days. FFO growth points to dividend increase in 2017 Consistent with the EBITDA growth detailed above we forecast Boralex generating strong FFO growth of 16% in 2016 to $149 mln and a further 9% in 2017 to $163 mln. Accordingly, we believe the company can meet its stated target of $70 mln in discretionary cash flows by 2017 which equates to $1.08/share. Thus, our forecasted dividend of $0.60/share represents a 56% payout ratio within the company s 40-60% targeted range. While we expect any dividend increase announcement would be a positive catalyst, we believe the company maintains sufficient accretive growth opportunities such that the company using internally generated cash for growth will also benefit shareholders.

29 Canada Research Page 29 of 115 Exhibit 9: Boralex Operating and Financial Summary E 2017E Capacity (MW - EOY)) 938 1,094 1,120 1,171 Consolidated Generation (GWh) 2,030 2,733 3,087 3,217 Average Revenue per MWh Financial Stats Total Revenue EBITDA - Wind EBITDA - Hydro EBITDA - Thermal EBITDA - Solar EBITDA - Corporate (24.1) (26.9) (28.2) (30.2) Adj. EBITDA (Proportionate Consolidation) FFO Net Income (2.4) (10.8) FFO/Share EPS (0.31) (0.21) Dividend/Share Payout Ratio 57% 54% 56% Balance Sheet Cash Adj. Net Debt - End of year Forecast , , ,489.8 Net Debt (%) 59% Source: Boralex, Inc., Raymond James Ltd. Strong balance sheet to support growth objectives With a 2016E net debt to capital ratio of 59%, a net debt to EBITDA of 5.9x and EBITDA/interest coverage of 3.2x we regard Boralex s balance sheet as solid, particularly in light of the company s high degree of contracted revenues and geographical diversification. We also note 95% of Boralex s debt is long term debt with fixed rates, with this debt typically fixed over the life of the company s contracts with high quality counterparties. With $150 mln available before project financing and strong access to public markets we see the company as abundantly able to finance projects in the growth pipeline. We note, with the equity requirement of recently acquired 79 MW in ready to build projects (part of a 350 MW portfolio of projects the company acquired in late December 2015) at a reasonable $45 mln, we believe the company is more than capable of funding these projects from existing liquidity. Looking for in-line 1Q16 results Our $77.4 mln 1Q16 EBITDA estimate is roughly in-line with consensus of $76.9 mln while our EPS estimate of $0.26 is also broadly in-line with the street at $0.25. In conjunction with quarterly results we will be looking for updates on the company s construction projects as well as any color on the progress with the first 35 MW of ready to build projects which were part of the Ecotera acquisition.

30 2017E EBITDA Canada Research Page 30 of 115 Valuation & Recommendation Initiating coverage with an Outperform rating and $20.00 target price Our $20.00 target price for Boralex is based on our DCF model (see summary table in Exhibit 11) and includes a WACC of 7.25% and terminal growth rate of 1.5%. Alternatively our price target also equates to an ~10.5x 2017E EV/EBITDA, in-line with the peer group average of ~10.6x. We also take a positive view of Boralex s access to an attractive pipeline of wind power projects in France and the longer term potential for the company to participate in large scale offshore wind projects in Europe. We believe the earnings momentum associated with recent projects reaching commercial operations, a potential 2017 dividend increase, and updates on the company s growth pipeline will represent positive catalysts for the stock. With a total return of 27% to our target price we are initiating coverage of Boralex with an Outperform rating. Exhibit 10: Independent Power Producer Comp Table ` 4/19/2016 North American Power Producer Comp Table Recent Market Net Total Net 2017E Dividend Ticker Price Target Return Shares Cap Debt EV Debt EBITDA EV/EBITDA Target Yield Company Symbol Rating 4/18/2016 Price* (%) o/s ($ mln) ($ mln) ($ mln) (%) 2014A 2015A 2016E 2017E 2015A 2016E 2017E EV/EBITDA (%) Atlantic Power Corporation* TSX:ATP - $ 3.31 $ % ,043 47% x 9.7x 9.5x 5.8x 0.0% Boralex Inc. TSX:BLX Outperform $ $ % 65 1,053 1,528 2,425 0% x 9.4x 8.8x 10.5x 3.5% Brookfield Renewable Energy Partners LP* NYSE:BEP Outperform $ $ % 276 8,069 9,745 23,383 42% 1,139 1,177 1,872 1, x 12.5x 11.7x 13.0x 6.1% Capital Power Corporation TSX:CPX Market Perform $ $ % 96 1,719 1,563 3,799 41% x 8.2x 8.3x 8.5x 8.2% Etrion Corporation* TSX:ETX - $ 0.33 $ % % x 17.1x 14.0x 11.1x 0.0% Innergex Renewable Energy Inc. TSX:INE Strong Buy $ $ % 108 1,468 2,340 3,958 59% x 18.7x 12.5x 14.0x 4.7% Maxim Power Corp.* TSX:MXG - $ 2.95 $ % % x 9.2x 5.8x 6.6x 0.0% Northland Power Inc. TSX:NPI Outperform $ $ % 171 3,591 5,274 3, % x 7.5x 5.4x 17.9x 5.2% Pattern Energy Group Inc.* NASDAQ:PEGI Outperform $ $ % 75 1,523 1,676 4,187 40% x 13.2x 11.0x 12.0x 7.5% TransAlta Renewables Inc. TSX:RNW Outperform $ $ % ,191 67% x 3.1x 2.8x 10.5x 7.0% Averages 13.1x 10.9x 9.0x 11.0x 4.1% *Note: Atlantic Power, Maxim Power, and Etrion Corp. not covered by Raymond James Ltd - estimates and target price reflect Capital IQ consensus average. Pattern Energy and Brookfield Renewable Energy covered by Raymond James Ltd. Analyst Frederic Bastien. Source: Capital IQ, Company Reports, Raymond James Ltd. Exhibit 11: Boralex DCF Summary Table (LHS) and Theoretical Equity Value Sensitivity Table (RHS) Discounted Cash Flow Summary Table Boralex Theoretical Equity Value Sensitivity to Assumed Multiple & EBITDA Estimate Assumptions: Assumed EV/EBITDA Multiple WACC 7.25% ##### Terminal Growth Rate 1.5% Assumed L/T Tax Rate 27% Sustaining Capex/Yr $10 mln DCF Output PV of FCFF 1,930 $ mln PV of Terminal FCFF 931 $ mln Total EV 2,860 $ mln Less: Adjusted Net Debt (End of 2016) + NCI 1,525 $ mln Equity Value 1,336 $ mln Shares O/S (mlns, f.d.) Equity Value/Share $ Source: Raymond James Ltd.

31 Canada Research Page 31 of 115 Appendix I: Financial Statements Exhibit 12: Boralex Income Statement ( E, $ mln unless otherwise noted) Fiscal Year E 2017E Filing Currency: CAD Total Revenue Selling General & Admin Exp Development Expnenses Ops. and Maintenance Other Operating Expenses (3.4) (7.3) (5.8) (11.9) Total Operating Exp Adj. EBITDA - IFRS Adj. EBITDA - Prop. Consolidation Net Interest Exp Depreciation & Amortization Currency Exchange Gains (Loss) (1.9) Other Non-Operating Inc. (Exp.) EBT (14.6) (9.7) Income Tax Expense (0.9) (1.5) Earnings from Cont. Ops. (13.7) (8.2) Earnings of Discontinued Ops Net Income to Company (11.1) (8.2) Minority Int. in Earnings (0.7) (2.6) (2.1) (2.4) Net Income (11.8) (10.8) Diluted EPS (0.31) (0.21) $ 0.44 $ 0.53 Source: Boralex, Inc., Raymond James Ltd.

32 Canada Research Page 32 of 115 Exhibit 13: Boralex Balance Sheet ( E, $ mln unless otherwise noted) Balance Sheet Fiscal Year E 2017E Filing Currency: CAD ASSETS Cash And Equivalents Accounts Receivable Inventory Prepaid Exp Restricted Cash Other Current Assets Total Current Assets Net Property, Plant & Equipment 1, , , ,614.0 Goodwill Other Intangibles Long-term Investments Deferred Tax Assets, LT Deferred Charges, LT Other Long-Term Assets Total Assets 1, , , ,518.1 LIABILITIES Accounts Payable Accrued Exp Short-term Borrowings Curr. Port. of LT Debt Curr. Port. of Cap. Leases Curr. Income Taxes Payable Unearned Revenue, Current Other Current Liabilities Total Current Liabilities Long-Term Debt 1, , , ,518.9 Def. Tax Liability, Non-Curr Other Non-Current Liab., Total Total Liabilities 1, , , ,970.2 Total Common Equity Minority Interest Total Equity Total Liabilities And Equity 1, , , ,518.1 Source: Boralex, Inc., Raymond James Ltd.

33 Canada Research Page 33 of 115 Exhibit 14: Boralex Cash Flow Statement ( E, $ mln unless otherwise noted) Cash Flow Fiscal Year E 2017E Filing Currency: CAD Net Income (11.8) (10.8) Depreciation & Amort.- Total (Gain) Loss On Sale Of Invest (Income) Loss on Equity Invest. (6.1) Change in Non-cash W/C (2.1) (14.0) (13.7) (0.1) Other Operating Activities Other Cash from Ops Capital Expenditures (167.7) (329.6) (162.0) (100.0) Sale of Property, Plant and Equipment Cash Acquisitions (196.9) (60.3) - - Net Cash from Investments (13.3) Deferred Charges (6.9) (4.4) - - Total Other Investing Activities (1.4) Cash from Investing (364.1) (388.6) (162.0) (100.0) Net Debt Issued Issuance of Common Stock Common Dividends Paid (19.9) (27.1) (35.6) (36.3) Other Financing Activities 3.1 (1.7) - - Cash from Financing Foreign Exchange Rate Adj Net Change in Cash (49.5) 24.2 (12.1) 86.8 Source: Boralex, Inc., Raymond James Ltd.

34 Canada Research Page 34 of 115 Appendix II: Management Team Patrick Lemaire, President & CEO Mr. Lemaire has held the position of CEO and President of Boralex since September Prior to this, Mr. Lemaire was the COO and VP Containerboard at Norampac where he managed 8 mills located in Canada, France and the US a position he held from September 2001 until joining Boralex in He also held various management level positions at Norampac as well as Cascades. Mr. Lemaire has been a Director of Boralex since June 2006 and holds a degree in Mechanical Engineering from the University of Laval. Jean-Francois Thibodeau, Vice President and CFO Mr. Thibodeau has held the position of Vice President and CFO of Boralex since October His prior roles include Vice President and Treasurer of CAE Inc. (from 2001 until joining Boralex in 2003), Corporate Treasurer of GTC Transcontinental Group ( ) and Director of Finance and Treasury at Provigo from Mr. Thibodeau is also a Director of Boralex. Sylvain Aird, Vice President, Boralex Europe, Chief Legal Officer, Corporate Secretary Currently Boralex s Chief Legal Officer as well as VP of Boralex Europe, Mr. Aird s prior roles include VP- Legal Affairs and Corporate Secretary from April 2008 to June Hugues Girardin, Vice President Development Mr. Girardin s previous roles with Boralex include time as General Manager, Development from January 2008 to September Denis Aubut, General Manager, Operations Mr. Aubut has held various roles within Boralex including Manager of the Hydroelectric and Gas Cogeneration Division. Marc Jasmin, Investor Relations Manager Mr. Jasmin is Boralex s Investor Relations Manager and has held prior roles including Director of Investor Relations for Cascades and has been a Director of D-Box Technologies since 2003.

35 Canada Research Page 35 of 115 Risks Ability to identify and acquire or develop attractive growth opportunities Part of Boralex s strategy includes expanding its fleet of renewable power assets either by development or acquisition. In some cases Boralex must make some capital expenditures prior to a project reaching an advanced stage of development which could be lost should a project not go ahead. Should the company have difficulty finding or executing on such projects (or the land required to build them on) going forward this would negatively impact the business. Financing and interest rate risk Consistent with Boralex s goal of expanding, the company may from time to time require cash for new projects which would come from either operational cash flows or external sources such as raising additional equity or debt on public markets. The inability to source sufficient cash by these methods to expand and maintain Boralex s business represents a risk to this strategy. In addition, increased interest rates on the company s floating rate facilities or difficulties in refinancing existing debt could arise, materially impacting the business. Boralex also has certain financial restrictions and debt covenants as part of its existing loan/security agreements which, if not met by the company, could result in issues in refinancing debt or sourcing sufficient liquidity to withstand downturns in the business. Similarly, the company s dividend could also be reduced or eliminated should the company s business enter a downturn of some kind. Currency risk As the company maintains international operations in France and the US, Boralex can be exposed to the risk that the company s cash flows in Canadian dollar terms will be affected by fluctuations in Euro/CAD exchange rates or USD/CAD exchange rates. Liquidity risks related to derivative financial instruments From time to time Boralex employs the use of derivative contracts to hedge exposure to foreign exchange rates, interest rates and other uncertainties. Failure on the part of the counterparties to these contracts could have a material negative impact on the business. Variability of renewable energy sources The fuel for Boralex s renewable power facility generally comes in the form of wind, solar irradiation or hydrology each of which are variable both seasonally and on a daily basis. A lack of water flow, wind, or sun availability could negatively impact the company s revenues. Boralex also pays water rental costs for some of its hydroelectric facilities, which, should they increase would have a negative impact on the company. Delays and cost overruns of construction projects Boralex has numerous current and future power facilities under construction as part of its ongoing business. As such, delays, cost overruns, or mechanical breakdowns would have a negative impact on the business. Moreover, until such time as these facilities are up and running, there exists a risk that they may not run as predicted by management, or face unexpected regulatory issues/costs. Health and safety risk Should any of the employees working either operating or building Boralex s facilities be injured this could result in fines, orders to remedy unsafe conditions, increased compliance costs or issues with licenses/permits required to operate these facilities. In addition, failure to ensure the safety of these facilities could result in the company being in contravention of environmental, health, and safety laws, or face civil liability. Permitting risk In order to build and run its power facilities Boralex requires certain licenses and permits including environmental approvals. Failure, or material delays in receiving these permits/licenses could materially impact the business. Performance of facilities in relation to PPAs The power purchase agreements Boralex signs with the local electrical utilities require that the company deliver a certain amount of power. If the facility is unable to generate sufficient power either due to operational or other issues, the company may incur financial penalties under the terms of the PPAs. In addition, as PPAs expire there exists a risk that due to competition or other reasons, Boralex may not be able to renew its PPAs on attractive terms, or at all. In addition, the entities purchasing power from Boralex may fail to meet their obligations to the company.

36 Canada Research Page 36 of 115 Fuel supply, transportation & price Some of Boralex s natural-gas fired facilities could be affected by the availability of stable fuel supply at reasonable prices. While these are generally factored into PPA agreements the mechanisms by which fuel costs are matched may fully remove this risk. The company is dependent on third party suppliers under natural gas supply agreements fulfilling their obligations. Boralex s wood-residue power stations also rely on the availability of wood residue as fuel. Operational risk As part of the normal course of business, Boralex s facilities are subject to operational risk due to premature weak or failure of major equipment due to defects, materials, or workmanship. In some cases Boralex also relies on third parties for operations and maintenance and therefore relies on these companies to fulfill their obligations. Labour relations A labour disruption or dispute, such as a strike or lockout could negatively impact Boralex s operations as some of the company s facilities are unionized. Boralex also relies on several key employees and the company s success could be impacted by its ability to retain these senior officers. Regulatory & litigation risk Boralex has operations in Canada, France, and the US and could be exposed to the risk of changing regulations or laws related to foreign ownership, taxation, royalties, duties, or environmental regulations. Changes of this nature could materially impact Boralex s business, increase the cost of compliance or result in litigation of some kind.

37 Canada Research Page 37 of 115 Capital Power Corporation April 21, 2016 CPX-TSX David Quezada CFA Independent Power Producers Climate Leadership Complications a Near-Term Risk; Brighter Future Ahead Recommendation We are initiating coverage of Capital Power (CPX) with a Market Perform rating and $18.00 target price. While we take a positive view of the company s rising contracted cash flows, attractive dividend yield, and inexpensive relative valuation, two key risks prompt our neutral stance. These include the potential for early retirement of CPX s coal-fired power plants due to the Alberta Climate Leadership Plan, and weak current Alberta power prices. Moreover, our estimates currently reflect a relatively flat EBITDA forecast, contributing to our Market Perform rating. Analysis Alberta Climate Leadership Plan; weak power prices prompt neutral stance As part of the province s Climate Leadership Plan, Alberta has proposed the complete phase-out of coal-fired electrical generation by 2030 something we believe would disproportionately impact Capital Power s relatively young fleet of coal power plants. We also note increased costs related to carbon emissions regulations will also likely mean significantly increased costs to CPX longer-term. Meanwhile, with ~40% of generation capacity being sold into the Alberta merchant power market, weak power prices are a headwind looking to 2017E and beyond (2016 output is fully hedged) YTD power prices in Alberta have averaged ~$15/MWh, which compares to 2015 average prices of $33/MWh. Attractive dividend, inexpensive relative valuation At 8.2%, CPX currently maintains the highest dividend yield in our independent power producer (IPP) coverage universe. In addition, management has guided to a targeted 7% y/y increase in the dividend through to 2018 something our estimates suggest the company is capable of, particularly considering its contracted cash flows profile. Based on our 2017 estimates, CPX currently trades at an 8.3x EV/EBITDA, a material discount to the IPP peer group at 10.5x. We believe this high relative yield and lower trading multiple likely relate to the above noted risks associated with the Climate Leadership Plan. Longer term opportunities in Alberta In the long run, we expect renewable power producers will reap the benefits of a significant required procurement of green energy projects if provincial emissions targets are to be achieved. The Alberta government has indicated roughly 6 GW of coal power generation capacity that will be retired in Alberta by 2030 will be replaced by 2/3 renewables and 1/3 natural gas, which will require significant investment in each of these areas. Valuation Our initial $18.00 target is based on an 8.5x 2017E EV/EBITDA, a discount to the 10.6x independent power producer group average multiple (see Exhibit 6) due to regulatory risk in Alberta, weak power prices, and a more modest growth outlook. EPS 1Q 2Q 3Q 4Q Full Revenues EBITDA Mar Jun Sep Dec Year (mln) (mln) 2015A C$0.24 C$0.10 C$0.22 C$0.42 C$0.97 C$1,251 C$ E , E , Source: Raymond James Ltd., Thomson One Company Report - Initiation of Coverage Market Perform 3 C$18.00 target price Current Price ( Apr ) C$17.87 Total Return to Target 9% 52-Week Range C$ C$15.41 Suitability Medium Risk/Growth Market Data Market Capitalization (mln) C$1,719 Current Net Debt (mln) C$1,563 Enterprise Value (mln) C$3,799 Shares Outstanding (mln, f.d.) Day Avg Daily Volume (000s) 181 Dividend/Yield C$1.46/8.2% Key Financial Metrics 2015A 2016E 2017E P/E EV/EBITDA 18.4x 15.8x 16.1x 8.2x 8.2x 8.3x FCF/Share C$3.60 C$3.33 C$3.25 Net Debt (%) 41% Company Description Capital Power is a Canadian independent power producer with operations in Canada and the US. The company has a total net capacity of 3,200 MW including coal (43%), gas (35%), wind (18%), solid fuels (4%) and solar (1%)

38 Canada Research Page 38 of 115 Table of Contents Investment Overview Company Overview Growth Strategy Financial Analysis & Outlook Valuation & Recommendation Appendix I: Financial Statements Appendix II: Management Team Risks... 52

39 Canada Research Page 39 of 115 Investment Overview Alberta regulatory risk and power prices an overhang Despite many attractive attributes, the regulatory risk of operating coal-fired assets and weak merchant power pricing in Alberta are the primary reasons for our neutral stance on Capital Power. As part of the province s Climate Leadership Plan (CLP), Alberta has proposed the complete phase-out of coal-fired electrical generation by 2030 something we believe would disproportionately impact Capital Power s relatively young fleet of coal power plants. Moreover, increased costs related to carbon emissions as part of the Carbon Competitiveness Regulations will also likely mean significantly increased costs in the long run. Meanwhile, with ~40% of power generation being sold into the Alberta merchant power market, weak power prices are a headwind looking to 2017E (2016 output is fully hedged). Longer term, however, as the CLP s coal retirements are implemented, we see rising Alberta power prices as a material benefit to CPX. Thus, while we see a more attractive outlook for CPX in Alberta over the time period, we await clarity on compensation for early coal asset retirements and an uptick in Alberta power prices. Expansion projects on holding pending clarity on compensation from Alberta government for early coal retirements under the CLP As part of a joint venture with ENMAX Energy (private), CPX plans to develop the Genesee 4 and 5 natural gas fired combined cycle power facilities with a total capacity of 1,060 MW, which represents the company s largest contemplated expansion project. The joint venture includes an 8-year tolling agreement with ENMAX for 50% of CPX s share of the output. With a total projected cost of $1.4 bln and an attractive projected unlevered after tax IRR in the 11% range, we expect this project to be accretive to cash flow and earnings. However, while all regulatory approvals are in place for the Genesee 4, the project is on hold pending further clarity from the Alberta government on the Climate Leadership Plan, compensation for CPX s coal-fired asset retirements and the potential impact to the Alberta power market design. While we regard this as a prudent course of action for CPX, it impacts visibility on the company s growth profile. Attractive dividend with upside At 8.2%, CPX currently maintains the highest dividend yield in our IPP coverage universe. In addition, given a conservative payout ratio, a rising proportion of cash flow coming from contracted facilities, and stable forecast FCF, we believe CPX is capable of delivering on management s guidance of 7% y/y dividend growth through to 2018E. We note CPX s strong balance sheet further supports our view of the dividend s safety. Relatively inexpensive valuation At a current 2017E EV/EBITDA of 8.3x, CPX trades at a discount to the IPP peer group average at 10.5x. We attribute this discounted multiple to the overhang represented by the Alberta Climate Leadership Plan and weaker Alberta power prices described above. We also note, according to our estimates, CPX has a relatively flat EBITDA outlook in coming years, compared to what are generally substantial forecast increases in EBITDA and FCF over our forecast horizon for the peer group. We believe clarity on the Alberta CLP negotiations and a decision to go ahead with the Genesee 4 and 5 facilities (which is contingent on these negotiations) would result in an increase in market confidence, provided a satisfactory outcome is reached. Opportunity to expand renewable, gas-fired footprint a longer term opportunity While the Alberta CLP is a near-term headwind, over time we expect renewable power producers will reap the benefits of a significant required procurement of green energy projects if provincial emissions targets are to be achieved. Assuming the roughly 6 GW of coal power generation capacity that will be retired in Alberta by 2030 will be replaced by 2/3 renewables and 1/3 natural gas, there will be significant investments required in each of these areas. CPX s management has noted that given the lower capacity factors, 4-6 GWh of renewable energy at an assumed 150 MW/site would necessitate over 40 sites at an estimated capital cost of $12 bln. Meanwhile, as for the 2 GW of natural gas replacement energy, 8-10 Natural Gas Combined Cycle (NGCC) sites would necessitate an estimated $8-$10 bln in investment. This is longer term development that we believe CPX is well positioned to capitalize on, particularly given the potential for the company to repurpose certain pieces of the infrastructure at coal power plants slated for retirement as part of new natural gas fired facilities.

40 Canada Research Page 40 of 115 Company Overview Company Profile Headquartered in Edmonton, Alberta Capital Power is an independent power producer focused on the development, acquisition and operation of a variety of power generation assets including natural gas, coal, wind, and solid fuel facilities. Originally a spin out from EPCOR Utilities (private) via a 2009 IPO, Capital Power has grown significantly and today owns 3,200 MW of net capacity at 18 North American Facilities. These assets are located throughout North America (primarily Alberta) with 43% of the company s capacity coming in the form of coal-fired power plants, followed by gas at 35%, wind at 18%, solid fuels at 4%, and solar at <1% (see Exhibit 1). Capital Power maintains both commercial (merchant) and contracted business lines and therefore has exposure to market power prices in Alberta which the company actively hedges. The company s contracted business represents ~60% of its total capacity, with the remaining ~40% sold into the Alberta energy only market. For 2016, CPX s merchant capacity is 100% hedged. In addition to the company s operational facilities, CPX has 530 MW of generation capacity at advanced stages of development. Exhibit 1: Capital Power Geographical Footprint (LHS) and Asset Mix by Fuel Type (RHS) Solid Fuels 4% Solar 0.5% Wind 18% Coal 43% Gas 35% Source: Capital Power Corporation New capacity online in 2015 CPX brought three facilities to commercial operations in 2015: a wind farm, a solar facility, and a large natural gas power plant. First, in partnership with Samsung Renewable Energy and Pattern Energy Group, CPX reached commercial operations at the 270 MW K2 Wind facility in Ontario, coming in on time and under budget (CPX s portion of construction costs was $297 mln). CPX owns a 33.3% stake in the facility (90 MW) which maintains a 20 year power purchase agreement (PPA) with the Ontario Independent Electricity System Operator. In addition, in late 2015, CPX commissioned the 15 MW Beaufort Solar facility which will sell power to Duke Energy as part of a 15 year PPA. Finally, in Mar-2015, Capital Power and partner ENMAX announced commercial operations at the 800 MW Shepard natural gas facility. CPX s 50% ownership stake equates to 400 MW of net capacity, of which commercial arrangements with ENMAX feature a 20 year tolling agreement where 75% of CPX s owned capacity is contracted from and 50% is contracted out to 2035.

41 $/MWh Canada Research Page 41 of 115 Weak Alberta Power Market a Risk to IPPs with Merchant Power Capacity Pressure on pricing of late mitigated by effective hedging strategy As illustrated in Exhibit 2 below, the marked weakness in the Oil and Gas sector and the subsequent impact on economic activity has weighed on power pricing in Alberta, with 2015 average pricing down 33% y/y to an average of $33/MWh and 2016 YTD prices down a further 55% to $15/MWh. While Capital Power s merchant output is 100% hedged for 2016 at an average price in the high $40/MWh range, we believe this soft price environment represents a risk in the medium-term with 38% of CPX s generation hedged for 2017 (in the low $50/MWh range) and 9% for 2018 (in the mid $60/MWh range). That said, CPX has a track record of consistently utilizing hedges (both operationally and with financial derivatives) to optimize the company s realized power prices, outperforming spot prices by an average of 35% since the beginning of 2010 (see Exhibit 2 RHS). As such, we assume CPX realizes average pricing of $40/MWh in 2017E. Exhibit 2: Alberta Power Prices (LHS), CPX Track Record vs. Spot Pricing (RHS) YTD Average Alberta Power Price ($/MWh) Source: Alberta Electric System Operator (AESO), Capital Power Corporation, Raymond James Ltd. Potential negative impact from the Alberta Climate Leadership Plan (CLP) As detailed in our industry outlook, there are federal and provincial regulations relating to the coal industry that each have the potential to impact CPX s coal-fired assets. The first of these is the Canadian Federal Government s Capital Stock Turnover regulations, which stipulate that coal-fired power facilities must meet greenhouse gas (GHG) requirements or retire by the time they reach 50 years of operation. As CPX s fleet of coal powered facilities is relatively new, the impact to the company s business will be modest with no facilities seeing retirement until 2039, followed by subsequent shuts in 2044, 2055 and The retirement of these facilities, however, will be pre-empted by much more onerous provincial level regulations as contemplated in the Alberta Climate Leadership Plan. The CLP includes the complete phase-out of coal-fired power plants in Alberta by 2030, of which 2/3 is to be replaced by renewable energy and the remaining 1/3 by natural gas. By this time the provincial government anticipates 30% of electricity generation will come from renewable sources. Thus, while we regard CPX s relatively young power generating assets as generally positive, the potential for the CLP to mandate the retirement of all coal power plants by 2030 could result in early asset retirements disproportionately impacting newer assets. Potential for compensation for early coal retirements While no details have been made available as of yet, the Alberta Government has indicated owners of facilities facing early retirement will be compensated and CPX is awaiting clarity as to how this compensation will be determined. To this end, a negotiator (Terry Boston, former CEO of US power giant PJM Interconnection) has been named to negotiate a settlement between the Alberta government and the coal power producers an important milestone in reaching clarity on the potential compensation for CPX and something we expect could be available by late 3Q16 or early 4Q16. We believe Mr. Boston s experience in deregulated markets and the process of coal retirements and their potential impact on grid reliability makes him a good choice for this role. Also noteworthy, part of Mr. Boston s mandate is dealing with stranded capital. We believe the Alberta government will take into consideration the potential issues with investor confidence should owners of retiring coal power assets not be adequately compensated. That said, there remains significant uncertainty as to how this issue develops, in our view.

42 Canada Research Page 42 of 115 What could compensation look like? CPX s management has noted a basis for the calculation may be based on the ratio of the reduced asset life to its remaining life multiplied by net book value (NBV). By this methodology, CPX s coal assets, which currently have an NBV of $2 bln and a combined remaining life of 139 years, would see remaining life reduced by 79 years assuming a 2030 retirement. Thus, the 57% reduction in the remaining life of the assets multiplied by the $2 bln NBV equates to a $1.1 bln rough compensation figure. We would consider this to be the upper bound of potential compensation, as our conversations with the company suggest that certain coal infrastructure can be repurposed for future natural gas fired assets under Alberta s expected large future procurement and are therefore not necessarily stranded. CPX believes a potential approach to implementing this compensation could be reduced compliance requirements for the affected facilities in the years leading up to This could be a palatable means of providing compensation for the government since it would not result in a rider on the utility bills of Alberta residents. If realized, we believe adequate compensation would represent a material positive for the stock; however, until such time as these negotiations are complete, there remains significant risk associated with this process. Changes to Alberta emissions regulations In Jun-2015 the Alberta government announced changes to regulations relating to carbon emissions. The current regulation, called the Specified Gas Emitters Regulation (SGER), includes required reductions in emissions intensity and contributions to the Climate Change and Emissions Management Fund. The announced changes to SGER, which relate to any facility producing more than 100K tonnes or more of GHG per year, include an increase to the required reduction of emissions intensity from 12% to 15% in 2016 and 20% in 2017, while the cost of contributions to the Climate Change and Emissions Management Fund will increase from $15/tonne to $20/tonne in 2016 and $30/tonne in 2017 for every tonne of GHG above these levels. Looking ahead, the CLP recommends SGER be replaced with the Carbon Competitiveness Regulation (CCR) in Under this new regulation, electricity generators would pay $30/tonne as of Jan-2018 for GHG emissions above an electricity sector performance standard which is consistent with the cleanest natural gas fired plant (which implies a 55-65% reduction in GHG emissions intensity). While there will be an impact to CPX s Genesee 3 and Keephills 3 facilities, the company expects this will be offset by higher pool prices and by utilizing the company s inventory of low-cost carbon offset credits through Notably, CPX s new Shepard gas facility is the low cost producer and therefore will see no compliance costs with CCR a net benefit relative to SGER. Expected financial impact of compliance costs under CCR At least initially, Capital Power s management expects the incremental EBITDA impact of the CCR legislation to be positive as the increased coal compliance costs will be passed on to consumers, resulting in higher Alberta wholesale power prices while CPX maintains an inventory of low cost carbon credits which it also plans to use to offset these requirements. The company also expects a positive impact to their natural gas and wind facilities from higher pool prices and a reduction in compliance costs at the Shepard natural gas facility. Thus, CPX has indicated an estimated EBITDA lift of $80 mln in 2018 from the CCR legislation and a more modest EBITDA increase of $5 mln in Looking beyond this initial period, however, CPX will be faced with increased compliance costs from CCR as the company s carbon credits will be depleted and the PPAs for Genesee 1 and Genesee 2 expire (the terms of these PPAs dictate that increased costs of carbon compliance are borne by the PPA holder (the Balancing Pool in Alberta)). As such, the company anticipates a negative EBITDA impact of $35 mln in 2020, and ~$100 mln/year from once these PPAs expire and the company begins to incur these increased carbon offset costs.

43 Canada Research Page 43 of 115 Share Ownership Capital Power shares trade on the Toronto Stock Exchange (TSX) and there are currently 96.3 mln common shares outstanding. Of these, 9.4 mln (or 9.8%) are owned by EPCOR Utilities, while institutional investors Letko Brosseau & Associates, CIBC Asset Management, and TD Asset Management, each own significant stakes at 10.1%, 6.1%, and 4.4% respectively. Shares of CPX have a 3 month average daily trading volume of 307K. Exhibit 3: Capital Power Corp. Shareholder Summary (as at Apr-15-16) Shareholder Summary Largest Institutional Holders # Shares (mlns) % Outstanding Letko, Brosseau & Associates % CIBC Asset Mgmt % TD Asset Mgmt % Mackenzie Financial % CI Investments % BMO Global Asset Mgmt % Other Institutional % Total Institutional % Insiders Largest Insider Holders # Shares (mlns) % Outstanding EPCOR Utilities % Brian Vaasjo (CEO) % John Bolton (Former Director) % Anthony Lee (Former SVP) % Total Insider + Corporations % Total Common Shares O/S Public & Other, 43% Insiders, 0% Corporations (EPCOR Utilities), 10% Institutional, 47% Source: Capital IQ, Raymond James Ltd. Growth Strategy Genesee 4 and 5 As part of a joint venture with ENMAX, CPX plans to develop 2 natural gas fired combined cycle facilities with a total capacity of 1,060 MW Genesee 4 and 5. The joint venture will include an 8 year tolling agreement with ENMAX for 50% of CPX s share of the output. With the total expected project cost of $1.4 bln, CPX expects an unlevered after tax IRR in the 11% range and we expect the project will be accretive. An agreement is in place with Mitsubishi- Hitachi for supply and maintenance of turbines. While regulatory approvals are in place, the project is on hold pending further clarity from the Alberta government on the Climate Leadership Plan and the potential impact to CPX s existing assets and the Alberta power market design. An agreement with Mitsubishi for turbine supply is in place with a notice to proceed deadline that was recently extended by 90 days beyond the prior March 1 deadline. We believe the likelihood of sufficient clarity being available on the CLP before this 90 day extension expires is minimal (some details are expected in late 3Q16/early 4Q16), however, the project is contingent on CPX receiving fair compensation for the potential accelerated closure of its coal-fired assets. As such, we believe the CLP negotiations, and not the turbine deadline, will drive this decision for CPX. We regard this as a prudent course of action for the company. Other attractive wind projects on deck In addition to Genesee 4 and 5, CPX has two attractive prospective wind projects in development Halkirk 2 and Bloom Wind. Halkirk 2 is a 150 MW wind facility which CPX plans to build next to the company s existing Halkirk facility at an expected investment of $300 mln. Applications for permits and supporting studies are currently underway and an interconnection application with Alberta Electric System Operator (AESO) has been filed with a request for proposal (RFP) process expected to commence in late CPX expects Halkirk

44 Canada Research Page 44 of will enjoy advantageous wind diversity which will result in a higher expected capture factor. Acquired in Feb-2014, Bloom Wind is a 180 MW wind farm project under development, which is located in a region of Kansas with one of the strongest wind regimes in the US. The Bloom wind project is ready to build pending execution of a PPA, which we understand is imminent. Acquisition of Element Power to expand renewable footprint In Dec-2014, CPX completed the acquisition of Element Power US for US$69 mln. This acquisition featured a development portfolio including 10 wind development sites and 4 solar development sites, one of which, Beaufort Solar, maintains a 15 year PPA with Duke Energy Progress Inc. Beginning commercial operations in Dec- 2015, the Beaufort facility marks CPX s first foray into solar power. The acquisition also included one operating asset, the MW Macho Springs Wind Project located in New Mexico, which was commissioned in Nov-2011 and has a 20 year PPA with Tucson Electric Power (private) securing 100% of revenues. In addition to Macho Springs and Beaufort, we understand two of the more advanced projects in the element portfolio are also at the RFP stage and could see offtake agreement announcements in the near-term. Significant investment required to offset reduced coal-fired power generation in Alberta Assuming the roughly 6 GW of coal power generation capacity that will be retired in Alberta by 2030 will be replaced by 2/3 renewables and 1/3 natural gas, there will be significant investment required in each of these areas. CPX notes that 4-6 GWh of renewable energy, at an assumed 150 MW/site and a 33% capacity factor, equates to GW of installed capacity, which would necessitate over 40 sites at an estimated capital cost of $12 bln. Meanwhile, as for the 2 GW of natural gas replacement energy, 8-10 Natural Gas Combined Cycle (NGCC) sites would necessitate an estimated $8-$10 bln in investment. In addition, gas peaking facilities would be required for wind intermittency while additional gas fired capacity would be required for growing demand. More recently, in early Mar-2016 the Alberta Government tasked the Alberta Electric System Operator with developing a renewable energy incentive program consistent with adding renewable power capacity by 2030 as coal-fired facilities are retired. AESO has begun consultations with stakeholders relating to this process and is expected to provide recommendations by May The first competition for new renewable projects is slated for late 2016 with these first facilities coming into service by As one of Alberta s largest IPPs, we expect CPX would see a material benefit in the form of participation in this large scale procurement of renewable and gas energy. We believe this represents a partial offset to the potential negative effects to the company from the CLP. Maintenance of Alberta wholesale electricity market structure Another element of the uncertainty surrounding the CLP has been whether or not Alberta s deregulated merchant power market would persist. Power prices in Alberta are set by supply and demand in real time with the independent system operator, AESO, which operates a balancing power pool by accepting offers to buy and sell power over an energy trading system. This contrasts with most other provinces where a provincial utility exists that runs a regulated power market which typically utilizes a costbased pricing system in determining rates. In light of an expected increase in power prices related to the implementation of the CLP, CPX has indicated a preference for the maintenance of the deregulated market. Initial indications from the government suggest the current market structure in Alberta will be maintained.

45 Canada Research Page 45 of 115 Financial Analysis & Outlook Steady forecast EBITDA as hedges, increased generation offset lower AB power prices CPX s management has stated that 100% of the company s baseload capacity is hedged for 2016 in the high $40/MWh range, while 38% is hedged for 2017 in the low $50/MWh range. Looking out to 2018, 9% is hedged in the mid $60/MWh range and prices are expected to increase due to higher carbon taxes coming into effect. As for power generation, we forecast full year contribution from the Shepard facility, K2 Wind, and Beaufort Solar resulting in total generation (excluding the Sundance PPA) rising 14% to 16,535 GWh for 2016E where, barring any potential acquisitions, we assume it will hold relatively constant for 2017E to 16,468 GWh. We also see results being impacted over 2017E by reduced average Alberta power prices which, although fully hedged for 2016, we expect will be lower than the $55/MWh average in 2015 (we assume $47/MWh). As such, we forecast flat EBITDA of $462 mln in 2016, from $461 mln in 2015, before declining modestly to $456 mln in Exhibit 4: Capital Power Operating & Financial Summary Table E 2017E Capacity (MW) 2,712 3,217 2,846 2,846 Consolidated Generation (GWh) 12,376 14,567 16,535 16,468 Income Statement Total Revenue 1,228 1,251 1,243 1,228 EBITDA Alberta Commercial & Sundance Alberta Contracted Ontario/BC Contracted US Contracted Corporate & Other Total Adj. EBITDA FFO FCF Net Income FFO/Share EPS Dividend/Share Payout Ratio 45% 50% Balance Sheet Cash Adj. Net Debt - End of year Forecast* Net Debt Mkt Basis(%) 41% Source: Capital Power Corporation, Raymond James Ltd. On pace to meet FFO guidance; increase dividend Consistent with modestly lower EBITDA, we forecast FFO of $385 mln for 2016, down from $408 mln in 2015 and toward the low end of management s FFO guidance of $ mln. After sustaining capex of $65 mln (per guidance) we arrive at FCF of $320 mln. Thus, assuming management s guided 7% dividend increase at some point in 2016 (from $1.46/share currently to $1.56/share), annual cash requirements would be $145 mln, which equates to a payout ratio of 45% or 53% including preferred dividends. Given strong growth in contracted cash flows (from Shepard, K2, Beaufort and Macho Springs see Exhibit 5 LHS), we believe these dividend growth targets are abundantly achievable. As CPX s current dividend of $1.46/share already represents an attractive 8.2% yield, we would expect a future dividend increase to be a positive catalyst.

46 Dividend/Share (C$) Canada Research Page 46 of 115 Exhibit 5: CPX Forecast Contracted Revenue Growth (LHS) and Forecast Dividend/Share (RHS) Dividend/Share E 2017E 2018E Source: Capital Power Corporation, Raymond James Ltd. Strong financial footing With net debt to cap of 41% (market basis) or 36% (book basis), 2016E net debt/ebitda of 3.4x and 2016E EBITDA/interest ratio of 4.9x, we regard Capital Power s balance sheet as very solid and the company s debt load as manageable. We also note the company s investment grade credit rating was recently re-affirmed by S&P (BBB-/stable) and DBRS (BBB/stable). Accordingly, we believe the company will have no trouble financing current growth plans. Looking for 1Q16 earnings ahead of consensus Capital Power reports 1Q16 results before market on April 25. We forecast EBITDA of $133 mln and EPS of $0.41, ahead of consensus of $126 mln and $0.35, respectively. In isolation we would expect a potential beat on earnings to have a positive impact on the share price, however, any update on the company s consultations with the Alberta government relating to CLP compensation could overshadow results.

47 2017E EBITDA Canada Research Page 47 of 115 Valuation & Recommendation Initiating coverage with a Market Perform rating and $18.00 target price While we take a constructive view of CPX s attractive dividend yield, inexpensive relative valuation, and potential growth projects, our outlook is tempered by material uncertainty relating to the Alberta CLP and weak Alberta power pricing. We believe the potential for early retirement of CPX s coal-fired generation assets represents a risk and note the development of Genesee 4 and 5 is contingent on fair compensation being received. While uncertain, we believe any indication that negotiations with the Alberta government will yield adequate compensation for these early retirements would represent a meaningful positive catalyst. Meanwhile, although CPX has an impressive track record of adding value through portfolio optimization, weak Alberta spot and forward power prices substantially lower than 2015 average realizations means our EBITDA outlook is relatively flat. Our initial $18.00 target price is based on an 8.5x 2017E EV/EBITDA, below the 10.6x peer group average due to the aforementioned risks. Exhibit 6: Independent Power Producer Comp Table ` 4/19/2016 North American Power Producer Comp Table Recent Market Net Total Net 2017E Dividend Ticker Price Target Return Shares Cap Debt EV Debt EBITDA EV/EBITDA Target Yield Company Symbol Rating 4/18/2016 Price* (%) o/s ($ mln) ($ mln) ($ mln) (%) 2014A 2015A 2016E 2017E 2015A 2016E 2017E EV/EBITDA (%) Atlantic Power Corporation* TSX:ATP - $ 3.31 $ % ,043 47% x 9.7x 9.5x 5.8x 0.0% Boralex Inc. TSX:BLX Outperform $ $ % 65 1,053 1,528 2,425 0% x 9.4x 8.8x 10.5x 3.5% Brookfield Renewable Energy Partners LP* NYSE:BEP Outperform $ $ % 276 8,069 9,745 23,383 42% 1,139 1,177 1,872 1, x 12.5x 11.7x 13.0x 6.1% Capital Power Corporation TSX:CPX Market Perform $ $ % 96 1,719 1,563 3,799 41% x 8.2x 8.3x 8.5x 8.2% Etrion Corporation* TSX:ETX - $ 0.33 $ % % x 17.1x 14.0x 11.1x 0.0% Innergex Renewable Energy Inc. TSX:INE Strong Buy $ $ % 108 1,468 2,340 3,958 59% x 18.7x 12.5x 14.0x 4.7% Maxim Power Corp.* TSX:MXG - $ 2.95 $ % % x 9.2x 5.8x 6.6x 0.0% Northland Power Inc. TSX:NPI Outperform $ $ % 171 3,591 5,274 3, % x 7.5x 5.4x 17.9x 5.2% Pattern Energy Group Inc.* NASDAQ:PEGI Outperform $ $ % 75 1,523 1,676 4,187 40% x 13.2x 11.0x 12.0x 7.5% TransAlta Renewables Inc. TSX:RNW Outperform $ $ % ,191 67% x 3.1x 2.8x 10.5x 7.0% Averages 13.1x 10.9x 9.0x 11.0x 4.1% *Note: Atlantic Power, Maxim Power, and Etrion Corp. not covered by Raymond James Ltd - estimates and target price reflect Capital IQ consensus average. Pattern Energy and Brookfield Renewable Energy covered by Raymond James Ltd. Analyst Frederic Bastien. Source: Capital IQ, Company Reports, Raymond James Ltd. Exhibit 7: Capital Power Theoretical Equity Value Sensitivity Table Capital Power Theoretical Equity Value Sensitivity to Assumed Multiple & EBITDA Estimate Assumed EV/EBITDA Multiple Source: Raymond James Ltd.

48 Canada Research Page 48 of 115 Appendix I: Financial Statements Exhibit 8: Capital Power Income Statement ( E, $ mln unless otherwise noted) Fiscal Year E 2017E Filing Currency: CAD Total Revenue 1, , , ,227.7 Fuel & Purchased Pow er Selling General & Admin Exp Other Operating Exp EBITDA Depreciation & Amort Net Interest Exp. (53.0) (93.0) (95.0) (97.0) Income/(Loss) from Affiliates Currency Exchange Gains (Loss) (10.0) (15.0) - - EBT Asset Writedow n (3.0) (2.0) - - Other Unusual Items (2.0) (1.0) - - EBT Incl. Unusual Items Income Tax Expense Earnings from Cont. Ops Diluted EPS Source: Capital Power Corporation, Raymond James Ltd.

49 Canada Research Page 49 of 115 Exhibit 9: Capital Power Balance Sheet ( E, $ mln unless otherwise noted) Balance Sheet Balance Sheet as of: E 2017E Filing Currency: CAD ASSETS Cash And Equivalents Accounts Receivable, Total Inventory Other Current Assets Total Current Assets Net Property, Plant & Equipment 3, , , ,444.0 Goodwill Other Intangibles Long-term Investments Accounts Receivable Long-Term Loans Receivable Long-Term Deferred Tax Assets, LT Other Long-Term Assets Total Assets 5, , , ,156.2 LIABILITIES Accounts Payable & Accrued Exp Curr. Port. of LT Debt Curr. Port. of Cap. Leases Other Current Liabilities Total Current Liabilities Long-Term Debt , , ,206.8 Capital Leases Unearned Revenue, Non-Current Pension & Other Post-Retire. Benefits - - Def. Tax Liability, Non-Curr Other Non-Current Liab., Total Total Liabilities 2, , , ,545.7 Total Pref. Equity Common Stock 1, , , ,280.0 Retained Earnings 25.0 (70.0) (166.7) (275.5) Comprehensive Inc. and Other Total Common Equity 1, , , ,542.5 Minority Interest Total Equity 3, , , ,610.5 Total Liabilities And Equity 5, , , ,156.2 Source: Capital Power Corporation, Raymond James Ltd.

50 Canada Research Page 50 of 115 Exhibit 10: Capital Power Cash Flow Statement ( E, $ mln unless otherwise noted) Fiscal Year: E 2017E Filing Currency: CAD Net Income Depreciation & Amort., Total (Gain) Loss On Sale of Assets Net (Increase)/Decrease in Loans Orig/Sold Change in non-cash W/C (81.1) (11.8) Change in Unearned Rev. (1.0) (1.0) - - Change in Other Net Operating Assets (4.0) (7.0) - - Other Operating Activities Cash from Ops Capital Expenditures (220.0) (140.0) (90.0) (120.0) Cash Acquisitions (18.0) Total Other Investing Activities Cash from Investing (230.0) (136.0) (90.0) (120.0) Net Debt Issued (48.0) (1.0) (59.3) (10.0) Issuance of Common Stock Repurchase of Common Stock - (121.0) - - Common Dividends Paid (68.0) (106.0) (145.4) (155.6) Pref. Dividends Paid (22.0) (22.0) (24.0) (24.0) Other Financing Activities (77.0) (32.0) (36.0) (36.0) Cash from Financing (191.0) (280.0) (264.7) (225.6) Foreign Exchange Rate Adj Net Change in Cash (29.0) 9.0 (51.1) 20.2 Source: Capital Power Corporation, Raymond James Ltd.

51 Canada Research Page 51 of 115 Appendix II: Management Team Brian Vaasjo, President & CEO Mr. Vaasjo has been the President and CEO of Capital Power since the company s IPO in July His 35 years of industry experience include roles as Executive Vice President at EPCOR, President of EPCOR s Energy Division and various positions over 18 years at the Enbridge Group of companies. Mr. Vaasjo holds an undergraduate degree and MBA from Western University, attended the University of Western Ontario s Executive Program and is a Fellow of the Society of Management Accountants. Bryan DeNeve, SVP-Finance & CFO Prior to being appointed to his current position in May 2015, Mr. DeNeve held positions within CPX including SVP-Corporate Development and Commercials Services and VP-Business Development. His prior roles include VP-Regulatory Affairs at EPCOR ( ) and time at the Alberta Department of Energy. Mr. DeNeve holds an undergraduate degree and an MBA from the University of Alberta and is a graduate of Harvard Business School s Advanced Management Program. Kate Chishom, SVP-Legal and External Relations Ms. Chisholm has held the position of SVP- Legal and External Relations at CPX since July 2009 and prior to this, served as EPCOR s SVP, General Counsel and Corporate Secretary from Ms. Chisholm was appointed a member of the Alberta Securities Commission in In terms of education, Ms. Chisholm earned a Bachelor of Arts from Mount Allison University, Bachelor of Laws from the University of Alberta, and an MBA from Queen s University. Ms. Chisholm currently serves on the board of the International Women s Forum (Edmonton), the Palix Foundation, and City of Edmonton LRT Governance boards, among others. Darcy Trufyn, SVP-Operations, Engineering & Construction With the company since 2009, Mr. Trufyn is Capital Power s SVP, Operations, Engineering and Construction. His prior experience includes senior roles in a number of large projects in Alberta and the Maritimes, as well as the role of SVP, Construction at Worley Parsons and President of construction firm Lockerbie and Hole based in Edmonton. Mr. Trufyn is a professional engineer, a graduate of the University of Alberta, Faculty of Engineering and serves as the Board Chair for the Art Gallery of Alberta and as a Board Director of Wellspring Edmonton. Jacquie Pylypiuk, VP-Human Resources Ms. Pylypiuk was appointed to her current role as VP- Human Resources in April 2015 and prior to that, was CPX s Senior Manager-Talent Acquisition & Employee Engagement as well as Senior Manager, Business Partners. A Chartered Accountant, Ms. Pylypiuk has over 20 years of experience including 7 in audit and assurance in both public practice and internal audit and 17+ years of senior level HR experience. Ms. Pylypiuk received her Bachelor of Commerce Degree from the University of Alberta, is a Chartered Accountant and a Certified Human Resources Professional. Mark Zimmerman, SVP-Corporate Development and Commercial Services As part of his 25 years of experience in the energy infrastructure and petroleum industries, Mr. Zimmerman has served as the President of TC Pipelines ( ) and also spent time with TransCanada Pipelines Ltd. from , most recently as VP-Corporate Development & Strategy. Mr. Zimmerman is a Chartered Accountant, Chartered Business Valuator and a member of the Institute of Corporate Directors. He earned a Bachelor of Commerce from the University of Alberta.

52 Canada Research Page 52 of 115 Risks Ability to identify and acquire or develop attractive growth opportunities Part of Capital Power s strategy includes expanding its fleet of renewable and gas powered assets either by development or acquisition. In some cases Capital Power must make some capital expenditures prior to a project reaching an advanced stage of development which could be lost should a project not go ahead. Should the company have difficulty finding or executing on such projects going forward this would negatively impact the business. Financing and interest rate risk From time to time CPX will require cash for new projects which would come from either operational cash flows or external sources such as raising additional equity or debt on public markets. The inability to source sufficient cash by these methods to expand and maintain Capital Power s business represents a risk of this strategy. In addition, increased interest rates or difficulties in refinancing existing debt could arise, materially impacting the business. Capital Power also has certain financial restrictions and debt covenants as part of its existing loan/security agreements which, if not met by the company, could result in issues in refinancing debt or sourcing sufficient liquidity to withstand downturns in the business. Similarly, the company s dividend could also be reduced or eliminated should the company s business enter a downturn of some kind. Currency risk As the company maintains operations in the US, Capital Power can be exposed to the risk that the company s cash flows in Canadian dollar terms will be affected by fluctuations in USD/CAD exchange rates. Liquidity risks related to derivative financial instruments From time to time Capital Power employs the use of derivative contracts to hedge exposure to exchange rates, interest rates and other uncertainties. Failure on the part of the counterparties to these contracts could have a material negative impact on the business. Variability of renewable energy sources The fuel for Capital Power s renewable power facilities generally comes in the form of wind or solar irradiation each of which are variable both seasonally and on a daily basis. A lack of wind or sun availability could negatively impact the company s revenues. Delays and cost overruns of construction projects Capital Power has numerous current and future power facilities under construction as part of its ongoing business. As such, delays, cost overruns, or mechanical breakdowns would have a negative impact on the business. Moreover, until such time as these facilities are up and running, there exists a risk that they may not run as predicted by management, or face unexpected regulatory issues/costs. Health and safety risk Should any of the employees working either operating or building Capital Power s facilities be injured this could result in fines, orders to remedy unsafe conditions, increased compliance costs or issues with licenses/permits required to operate these facilities. In addition, failure to ensure the safety of these facilities could result in the company being in contravention of environmental, health, and safety laws, or face civil liability. Permitting risk In order to build and run its power facilities Capital Power requires certain licenses and permits including environmental approvals. Failure, or material delays, in receiving these permits/licenses could materially impact the business. Performance of facilities in relation to PPAs The power purchase agreements Capital Power signs with the local electrical utilities require that the company deliver a certain amount of power. If the facility is unable to generate sufficient power either due to operational or other issues, the company may incur financial penalties under the terms of the PPAs. In addition, as PPAs expire there exists a risk that due to competition or other reasons, Capital Power may not be able to renew its PPAs on attractive terms, or at all.

53 Canada Research Page 53 of 115 Fuel supply, transportation & price Some of Capital Power s natural-gas fired and coal facilities could be affected by the availability of stable fuel supply at reasonable prices. While these are factored into PPA agreements, in some cases the mechanisms by which fuel costs are matched may fully remove this risk. The company is dependent on third party suppliers under natural gas supply agreements fulfilling their obligations. Operational risk As part of the normal course of business, Capital Power s facilities are subject to operational risk due to premature weak or failure of major equipment due to defects, materials, or workmanship. In some cases Capital Power also relies on third parties for operations and maintenance and therefore relies on these companies to fulfill their obligations. Labour relations A labour disruption or dispute, such as a strike or lockout could negatively impact Capital Power s operations as some of the company s facilities are unionized. Merchant power sales risk A portion of CPX s sales are sold at prevailing rates in the Alberta power market. Thus, while the company effectively hedges this exposure in some cases, the weak power price environment in Alberta presents a risk to the company s business as lower forward prices available for hedging purposes could also decline. Political and regulatory risk As discussed elsewhere in this report, one of the key risks CPX faces is the potential early retirement of some of the company s coal-fired assets as part of the Alberta Climate Leadership Plan. The CLP also recommends the implementation of the Carbon Competitiveness Regulations which are also expected to result in increased compliance costs for the company. In addition, since some of CPX s facilities emit pollutants and or waste, the company is also responsible for acting in accordance with environmental regulations with respect to emissions and waste management. These and other regulatory challenges could have a material impact on the company's business. Changing political conditions could also have an impact on these regulations.

54 Canada Research Page 54 of 115 Innergex Renewable Energy, Inc. April 21, 2016 INE-TSX David Quezada CFA Independent Power Producers Long Life Canadian Stability with a French Growth Kicker Recommendation We are initiating coverage of Innergex Renewable Energy (INE) with a Strong Buy rating and $16.25 target. A pure-play renewable power company, we highlight INE s long life hydro-weighted asset base, attractive growth pipeline, strong expected EBITDA/FCF growth, track record of successful project development, and highly experienced management team as the key elements of our constructive thesis. Analysis Renewable pure-play with stable contracted existing business With a bias towards reliable, long life hydroelectric assets, an average PPA contract length of 18 years, the majority of the company s debt locked in at effectively fixed rates, and a relatively new fleet of assets with an average age of ~8 years we regard INE s core business as highly stable. Moreover, we take a positive view of the company s 100% renewable footprint something we expect will contribute to INE continuing to trade a premium forward multiple. Attractive growth pipeline INE currently has 5 projects under construction totaling 341 MW of gross capacity which, once complete, will increase the company s total gross capacity to just over 1660 MW, or 26% above current levels. Of these five projects, three are hydroelectric and two are wind farms. With PPA terms of 40 yrs for each of the hydro assets, yrs for the wind farms we expect INE s weighted average contract life will be further extended upon project completion. We also highlight INE s recent entry into the France with an acquisition of 8 wind projects with a gross 131 MW of capacity. We take a positive view of France as a jurisdiction for wind power development given significant targeted renewable power expansion and supportive government policies. Consistent with the above noted capacity additions we estimate INE s EBITDA will increase an average of 30+%/yr in each of 2016 and 2017 rising from $184 mln in 2015 to $316 mln in Robust forecast FCF growth from projects under construction We expect Innergex s free cash flow to post impressive gains over our forecast horizon, rising 47% between from $74 mln in 2015 ($0.71/sh) to $109 mln in 2017 ($1.01/sh). Accordingly, we expect a dividend hike to an estimated $0.68/share in 2017 which equates to a payout ratio of 67% by our estimate, just below the low end of the company s targeted 70-80% range. Strong, highly experienced, management team Led by President and CEO Michel Letellier (with INE for ~20 years), we regard INE s management team as among the best of the TSX-listed IPPs. We note the company s other senior management also boast lengthy careers in the renewable power industry and long tenures at Innergex. We believe the company s strong track record of completing projects on time/budget is a testament to management s abilities. Valuation Our $16.25 target is based on a 14.0x 2017E EV/EBITDA, a premium to the independent power producer average of 10.6x (see Exhibit 11) due to the company s long-life asset base, highly stable core business and attractive growth profile. EPS 1Q 2Q 3Q 4Q Full Revenues EBITDA Mar Jun Sep Dec Year (mln) (mln) 2015A C$(0.30) C$0.19 C$0.04 C$(0.31) C$(0.37) C$247 C$ E (0.04) E (0.02) Source: Raymond James Ltd., Thomson One Company Report - Initiation of Coverage Strong Buy 1 C$16.25 target price Current Price ( Apr ) C$13.60 Total Return to Target 24% 52-Week Range C$ C$9.51 Suitability Medium Risk/Growth Market Data Market Capitalization (mln) C$1,468 Current Net Debt (mln) C$2,340 Enterprise Value (mil.) C$4,089 Shares Outstanding (mln, f.d.) Day Avg Daily Volume (000s) 150 Dividend/Yield C$0.64/4.7% Key Financial Metrics 2015A 2016E 2017E P/E EV/EBITDA NA 54.1x 29.0x 22.3x 19.4x 12.9x FCF/Share C$2.50 C$2.30 C$2.52 Net Debt (%) 57% Company Description Innergex Renewable Energy is a Canadian pure play renewable independent power producer with operations in Canada, the US and France. The company's proforma gross capacity of 1,660 MW is composed of hydroelectric assets (61%) wind (35%) and solar (4%)

55 Canada Research Page 55 of 115 Table of Contents Investment Overview Company Overview Growth Strategy Financial Analysis & Outlook Valuation & Recommendation Appendix I: Financial Statements Appendix II: Management Team Risks... 69

56 Canada Research Page 56 of 115 Investment Overview Stable, highly contracted business core business, renewable pure-play Given our constructive outlook for the renewable power sector overall, we take a positive view of Innergex s 100% green energy asset base. With an average PPA contract length of 18 years with high quality counterparties, and relatively young fleet (avg. age of ~8 yrs) we also regard INE s core business as highly stable. We believe the core of the company s competitive advantage centers around INE s deal sourcing, rare hydroelectric development capabilities and strong First Nations relationships which have given rise to a very attractive asset mix consisting largely of premium long-life hydro assets. Further contributing to this stability Innergex s debt is locked in at effectively fixed rates and the company s balance sheet is strong, in our view. In light of this we believe Innergex will continue to trade at a premium valuation to peers. Track record of delivering renewable power projects on time and on budget We highlight that since 2010, INE has completed 9 projects (in addition to acquisitions of already operating facilities) bringing substantially all of them to commercial operations on time and largely on budget (and under budget in some cases). More recently, Innergex completed construction of the Tretheway Creek Hydro Project $8.0 mln under budget and reduced the budget for the 4 projects under construction by $28 mln. We believe this strong track record of successfully guiding projects from development, through construction, to commercial operations positions the company well to deliver on future accretive expansion. We also highlight the company s strong First Nations relationships as facilitating access to additional attractive renewable power opportunities. Attractive growth project pipeline Innergex currently has 5 projects under construction totaling 341 MW of gross capacity which, once complete, will increase the company s total capacity to 1,660 MW, or 26% above current levels. Of these five projects, three are hydroelectric and two are wind farms. Looking forward, INE s prospective pipeline stands at 3,530 MW largely composed of wind projects as well as hydro while the company also now has 100 MW of potential development projects in France. We believe Innergex s ability to source attractive renewable power projects is underappreciated and will serve the company well in the long run. We also highlight INE s recent entry into the France with an acquisition of 8 wind projects with a gross 131 MW of capacity and a development agreement with local wind developers for projects totaling over 100 MW. We take a positive view of France as a jurisdiction for wind power development given significant targeted renewable power expansion and supportive government policies. Consistent with the above noted capacity additions we estimate Innergex s EBITDA will increase an average of 30+%/yr in each of 2016 and 2017 rising from $184 mln in 2015 to $316 mln in Robust forecast FCF growth from projects under construction We expect Innergex s free cash flow to post impressive gains over our forecast horizon, rising 47% between from $74 mln in 2015 ($0.71/sh) to $90 mln in 2016 ($0.84/sh) and $109 mln in 2017 ($1.01/sh). As a result, we forecast INE s dividend holding at $0.64/share in 2016 (a level it was increased to as per an announcement on Feb-24-16) and forecast a dividend hike to an estimated $0.68/share in 2017 which equates to a payout ratio of 67% by our estimates. As this forecasted payout ratio is just below the low end of the company s targeted 70-80%, we believe there is implied upside to this forecasted dividend and, based on the company s current share price, this equates to a 5.0% yield. Strong, highly experienced, management team Led by President and CEO Michel Letellier, who has been with Innergex for almost 20 years, we regard INE s management team as among the best of the TSX-listed IPPs. Other members of Innergex s management team including CFO Jean Perron (with INE since 2003) and CIO Jean Trudel (since 2002) also boast long tenures with Innergex while the company s other senior management are also seasoned renewable power industry veterans. As noted above, INE s management team has built an attractive asset base through strong First Nations relationships (a good source of accretive projects) and rare hydroelectric construction know-how.

57 Canada Research Page 57 of 115 Company Overview Innergex Renewable Energy is a Canada-based independent power producer (IPP) focusing on renewable power from sources including run of river hydroelectric facilities, wind farms, and solar photovoltaic farms. The company develops, owns and operates renewable energy facilities in Quebec, Ontario, and BC in Canada, Idaho in the US, and throughout Northern France (after a recent acquisition) (see Exhibit 1). Founded in 1990, INE has total installed capacity of 1,319 MW across 42 different facilities (775 MW net) and is a pure-play renewable energy company weighted towards hydro assets (61% of gross capacity) (see Exhibit 2). These assets have a weighted average age of ~8 years (relatively new by IPP standards) and sell power under long term PPAs with a weighted average life of ~18 years (as of Dec-31-15). Innergex targets high quality long life contracted assets and currently has five sites under construction totaling 341 MW (217 MW net) of capacity of which three are hydro facilities and 2 are wind farms. In % of INE s revenues came from hydro assets while a further 23% were from wind and 7% from solar. Geographically, 54% of INE s gross capacity is located in Quebec, followed by BC at 33%, France at 8%, Ontario at 4%, and Idaho 1% (on a pro-forma basis after a recent acquisition in France). Innergex s stated strategy is to remain exclusively in renewable energy while looking to consolidate its leadership position in Canada, where it has strong relationships and numerous partnerships with First Nations and local communities. As noted above INE recently expanded into France and continues to actively pursue projects in certain international markets such as Europe, Mexico and Peru where demand for renewable energy is strong. Exhibit 1: Innergex Geographical Footprint Source: Innergex Renewable Energy, Inc.

58 Canada Research Page 58 of 115 Exhibit 2: Innergex Pro-Forma Capacity by Source (LHS), Pro-Forma Geographic Exposure (RHS) Operating Facilities - Pro-Forma Gross Capacity* Pro-Forma Geographic Exposure* Solar 4% France, 8% Idaho, 1% Ontario, 4% British Columbia, 33% Wind 35% Hydro 61% Quebec, 54% *Includes projects under construction Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Share Ownership As of Apr Innergex had 104 mln common shares outstanding of which 42% are owned by institutional shareholders and 2% are owned by management/insiders (see Exhibit 3). We note, after adjusting for the company s recent $50 mln private placement with Desjardins we add a further 3.9 mln shares bringing the company s pro-forma fully diluted share count to 111 mln shares. Traded on the TSX, the stock has an average daily volume of 181.6K shares. Exhibit 3: Innergex Shareholder Summary (as at Apr-15-16) Shareholder Summary Largest Institutional Holders # Shares (mlns) % Outstanding 1832 Asset Mgmt % Caisse de dépôt et placement du Québec % Manulife Asset Mgmt % TD Asset Mgmt % The Vanguard Group % BMO Global Asset Mgmt % Other Institutional % Total Institutional % Insiders Largest Insider Holders # Shares (mlns) % Outstanding Michel Letellier (CEO & President, Director) % François Hébert (SVP) % Richard Blanchet (SVP) % William Lambert (Director) % Total Insider % Total Common Shares O/S Source: Capital IQ, Raymond James Ltd. Public & Other 56% Insiders 2% Institutional 42%

59 Canada Research Page 59 of 115 Growth Strategy New foothold in France with wind acquisition On Mar Innergex announced the acquisition of a portfolio of 8 wind farms in France from WPD Europe GMBH for a total purchase price of $137 mln ( 93 mln). This portfolio includes 7 operating wind farms with a combined capacity of 87 MW and a 44 MW project under construction with an expected commissioning in 1Q17 (see Exhibit 4). Located primarily in Northern France, these assets feature fully contracted revenues with EDF (A+ credit rating) and SICAE Oise (not rated) with an average remaining PPA term of 13 years and have an average asset age of 2 years. Consistent with INE s M&A strategy, we regard these as low-risk, high quality assets. Separately from this portfolio, Innergex also entered into a partnership with local wind developers S.E.M. and DRC to develop wind projects totaling 100 MW in France. In addition to the $137 mln purchase price INE will assume $178 mln of project level debt (projected by 2017). Innergex estimates the portfolio will generate a run rate of $35 mln in revenues and $28 mln in adjusted EBITDA as of 2017 and has a IRR in the 8-10% range. The company intends to hedge exchange rate exposure on cash flows associated with the project. The purchase price is to be funded by $88 mln ( 60 mln) in cash up-front for the 7 operating assets, a fully reimbursable $15 mln ( 10 mln) deposit for the project under construction (note: INE assumes no construction risk with this project as it will close once the seller has brought it to commissioning) and a $34 mln ( 23 mln) additional amount payable on commissioning of the construction project. The financing will include $72 mln from Innergex ( 49 mln), of which $50 mln will come via a private placement of common shares with the Desjardins Group (3.9 mln common $12.86/share), $50 mln from a Canadian Pension Fund ( 34 mln) to be completed post-closing at a premium to INE s entry price and $15 mln ( 10 mln) from a French Infrastructure Fund (also post-closing) (see Exhibit 5). The acquisition of the 7 operating facilities is expected to close by the end of Apr-2016 while the project under construction is targeting a 1Q17 close. Innergex will own 68% of these assets while the Canadian pension fund will receive a 32% stake. We take positive view of this as we consider France to be an attractive jurisdiction for wind power development given supportive government policies (attractive feed-in-tariff system) and significant targeted increase in renewable power corresponding to a reduction in nuclear power. We see this high quality portfolio of wind assets as representing a foothold for Innergex in France, which we understand the company intends to be a platform for the next stage of the company s growth. We also note company commentary suggests that now that INE has obtained critical mass in France there exists the opportunity to add on smaller wind assets in the future. In terms of valuation, we believe the implied 2017 EV/EBITDA multiple is reasonable at 11.25x while we estimate the project is a modest 2% accretive to 2017 FCF/share. Exhibit 4: Innergex Wind Farm Acquisition - France Portfolio Map Project Operating Gross Capacity (MW) COD PPA Expiry Off- Taker Off-Taker Credit Rating Porcien EDF A+ Longueval EDF A+ Antoigne EDF A+ Vaolttes EDF A+ Binas EDF A+ Park P EDF A+ Bois des Cholletz SICAE Oise Not Rated Total Operating 86.8 Construction Yonne EDF A+ Total Source: Innergex Renewable Energy, Inc.

60 Canada Research Page 60 of 115 Exhibit 5: INE French Wind Acquisition - Financing Uses (in mlns) C$ Equity in Operating Projects Deposit for Construction Project Payment Upon COD of Construction Project E Non-recourse Debt Total Enterprise Value Sources (in mlns) Innergex Investment Cdn. Pension Fund Investment French Infrastructure Fund Mezz. Debt E Non-Recourse Debt Total Funding Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Including the project under construction included in the above noted French acquisition, Innergex currently has five projects under construction, two of which are expected to be complete by the end of 2016 while the other three are expected to be complete in the first half of 2017 (see Exhibit 6). With a total gross capacity of 341 MW and a combined total cost of over $1 bln these projects will increase the company s gross installed capacity by 26% to 1,660 MW. With PPA terms for the three hydro projects of 40 years each and the wind projects at years, the addition of these assets will increase the company s weighted average PPA term which was already the longest in our coverage universe at ~18 years. Reflecting the impact of these new facilities as well as the France acquisition which is expected to contribute a $28 mln EBITDA run rate, we now forecast 2017 EBITDA of $316 mln and FCF of $109 mln. Exhibit 6: Innergex Construction Project Pipeline Project Location Gross Capacity Ownership Net Stake (%) Capacity Hydro Est. Construction Cost PPA Term (Yrs) Expected In- Service Boulder Creek BC % Q17 Upper Lillooet River BC % Q17 Big Silver Creek BC % Q16 Wind Mesgi'g Ugju's'n (MU) QC % Q16 Yonne France % Q17 Total Source: Innergex Renewable Energy, Inc., Raymond James Ltd. We also believe Innergex plans to submit proposals relating to a Large Renewable Procurement (LRP) in Ontario which is expected to commence in late 2016 which the company believes may include 300 MW of wind power and 150 MW of solar power. In Quebec, Innergex also sees opportunities arising from the recent issuance of a 200 MW block of wind energy to the Innu First Nation. Outside Canada, Innergex recently announced a memorandum of understanding with the Comisión Federal de Electricidad in Mexico to study renewable energy project opportunities in Mexico with the potential for joint development particularly small hydroelectric plants with capacity of less than 200 MW. Consistent with recent company commentary we believe INE is doing considerable work in attempting to expand in Mexico and could use the recent French acquisition as a platform for increased growth in Europe. The company remains open to the potential for M&A in Canada as well.

61 Canada Research Page 61 of 115 First Nations relationships & hydroelectric development know-how a key competitive advantage We believe the key factors behind Innergex s attractive hydro-heavy asset base include strong First Nations relationships and relatively rare hydroelectric development expertise. We understand the company s willingness to partner with local First Nations groups has facilitated the sourcing of subsequent opportunities as these groups have been able to refer to INE s previous partners for comfort on proceeding on a given project. Moreover, we believe Innergex s expertise in developing hydro assets is rare in North America, and represents a durable competitive advantage. This is something that is particularly important as a hydro project s costs are weighted more towards the construction of the project (~70%), while the equipment to be installed makes up the remaining ~30%. This contrasts with wind and solar projects where these proportions are reversed and installation of wind turbines or solar panels can by sourced by a number of third party developers. INE s prospective project pipeline currently stands at 3,530 MW worth of projects that are in the preliminary stages including a strong pipeline of numerous potential projects in partnership with First Nations. Exhibit 7: Innergex Prospective Project Pipeline Composition Solar 2% Hydro 28% Wind 70% Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Strong record of delivering projects on-time and on-budget Since the beginning of 2010, Innergex has successfully completed construction and commenced commercial operations on 9 projects of which 7 were either on or under budget and all of which completed on time. In fact, we note the only two instances where the company saw a project go over initial estimates (Montage Séche and Gros-Morne I where INE had a 38% stake) the original cost estimates were revised upward for the indices included in the turbine supply agreements (which were indexed to the Canadian & US CPI, the USD/CAD exchange rate, and a Canadian steel index). However, the respective PPAs for these projects provided for an upward adjustment to the selling prices which were based on similar indices resulting in revenues and EBITDA associated with these projects being revised upward as well. More recently, Innergex completed construction of the Tretheway Creek Hydro Project $8.0 mln under budget and reduced the construction budget for the 4 projects under construction by $28 mln. Thus, we take a positive view of INE s track record of delivering on renewable energy construction projects which gives us conviction the company can deliver on current projects and guidance.

62 E 2017E C$ mlns MW Canada Research Page 62 of 115 Exhibit 8: Innergex Project Commissioning Track Record On-Time? On Budget? Capacity (MW) Type COD Revenues (C$ mlns) Adj. EBITDA (C$ mln) LTA (GWh- Net) Ownership Tretheyway Creek Yes Under 21.2 Hydro Oct % Kwoiek Creek Yes On 49.9 Hydro Jan % Northwest Stave River Yes On 17.5 Hydro Dec % Viger-Denoville Yes Under 24.6 Wind Nov % Gros-Morne II Yes Under 111 Wind Nov % Stardale Yes On 33.2 Solar May % Montagne Séche Yes Over* 22.2 Wind Nov % Gros-Morne I Yes Over* 38.2 Wind Nov % Fitsimmons Creek Yes Under 7.5 Hydro Jan % * Overrun due to pricing terms of turbine purchase agreement, offset by increased revenues/ebitda as per PPA terms. Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Financial Analysis & Outlook France acquisition, projects under construction to drive EBITDA growth in 2016 and 2017 We expect additions to Innergex s fleet of generating assets both via acquisition and project completions will drive robust growth in revenue and EBITDA over our forecast horizon. Specifically, these new facilities include the 21.2MW Tretheway Creek Hydro facility in BC in commissioned in Oct-2015 (with expected annual production of 81 GWh), the acquisition of a 51% stake in the Walden Hydro facility (8.2 MW net) and the more recent announcement of the acquisition of 87 MW across 7 operating wind farms in France (expected to close 2Q16) results will also see a contribution from the Big Silver Creek (Hydro) in 3Q16. Therefore, we forecast INE s total power generation increasing 14% to 3,402 GWh in 2016 from 2,988 GWh in Looking to 2017, we anticipate the commencement of 3 more projects under construction (including the recently acquired 44 MW Yonne wind farm in France) during 1H17 as well as a full year contribution from assets acquired/commissioned in 2016 to result in a further 31% y/y generation growth to 4,469 GWh. Accordingly, we expect the company s revenues will also see growth in 2016 accelerating into 2017 rising 15% y/y in 2016 and 41% y/y in We estimate this will drive EBITDA of $211 mln in 2016 (up 15% y/y) and $316 mln in 2017 (up 50% y/y) (see Exhibit 9). Exhibit 9: Innergex Revenue and EBITDA (LHS) and Gross Installed Capacity (RHS) E 2017E Revenues EBITDA Gross Installed Capacity Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Rising FCF points to dividend hike in 2017 Consistent with the above noted EBITDA growth, we expect INE s FCF will also increase, rising from $74 mln in 2015 ($0.71/sh) to $90 mln in 2016 ($0.84/sh) and $109 mln in 2017 ($1.01/sh). As a result, we forecast INE s dividend holding at $0.64/share in 2016 (a level it was increased to as per an announcement on Feb-24-16) before a forecasted increase to $0.68/share in 2017 which equates to a payout ratio of 67% by our estimates. As this forecasted payout ratio is just below the company s targeted 70-80% range, we see potential for upside to this forecasted dividend.

63 Canada Research Page 63 of 115 Exhibit 10: Innergex Operating and Financial Performance Summary Table E 2017E Gross Capacity (MW) Consolidated Generation (GWh) 2,962 2,988 3,402 4,469 Financial Summary 15% 50% Total Revenue Gross Profit Gross Profit (%) 83% 83% 81% 85% Adj. EBITDA FCF Net Income FCF/Share EPS (0.63) (0.37) Dividends Paid Dividend/Share Payout Ratio 88% 86% 74% 67% Adj. Net Debt - End of year Forecast* 1,670 2,109 2,469 2,493 *Adjusted for minority ownership share of project debt Source: Innergex Renewable Energy, Inc., Raymond James Ltd. Minimal exposure to interest rate volatility As at the end of 2015 INE had almost 100% of total debt essentially secured at fixed rates via hedging including the company s project level debt and the majority of the company s revolving term credit facility (which is secured by INE s wholly owned assets). These measures insulate the company from the potential for rising interest rates, locking in the majority of interest expenses as well as securing the IRRs on projects under construction. As for future potential projects, PPA rates typically adjust for prevailing interest rates and financing can therefore still be hedged to produce an attractive, low risk IRR. Balance sheet solid With a pro-forma 2016E net debt/cap of 60%, a 2017E EBITDA/interest ratio of 2.8x, strong expected FCF growth and the company s aforementioned minimal exposure to interest rates we regard Innergex s financial footing as solid. We also note the company has an investment grade BBB- (S&P) credit rating and maintains access to capital markets both debt and equity. As such we believe the company as abundantly capable of funding its growth profile. Innergex maintains a $425 mln revolving line of credit which the company uses to bridge timing differences between construction expenditures and financing needs thus allowing the company the flexibility raise equity and project level financing under favourable conditions. Supported by INE s 13 unencumbered assets, the company s revolving credit line has a maturity in 2019, no scheduled repayment, and a 90% fixed interest rate through interest rate swaps equating to an average all-in interest rate of 5.45%. As of December 31, 2015 the facility carried a balance of $245 mln. Looking for 1Q16 modestly ahead of consensus Looking to 1Q16 earnings season, we note we expect results modestly ahead of consensus for Innergex. Specifically, our 1Q16 EBITDA estimate of $37.9 mln is just above the street average of $36.8 mln while our EPS estimate of ($0.04) is inline with consensus. More important than these earnings, in our view, will be updates on INE s 5 projects under construction. In fact, given the long term contracted nature of INE s assets we ascribe minimal importance to quarterly earnings and believe commentary as to the company s growth prospects will have a much greater impact of the share price. Capital allocation plans include dividend hikes, NCIB, further potential M&A Aside from a relatively small base-line level of investment necessary in greenfield project expenses to prepare for future RFPs INE also intends to grow its existing dividend as FCF rises, targeting a payout ratio of 70-80%. The company also recently renewed its NCIB which now expires Mar-2017 that allows for the purchase and cancellation of up to 2.0 mln common shares. As discussed above, INE also considers further potential M&A transactions as a use of capital.

64 2017E EBITDA Canada Research Page 64 of 115 Valuation & Recommendation Initiating coverage with an Strong Buy rating and $16.25 target price We apply a 14x 2017E EV/EBITDA to our $316 mln 2017 EBITDA estimate in arriving at our $16.25 target price. While a premium to the peer group average of 10.6x we note this target multiple is in-line with the midpoint of the company s 5-year trading range at 14x. We attribute this premium to Innergex s highly stable, long life asset base and attractive growth profile. We also note our target price is based on our 2016E adjusted net debt estimate of $2,469 mln which adjusts for the minority shareholder interest in INE s joint ventures. Alternatively, we note our target price also equates to a 4.2% target dividend yield based on our 2017 forecasted dividend of $0.68/share. Innergex stock currently has a dividend yield of 4.7%, however, as the company s projects under construction continue to advance, and are accordingly de-risked we believe the company s dividend will decline due to share price appreciation. With a total return to target of 24% and what we regard as the lowest risk profile in our coverage universe, we arrive at our Strong Buy rating. Exhibit 11: Independent Power Producer Comp Table ` 4/19/2016 North American Power Producer Comp Table Recent Market Net Total Net 2017E Dividend Ticker Price Target Return Shares Cap Debt EV Debt EBITDA EV/EBITDA Target Yield Company Symbol Rating 4/18/2016 Price* (%) o/s ($ mln) ($ mln) ($ mln) (%) 2014A 2015A 2016E 2017E 2015A 2016E 2017E EV/EBITDA (%) Atlantic Power Corporation* TSX:ATP - $ 3.31 $ % ,043 47% x 9.7x 9.5x 5.8x 0.0% Boralex Inc. TSX:BLX Outperform $ $ % 65 1,053 1,528 2,425 0% x 9.4x 8.8x 10.5x 3.5% Brookfield Renewable Energy Partners LP* NYSE:BEP Outperform $ $ % 276 8,069 9,745 23,383 42% 1,139 1,177 1,872 1, x 12.5x 11.7x 13.0x 6.1% Capital Power Corporation TSX:CPX Market Perform $ $ % 96 1,719 1,563 3,799 41% x 8.2x 8.3x 8.5x 8.2% Etrion Corporation* TSX:ETX - $ 0.33 $ % % x 17.1x 14.0x 11.1x 0.0% Innergex Renewable Energy Inc. TSX:INE Strong Buy $ $ % 108 1,468 2,340 3,958 59% x 18.7x 12.5x 14.0x 4.7% Maxim Power Corp.* TSX:MXG - $ 2.95 $ % % x 9.2x 5.8x 6.6x 0.0% Northland Power Inc. TSX:NPI Outperform $ $ % 171 3,591 5,274 3, % x 7.5x 5.4x 17.9x 5.2% Pattern Energy Group Inc.* NASDAQ:PEGI Outperform $ $ % 75 1,523 1,676 4,187 40% x 13.2x 11.0x 12.0x 7.5% TransAlta Renewables Inc. TSX:RNW Outperform $ $ % ,191 67% x 3.1x 2.8x 10.5x 7.0% Averages 13.1x 10.9x 9.0x 11.0x 4.1% *Note: Atlantic Power, Maxim Power, and Etrion Corp. not covered by Raymond James Ltd - estimates and target price reflect Capital IQ consensus average. Pattern Energy and Brookfield Renewable Energy covered by Raymond James Ltd. Analyst Frederic Bastien. Source: Capital IQ, Company Reports, Raymond James Ltd. Exhibit 12: Innergex Theoretical Equity Value Sensitivity Table Innergex Theoretical Equity Value Sensitivity to Assumed Multiple & EBITDA Estimate Assumed EV/EBITDA Multiple Source: Raymond James Ltd.

65 Canada Research Page 65 of 115 Appendix I: Financial Statements Exhibit 13: Innergex Income Statement ( E, $ mln unless otherwise noted) Income Statement Fiscal Year E 2017E Filing Currency: CAD Revenue Other Revenue Total Revenue Selling General & Admin Exp Depreciation & Amort Other Operating Exp. (COGS & Proj. Development) Total Operating Exp Operating Income Interest Expense, Total (84.1) Interest and Invest. Income Net Interest Exp. (84.1) Other Non-Operating Inc. (Exp.) (132.1) EBT Excl. Unusual Items (110.7) (8.7) Other Unusual Items (0.5) EBT Incl. Unusual Items (111.3) (63.2) Income Tax Expense (26.9) (12.0) Earnings from Cont. Ops. (84.4) (48.4) Minority Int. in Earnings Net Income (54.9) (31.1) EPS (0.63) (0.37) $ 0.25 $ 0.47 Source: Innergex Renewable Energy, Inc., Raymond James Ltd.

66 Canada Research Page 66 of 115 Exhibit 14: Innergex Balance Sheet ( E, $ mln unless otherwise noted) Fiscal Year E 2017E Filing Currency: CAD ASSETS Cash And Equivalents Accounts Receivable Other Receivables Accounts Receivable, Total Prepaid Exp Loans Receivable Current Restricted Cash Other Current Assets Total Current Assets Net Property, Plant & Equipment 1, , , ,688.2 Goodwill Other Intangibles Long-term Investments Deferred Tax Assets, LT Deferred Charges, LT Other Long-Term Assets Total Assets 2, , , ,690.4 LIABILITIES Accounts Payable Accrued Exp Curr. Port. of LT Debt Curr. Income Taxes Payable Other Current Liabilities Total Current Liabilities Long-Term Debt 1, , , ,701.0 Def. Tax Liability, Non-Curr Other Non-Current Liab., Total Total Liabilities 2, , , ,023.9 Total Pref. Equity Common Stock Additional Paid In Capital Retained Earnings (466.3) (567.8) (474.3) (483.1) Treasury Stock Comprehensive Inc. and Other Total Common Equity Minority Interest Total Equity Total Liabilities And Equity 2, , , ,690.4 Source: Innergex Renewable Energy, Inc., Raymond James Ltd.

67 Canada Research Page 67 of 115 Exhibit 15: Innergex Cash Flow Statement ( E, $ mln unless otherwise noted) Fiscal Year E 2017E Filing Currency: CAD Net Income (54.9) (30.3) Depreciation & Amort Other Amortization Total Asset Writedown (Income) Loss on Equity Invest Stock-Based Compensation Change in Non-Cash W/C (13.1) (29.7) 0.6 Change in Other Net Operating Assets (0.2) Other Operating Activities 72.4 (111.7) Cash from Ops Capital Expenditures (230.4) (325.3) (200.0) (12.0) Sale of Property, Plant and Equipment Cash Acquisitions (38.4) - (351.0) (150.0) Total Other Investing Activities 0.3 (229.6) - - Cash from Investing (268.4) (554.8) (551.0) (162.0) Net Debt Issued Issuance of Common Stock Repurchase of Common Stock - (12.3) - - Common Dividends Paid (48.1) (54.5) (67.1) (71.0) Pref. Dividends Paid (7.1) (7.1) (7.1) (7.1) Total Dividends Paid (55.3) (61.6) (74.2) (78.1) Other Financing Activities (3.0) (21.5) - - Cash from Financing Foreign Exchange Rate Adj Net Change in Cash 20.3 (13.9) (17.1) 63.4 Source: Innergex Renewable Energy, Inc., Raymond James Ltd.

68 Canada Research Page 68 of 115 Appendix II: Management Team Michel Letellier, CEO President, Non Independent Director First joining Innergex in 1997 in the position of VP-Finance, Mr. Letellier was appointed EVP and CFO in 2003 and then President and CEO in October Mr. Letellier s prior roles include several positions of increasing responsibility at Boralex Inc. (from ) and well as being part of the Corporate Finance Group at Brault, Guy, O Brien Inc. Mr. Letellier holds a Bachelor of Commerce from the Université du Québec à Montréal and a Master of Business Administration from Université de Sherbrooke. Jean Perron, CFO Mr. Perron first joined Innergex in December 2003 assuming the role of Vice President and Treasurer and was later appointed CFO in Mr. Perron s prior roles include positions of increasing responsibility at accounting firm KPMG for 13 years where his last role was as Senior Manager in taxation for numerous private and public companies. Mr. Perron holds a Bachelor of Business Administration from Université du Québec à Montréal and has been a Chartered Accountant and a Certified Management Accountant since Jean Trudel, CIO First joining Innergex as VP Corporate Development in 2002 Mr. Trudel was named VP-Finance the following year and later appointed CIO and SVP-Communications in May Mr. Trudel s prior roles include Director, Investment Project Finance for Quebec and Atlantic Canada at Sun Life Assurance Company of Canada and three years in the Corporate Banking Group at Bank of Nova Scotia. Mr. Trudel holds a Bachelor of Business Administration (Finance) degree from HEC Montréal and a Master of Business Administration degree from Queen s University. Renaud de Batz, SVP, Hydroelectric Project Management Mr. de Batz joined Innergex in 2002 as Project Manager before being appointed VP Hydroelectric Development in 2005 and then his current role as SVP, Hydroelectric Project Management in Mr. de Batz s prior roles include more than 12 years at RSW Inc. in positions of increasing responsibility, lastly as Project Director and Specialist. Mr. de Batz s education includes a Master of Science (Geology) degree from Université de Marseille, and a Master of Business Administration degree from Université du Québec à Montréal. He is also a member of the APEGBC as a Professional Geoscientist. Richard Blanchet, SVP Development, Western Canada and Latin America Mr. Blanchet joined Innergex in 2001 and was appointed to his position as SVP Western Region as of In February 2015 he also assumed the role of SVP-Development, Western Canada and Latin America. Mr. Blanchet s prior roles include specialist and project manager at RSW for over 13 years. In terms of education, Mr. Blanchet holds a Master of Science degree and a Bachelor of Civil Engineering degree, both from Université Laval and is also a member of the Ordre des Ingénieurs du Québec, and a member of the Association of Professional Engineers and Geoscientists of British Columbia. Peter Grover, SVP Wind and Solar Project Management Joining Innergex in 2005 as VP-Project Management, Mr. Grover was later appointed SVP-Project Management in 2011 and then VP- Wind and Solar Management in Mr. Grover s prior positions include more than 20 years at Alstrom in positions of increasing responsibility. Mr. Grover holds a Bachelor of Electrical Engineering degree from Concordia University and has been a member of the Ordre des Ingénieurs du Québec. François Hébert SVP, Operations and Maintenance Mr. Hébert joined Innergex in 1999 as VP- Operations and Maintenance and was later appointed SVP-Operations and Maintenance in Prior to his time at Innergex he worked at Alstrom for 12 years in positions of increasing responsibility. He holds a diploma in Electronics from Cégep de Sherbrooke and a diploma in instrumentations and controls from Cégep du Vieux-Montréal.

69 Canada Research Page 69 of 115 Risks Ability to identify and acquire or develop attractive growth opportunities Part of Innergex s strategy includes expanding its fleet of renewable power assets either by development or acquisition. Should the company have difficulty finding or executing on such projects going forward this would negatively impact the business. Financing and interest rate risk Consistent with Innergex s goal of expanding, the company may from time to time require cash for new projects which would come from either operational cash flows or external sources such as raising additional equity or debt on public markets. The inability to source sufficient cash by these methods to expand and maintain Innergex s business represents a risk of this strategy. In addition, increased interest rates on the company s floating rate facilities or difficulties in refinancing existing debt could arise, materially impacting the business. Innergex also has certain financial restrictions and debt covenants as part of its existing loan/security agreements which, if not met by the company, could result in issues in refinancing debt or sourcing sufficient liquidity to withstand downturns in the business. Similarly, the company s dividend could also be reduced or eliminated should the company s business enter a downturn of some kind. Liquidity risks related to derivative financial instruments From time to time Innergex employs the use of derivative contracts to hedge exposure to foreign exchange rates, interest rates and other uncertainties. Failure on the part of the counterparties to these contracts could have a material negative impact on the business. Variability of renewable energy sources The fuel for Innergex s renewable power facility generally comes in the form of wind, solar irradiation or hydrology each of which are variable both seasonally and on a daily basis. A lack of water flow, wind, or sun availability could negatively impact the company s revenues. Delays and cost overruns of construction projects Innergex has numerous current and future renewable power facilities under construction as part of its ongoing business. As such, delays, cost overruns, or mechanical breakdowns would have a negative impact on the business. Moreover, until such time as these facilities are up and running, there exists a risk that they may not run as predicted by management, or face unexpected regulatory issues/costs. Health and safety risk Should any of the employees working either operating or building Innergex s facilities be injured, this could result in fines, orders to remedy unsafe conditions, increased compliance costs or issues with licenses/permits required to operate these facilities. In addition, failure to ensure the safety of these facilities could result in the company being in contravention of environmental, health, and safety laws, or face civil liability. Permitting risk In order to build and run its power facilities Innergex requires certain licenses and permits including environmental approvals. Failure, or material delays in receiving these permits/licenses could materially impact the business. Performance of facilities in relation to PPAs The power purchase agreements Innergex signs with the local electrical utilities require that the company deliver a certain amount of power. If the facility is unable to generate sufficient power either due to operational or other issues, the company may incur financial penalties under the terms of the PPAs. In addition, as PPAs expire there exists a risk that due to competition or other reasons, Innergex may not be able to renew its PPAs on attractive terms, or at all.

70 Canada Research Page 70 of 115 Northland Power Inc. April 21, 2016 NPI-TSX David Quezada CFA Independent Power Producers Duo of World Class Offshore Wind Projects to Send Shares North Company Report - Initiation of Coverage Outperform 2 C$25.00 target price Recommendation We are initiating coverage of Northland Power (NPI) with an Outperform rating and $25.00 target price. Our bullish stance is a function of the company s considerable nearterm expansion via large scale, world class offshore wind projects in Europe which we expect will drive robust EBITDA and FCF growth. While shares of Northland have appreciated significantly of late, we believe the full valuation implications of these projects, as well as a corresponding shift to renewable power in the company s asset mix is considerable - and yet to be fully reflected in the company s share price. Analysis Transformational offshore wind projects under construction With a combined net capacity of 642 MW and targeted commercial operation in 2017, we regard Northland s Gemini and Nordsee One offshore wind projects as transformational. Once complete, Northland s asset mix will shift from predominately gas-fired to over 50% renewable-based (mostly wind and some solar). We expect this transition will result in NPI garnering an increased trading multiple and see successful completion of these projects as positioning NPI well for future accretive offshore wind projects. Growth profile in a league of its own According to management guidance, the Gemini and Nordsee One projects will generate a combined EBITDA run rate of mln (C$ mln) which, when layered onto our 2016 estimate of $519 mln and assuming a full year contribution from the Grand Bend wind project equates to an EBITDA run rate of $ mln in 2018 a 32% CAGR over We believe this places Northland s growth profile in a league of its own. Rising FCF to drive increased dividend We currently forecast NPI s 2017 FCF at ~$259 mln, or $1.51/share which implies a payout ratio of 71% based on the current dividend well below 2016 s estimated 104%. Perhaps more importantly, by late 2017 (once Gemini and Nordsee One reach commercial ops) NPI s free cash generation will be such that, should the board elect to, the company could significantly increase its dividend. Alternatively, given the company s strong track record of capital deployment we believe these cash flows could also be used to fund future accretive offshore wind projects. Strong management team and insider ownership Led by CEO John Brace, who has been with NPI since 1988 and CEO since 2005, the company s management team has more than 250 years of combined experience and an average tenure of 14 years at Northland. In addition, Chairman James Temerty owns ~33% of NPI, part of an overall 35% management/insider ownership position aligning management interests with shareholders. Valuation Our price target of $25.00 is based on a 14x 2017E EV/EBITDA, a premium to the 10.6x independent power producer peer group average target multiple (see Exhibit 12) due to NPI s robust growth profile. Current Price ( Apr ) C$21.00 Total Return to Target 24% 52-Week Range C$ C$14.45 Suitability Medium Risk/Growth Market Data Market Capitalization (mln) C$3,591 Current Net Debt (mln) C$5,274 Enterprise Value (mln) C$9,150 Shares Outstanding (mln, f.d.) Day Avg Daily Volume (000s) 325 Dividend/Yield C$1.08/5.1% Key Financial Metrics 2015A 2016E 2017E P/E EV/EBITDA NM 21.8x 16.4x 22.8x 17.6x 12.6x FCF/Share C$1.09 C$1.04 C$1.51 Net Debt (%) 58% Company Description Northland Power is an indepdent power producer with operations in Canada, the Netherlands and Germany. After the completion of 2 large wind farms in the North Sea and another in Canada the company will have over 2.0 GW of net capacity. EPS 1Q 2Q 3Q 4Q Full Revenues EBITDA Mar Jun Sep Dec Year (mln) (mln) 2015A C$(0.20) C$0.76 C$(0.54) C$0.05 C$0.16 C$728 C$ E E , Source: Raymond James Ltd., Thomson One

71 Canada Research Page 71 of 115 Table of Contents Investment Overview Company Overview Growth Strategy Financial Analysis & Outlook Valuation & Recommendation Appendix I: Financial Statements Appendix II: Management Team Risks... 86

72 Canada Research Page 72 of 115 Investment Overview World class offshore wind projects under construction With a total gross capacity of 600 MW, the Gemini project, once complete, will be the second largest wind farm in the world, while Nordsee One at 332 gross MW is another large-scale, world class project, in our view. Once completed, these two projects, plus the 50 MW (net) Grand Bend wind project will bring Northland s net capacity to just over 2 GW a ~50% increase from current levels. We believe success in bringing these ambitious projects to commercial operations positions Northland as a leading global developer and operator of large wind power and bodes well for the future development of the Nordsee Two and Three (later this decade). Moreover, as these projects are now well underway we believe NPI will be able to turn its focus to additional growth opportunities. We see this pipeline of large-scale offshore wind power projects as unique among our coverage universe, placing Northland s growth profile in a league of its own. Transition to renewables-based asset mix We note, looking at relative valuations among the Independent Power Producers, those with a greater proportion of renewable power capacity typically garner a material premium, trading at an EV/EBITDA x higher than that of fossil fuel based power producers. We believe this makes intuitive sense given the expected government support for renewable power vs. the regulatory risk faced by greenhouse gas (GHG) emitting fossil fuel based generation (most notably coal). While NPI s existing thermal assets are largely gas-fired (significantly less GHG intensive than coal) we believe the ongoing transition from 30% renewable power capacity in 2015 to 54% in 2018 will lead to an expanded trading multiple for NPI over time. NPI management is targeting 61% of EBITDA from offshore wind and 76% from renewable sources by 2018, which compares to 28% from renewables in Growth profile in a league of its own Looking to 2018, according to management guidance, the Gemini and Nordsee One projects will generate a combined EBITDA run rate of mln (C$ mln). When layered onto our 2016 estimate of $519 mln (which compares to management s $ mln 2016 guidance range and includes some precompletion revenues from Gemini) and adjusting for a full year contribution from the Grand Bend Wind Project and a near-term PPA expiry equates to EBITDA of $ mln. Thus, while the stock has appreciated considerably recently, we believe the valuation implications of this transition are profound, and yet to be fully reflected in the share price Robust FCF Growth Expected Driven by the significant cash flows from projects under construction, we estimate NPI s FCF will increase 42% over while FCF/share grows from $1.09/share in 2015 to $1.51/share in We expect this will result in a declining payout ratio and potentially an increased dividend in late 2017 once each of the Gemini and Nordsee One projects reach commercial operations. In fact, assuming a constant dividend we forecast Northland s payout ratio declining to ~71% in 2017 and below 50% in We believe the FCF potential once the two offshore wind projects are complete could reach $3.00/share, which, should the company s board of directors elect to, could support a dividend of as much as $ /share (vs. $1.08/sh currently). Alternatively, given the company s strong track record of capital deployment we believe these cash flows could also be used to fund future accretive offshore wind projects. Strong management team and insider ownership Led by CEO John Brace, who has been with NPI since 1988 and CEO since 2005, the company s management team has more than 250 years of combined experience and an average tenure of 14 years at Northland. In addition, Chairman James Temerty owns ~33% of NPI, part of an overall management/insider stake of 35%. Thus, we believe management s interests are aligned with shareholders and we take a positive view of the company s seasoned management team.

73 Canada Research Page 73 of 115 Company Overview Northland Power is a developer, owner, and operator of gas and renewable power facilities located primarily in Canada and Europe. The company produces electricity from assets including clean-burning natural gas, as well as wind, solar and biomass. In business since 1987, Northland was one of Canada s first independent power producers and now maintains 1,338 MW of net total capacity with a further 1,052 MW (692 MW net) under construction. 98% of the company s current revenues come in the form of long term power contracts which maintain a weighted average remaining life of 14.1 years. Key growth initiatives for the company include 2 large offshore wind projects in Europe located in the North Sea including a 60% stake in Gemini, a 600 MW offshore wind project and an 85% stake in Nordsee One, a 332 MW offshore wind project. In Canada, Northland is also in the process of building a 100 MW onshore wind farm in Grand Bend, ON, in which it maintains 50% ownership stake. As illustrated in Exhibit 1 below, these large projects under construction will significantly alter Northland s asset mix and geographical footprint, with a greater future weighting towards renewable power assets and greater proportional presence in Europe. Northland estimates the project cost for the European offshore wind projects at 4 bln with an expected commissioning in 2017 while the Grand Bend wind farm has a project cost of C$384 mln. Exhibit 1: Northland Power Geographical Footprint Source: Northland Power Inc.

74 Canada Research Page 74 of 115 Exhibit 2: Northland Power Operating Facilities Project Location Size (MW) Ownership Stake (%) Technology PPA Term Gas Term Thorold ON, CA Nat. Gas cogeneration Kingston ON, CA Nat. Gas combined cycle 2017* 2017 Iroquois Falls ON, CA Nat. Gas cogeneration 2021* 2021 Spy Hill SK,CA Nat. gas peaking plant 2036 n/a^ Kirkland Lake ON, CA ** Biomass and nat. gas combined cycle and peaking Mont Louis QC,CA Wind 2031 n/a Jardin d'éole QC,CA Wind 2029 n/a Kavelstorf and Eckolstadt Germany Wind n/a*** n/a Roof Top Solar ON, CA 2 75 Solar 2031 n/a North Battleford SK,CA Nat. Gas combined cycle 2033 n/a^ Ground-Mount Solar Sites (#1-13) ON, CA % 90 MW, 62.5% (40 MW) Solar n/a McLean's Mountain ON, CA Wind 2034 n/a * Facilities have option to extend power contracts. **Northland has an effective 77% residual economic interest ***German electricity production is purchased by local power utilities at predetermined prices as required by German legislation ^SaskPower effectively assumes all natural gas-price risk under the long-term PPA Source: Northland Power Inc. Share Ownership As of Apr there were 171 mln shares of Northland Power outstanding of which roughly one third is owned by institutional, insider and other holders respectively. We highlight NPI s large proportion of insider ownership, most notably Chairman James Temerty (33%), represents ~35% of NPI stock a strong vote of confidence in our view. Among institutional holders, RBC Global Asset Management, Sentry Select, and CI Investments are the largest holders at 5.9%, 3.1% and 2.3% respectively. We note shares of Northland have a 3 month average daily trading volume of 477K shares. Assuming full dilution of Northland s outstanding convertible debentures the company has mln fully diluted shares outstanding. Exhibit 3: Northland Power Shareholder Summary (as at Apr-15-16) Shareholder Summary Largest Institutional Holders # Shares (mlns) % Outstanding RBC Global Asset Mgmt % Sentry Select Capital Corp % CI Investments % Mackenzie Financial Corp % BMO Global Asset Mgmt % Guardian Capital % Other Institutional % Total Institutional % Insiders Largest Insider Holders # Shares (mlns) % Outstanding James C.M. Temerty (Chairman) % John Brace (CEO) % Salvatore Mantenuto (Vice Chairmain and COO) % Dino Gliosca % Total Insider % Total Common Shares O/S Source: Capital IQ, Raymond James Ltd. Public & Other 37% Institutional 27% Insiders 35%

75 Canada Research Page 75 of 115 Track record of delivering projects on time and on budget As highlighted in Exhibit 4 below, Northland has a strong track record of delivering a broad range of power projects on time and on budget. We note since 1997 the company has developed 11 projects with a total of 1,253 MW of capacity and total construction costs of $2.6 bln, each of which were either under or on budget (on average these projects were under budget by 3%). We note the third phase of the Groundmounted solar projects, not included in the table below, resulted in litigation as Northland cancelled the EPC contract with H.B. White Canada Corp. (White) for default of White s obligation to build the Cochrane solar project. This case is currently going through the arbitration process, however, given White s financial condition we understand the odds of NPI recovering anything financially are minimal. Northland was able to complete this project on time with a new developer; however, the company did see a negative financial impact of ~$115 mln. Nevertheless, we see this as the lone exception to what is a very strong track record of project development. We believe this strong track record bodes well for the North Bend, Gemini, and Nordsee One projects which are each currently on time and on budget. Exhibit 4: Northland Power Construction Track Record On or Under Budget Project COD Location Budget (C$ Actual (C$ Size (MW) mlns) mlns) (Y/N) Iroquois Falls cogen plant 1997 ON Y Y Iroquois Falls gas turbine replacement 2003 ON Y Y Kirkland Lake peaker facility 2004 ON Y Y Mont Miller wind farm 2005 QC Y Y Jardin d'éole 2009 QC Y Y Thorold cogen facility 2010 ON Y Y Mont Louis wind farm 2011 QC Y Y Spy Hill peaker facility 2011 SK Y Y North Battleford facility 2013 SK Y Y Ground-mounted solar Phases I & II 2013 ON Y Y McLean's Mountain wind farm 2014 ON Y Y Source: Northland Power Inc., Raymond James Ltd. On Time? (Y/N) Growth Strategy Grand Bend Wind Project Located in Southern Ontario, Northland has a 50% stake in the Grand Bend project in partnership with two local First Nations groups and has an expected capacity of 100 MW at an estimated project cost of $384 mln. Revenues for the facility are secured via a 20 year feed in tariff agreement with the Ontario Independent Electricity System Operator. Construction progress on the project to date includes 28 of 40 turbines now fully installed while turbine commissioning is now underway providing interim revenues from several turbines. In addition, as of Jan-2016 NPI had achieved full energization of the switching station, 32 km transmission line, and the main transformer and reactor station. Completion of Grand Bend is expected in near the end of 3Q16 ($301 mln of the total projected budget of $384 mln has been spent) with an expected EBITDA contribution of $11-14 mln in 2016 as per management guidance. A modest delay has occurred due to the anticipated late delivery of turbines by the vendor something Northland expects to be partially compensated for and the project remains on budget. Gemini Offshore Wind Project Once complete, NPI s Gemini offshore wind project in the Netherlands will be the largest wind farm in the North Sea and the second largest wind farm in the world with a total capacity of 600 MW (2 wind farms x 300 MW) consisting of 150 turbines. Northland has a 60% stake in the project (360 MW) which has a total expected project cost of 2.8 bln with other partners including Siemens (20%), Van Oord (10%) and HVC (10%). Utilizing a 2 contract project structure, Siemens will construct and erect Gemini s turbines while Van Oord will build the balance of the wind farm. Gemini s commercial operation date is slated for 2017 and the revenues for the project are secured via a 15 year fixed price contract with the Dutch

76 Canada Research Page 76 of 115 Government. Important construction milestones for the Gemini Project thus far include cable manufacturing, installation and testing, the completion of turbine foundation installations as well as the onshore and offshore substations. Turbine installation has now commenced with the project s first two wind turbines installed as of Feb As of the most recent update 2 bln has been incurred of the total 2.8 bln total estimated project costs. The project remains on time and on budget and first power to shore from the project came online in late Feb NPI expects stable cash flows from Gemini due to a proven wind resource in the North Sea which is expected to facilitate a high capacity factor with average wind speeds of 10 m/s, subject to some seasonal variability (lower daily production during the spring and summer months and greater production during the fall and winter). Meanwhile, the fixed price contract with the Dutch government that tops up market based revenues to arrive at a constant price of 169/MWh and 15 year largely fixed operations and maintenance contracts (subject to annual escalation tied to indices) also support stable cash flows for the project. NPI expects the project to generate mln in EBITDA annually (or C$ mln at current exchange rates). We note, NPI has hedged the cash flows from Gemini at an attractive rate of C$1.67/ which, while not running through the EBITDA line, will boost cash flows and returns on the project. Nordsee One Offshore Wind Project NPI has an 85% interest in the 332 MW Nordsee One Offshore Wind Project located in the North Sea (Germany). The project has a total expected capital cost of 1.2 bln and will be developed in partnership with RWE Innogy, which maintains a 15% stake. With an expected commercial operations date in 2017, project revenues will come via a 10 year fixed price feed-in-tariff while a 10 year contract for operations and maintenance with Senvion will lock in the majority of costs. In terms of construction progress, NPI recently announced that the installation of all 54 turbine foundations including monopiles and transition pieces was successfully completed 6 weeks ahead of schedule. Looking ahead, installation of the inter-array cables and offshore substation is set to begin in coming months while turbine installation will occur in early 2017 with first power also coming later that year. NPI has hedged the revenues from Nordsee at C$1.51/ and expected revenues of equate to an expected EBITDA of C$ mln. The project remains on time and on budget. NPI also has the rights to develop two additional projects (Nordsee Two and Three) over the next decade with total capacity of 670 MW. These projects are expected to go to RFP in early 2017 and, while they will face competition, each of these projects enjoy the benefit of early permitting being in place placing them in favourable position vs. other bidders. In general, while competition for offshore wind projects continues to increase, we believe Northland maintains a first mover advantage in the sector that also positions the company well for future projects. Exhibit 5: Northland Projects under Construction Grand Bend - Onshore Wind Source: Northland Power Inc., Raymond James Ltd. Gemini Nordsee One Location S. Ontario North Sea, North Sea, Netherlands Germany Capacity (MW) (2 sites X 300 MW) 332 Project Cost $384 mln 2.8 bln 1.2 bln Northland Ownership (%) 50% 60% (360 MW) 85% Power Contract Fixed price Feed in 20 yrs (Feed in Fixed Price 15 yr PPA Tariff subsidy (10 Tariff) w/dutch Government years) COD A company in transition As illustrated in Exhibit 6 below, once Northland s projects under construction are complete, the company s footprint will be altered significantly. We highlight the company s existing operational capacity includes 70% thermal, 21% wind and 9% solar. This will change to 48% wind, 46% thermal and 6% solar once Gemini, Nordsee One, and Grand Bend are all complete. In fact, referring to Exhibit 7 below, NPI management is targeting 61% of EBITDA

77 Canada Research Page 77 of 115 from offshore wind and 76% from renewable sources by Given our preference of renewable-weighted power producers we take a positive view of this transition which, augmented by the company s increased scale at this point, will lead to an expanded trading multiple over time, in our view. More importantly, according to management guidance, the Gemini and Nordsee One projects will generate an EBITDA run rate of $ mln, which, including other adjustments, when layered onto our 2016 estimate of $519 mln equates to EBITDA of $ mln. Thus, while the stock has appreciated recently, we believe the valuation implications of this transition are profound, and have yet to be fully reflected in the share price. Exhibit 6: Northland Power Asset Mix and Geographical Footprint Current and After Projects Under Construction Current Operating Asset Breakdown Solar 9% After Projects Under Construction Solar 6% Wind 21% Wind 48% Thermal 46% Thermal 70% Current Operating Asset Breakdown Germany 2% After Projects Under Construction Germany 15% The Netherlands 18% Canada 98% Canada 67% Source: Northland Power Inc., Raymond James Ltd. Exhibit 7: Northland Power EBITDA Breakdown Objectives Onshore Wind, 13% 2015 Original NUGs, 31% 2018E Original NUGs, 6% Thermal, 18% Solar, 15% Solar, 8% Thermal, 41% Offshore Wind, 61% Onshore Wind, 7% *Based on management objectives Source: Northland Power Inc., Raymond James Ltd.

78 Canada Research Page 78 of 115 Financial Analysis & Outlook Strong EBITDA and FCF growth over our forecast horizon Looking to 2016 we expect Northland will see increased revenues and EBITDA as several projects either come on line, or came on line at some point during 2015 and will make a full contribution for Specifically, NPI s last 4 ground mounted solar projects were completed 4Q15 and will fully contribute in 2016 while the Grand Bend wind farm will also come in line the latter half of As result, we estimate power generation at 5,837 GWh (up 11% y/y) and another 19% to 6,945 GWh in 2017 as the company s offshore wind projects continue to ramp up. We note, according to management guidance, the ground mounted solar facilities will add an incremental $15-18 mln in EBITDA for 2016 while Grand Bend will add a further $11-14 mln (which represents roughly half a year of operations). In addition, NPI management expects initial pre-completion revenues from the Gemini offshore wind project will boost EBITDA by an estimated mln in Representing a partial offset, lower rates for the baseload gas-fired portion of the company s Kirkland Lake facility and higher expected development expenditures at NPI s international operations will negatively impact EBITDA in Taking into account of all these impacts we estimate 2016 EBITDA for Northland of $519 mln, just above the mid-point of management s $ mln guidance range and up 29% y/y. Looking to 2017, we expect a full year contribution from Grand Bend as well as commercial operations at Gemini and later Nordsee One will result in EBITDA rising a further 40% to $725 mln, or an 80% increase over 2015 levels. By 2018 Northland management expects Gemini and Nordsee One to generate EBITDA of mln or C$500-C$550 based on recent FX rates (note cash flows from these projects are hedged at C$1.67/ and C$1.51/ respectively but will flow through NPI s financials separately). Looking for in-line 1Q16 results Looking to 1Q16 results, (NPI reports May 11, after market) we are looking for results broadly in line with current street estimates for Northland. Specifically, our 1Q16 EBITDA estimate of $100.9 mln is slightly below consensus of $102.9 mln while our EPS estimate is in line with consensus at $0.13. We expect the more important elements of NPI s earnings release will center around an update on the Gemini and Nordsee One projects and suspect the market will ascribe minimal importance to backward looking results, particularly in light of robust expected earnings growth. Exhibit 8: Northland Power Operating & Financial Summary Table E 2017E End of Yr. Capacity (MW) 1,345 1,338 1,488 2,030 Power Generation (GWh) 5,064 5,245 5,837 6,945 Average Revenue per MWh Financial Summary Total Revenue ,123.1 EBITDA - Thermal EBITDA - Renewable EBITDA - Managed Projects EBITDA - Offshore Wind (1.4) (1.7) EBITDA - Corporate (24.5) (17.7) (31.5) (36.0) Adj. EBITDA FCF Net Income (177.5) FCF/Share EPS $ (1.21) $ 0.16 $ 0.97 $ 1.28 Dividend/Share $ 1.08 $ 1.08 $ 1.08 $ 1.16 Payout Ratio 95% 98% 104% 77% Balance Sheet Cash Adj. Net Debt - End of year Forecast* 2, , ,884 5,210 Source: Raymond James Ltd.

79 E 2017E 2018E Run Rate* E 2017E 2018E Run Rate* GWh MW Capacity C$ mlns C$ mlns Canada Research Page 79 of 115 Exhibit 9: Northland Power Capacity and Power Generation Growth (LHS), Revenue and EBITDA Growth (RHS) 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, ,500 2,000 1,500 1, , EBITDA CAGR = 32% 1,400 1,200 1, Power Generated (GWh) - LHS Capacity (MW) - RHS EBITDA Revenues *2018E Run rate assume completion of all projects under construction Source: Raymond James Ltd., Northland Power Inc. Cash flows from projects under construction to reduce payout ratio NPI currently pays an attractive $1.08/share dividend ($0.09/month) which equates to a 5.1% dividend yield (modestly below the 5.6% average of dividend paying IPPs in our coverage universe). While we estimate NPI s payout ratio will be modestly north of 100% in 2016 at 104%, we see it falling to the low 70% range in 2017(assuming the current dividend) or 77% in 2017 based on our 2017E dividend of $1.16/share. We note, this is consistent with management s historical strategy which has seen the payout ratio rise above 100% purposely during periods of investment in growth projects before falling back to more normalized levels. Referring to Exhibit 10, NPI s payout ratio was well above 100% from as the company s North Battleford, Spy Hill and Ground-mounted Solar projects were built, before falling just below 100% during 2013 and We note a similar cycle is playing out currently with the Grand Bend, Gemini and Nordsee One projects underway. Beyond 2018, we believe NPI s increased diversification both in terms of asset mix and geographical distribution of assets will provide greater dividend security than the company has seen in a decade. As such, while our forecasted dividend is more conservative, we would not be surprised to see a potentially significant dividend increase as soon as late 2017/early As noted above, we believe, should Northland s board elect to, the company could sustain a dividend of $ /share. However, we also highlight NPI s strong track record of capital deployment and also believe these cash flows could be used to fund future accretive offshore wind expansion. Exhibit 10: Northland Historical Payout Ratio Source: Northland Power Inc.

80 Canada Research Page 80 of 115 Balance sheet solid With an adjusted 2016E net debt/cap of 53% and a 2017 EBITDA/interest ratio of 3.0x, we regard NPI s debt load as abundantly manageable and its balance sheet as solid. We forecast NPI s net debt/ebitda ratio falling throughout our forecast horizon from 9.4x in 2016 to 7.2x in 2017 to ~5.6x in 2008 based on our estimate of the company s 2018 EBITDA run rate as the company s projects under construction are completed. Moreover, NPI maintains a BBB stable credit rating from S&P and has 98% of revenues locked in via long term contracts with creditworthy counterparties. After adjusting for projects under construction, NPI maintains a weighted average remaining PPA term of 13.6 years, or, factoring in the extension options at Kingston and Iroquois Falls, this measure rises to 14.1 years (see Exhibit 11). Potential impact of near-term PPA expiries We note the PPA relating to NPI s Kingston facility expires in Jan-2017 at which time it may be renewed upon request by Kingston for a further 60 month term. However, this extension is subject to the negotiation of a new PPA which is somewhat uncertain. Our estimates currently reflect a PPA renewal, albeit at materially lower rates reducing cash flows associated with the facility by ~75%. While Kingston represented 13% of NPI s 2015 EBITDA, given the company s forecasted expansion we see this proportion falling to 10% in 2016 and 8% in 2017 before commercial operations of Gemini and Nordsee One will further reduce this relative impact to ~5-6% of consolidated EBITDA in Moreover, we believe the reduced cash flows relating to this PPA expiry are well understood and widely expected. Beyond this, NPI s nearest term PPA expiry is at Iroquois Falls in Dec Iroquois Falls represented 15% of NPI s 2015 EBITDA; however, by the time this PPA expires we expect the impact will be significantly less. Exhibit 11: North Power Remaining PPA Terms Source: Northland Power Inc.

81 2017E EBITDA Canada Research Page 81 of 115 Valuation & Recommendation Initiating coverage with an Outperform rating and $25.00 target price Our $25.00 target is based on a 14.0x 2017E EV/EBITDA, which is a premium to the 10.6x peer group average target multiple due to NPI s robust FCF growth profile and ongoing transition to a more renewableweighted asset mix. While we use 2017 as our valuation basis, we note our current target implies a 2018 EV/EBITDA of 10.75x much more in line with our peer group average target multiple of 10.6x. For valuation purposes we adjust NPI s net debt by excluding the minority interest share of net debt (we estimate adjusted net debt of $4.9 bln as at 2016 year-end) and assume conversion of the company s convertible debentures for a share count of mln. Alternatively, we note our $25.00 price target equates to a 4.6% 2017 dividend yield based on our estimated $1.16 dividend per share payout in 2017, below the 5.6% average of dividend paying renewable power producers in our coverage universe again reflecting Northland s attractive growth profile. With construction now at a relatively advanced stage we regard the Gemini and Nordsee One projects as largely de-risked, however as initial cash flows from the projects commence in 2016 and build throughout 2017 we expect shares of NPI will see a lift from reduced perceived execution risk. We also believe a late 2017 dividend increase, as well as any news on the status of the Nordsee 2 and 3 projects (a longer term development) will result in a lift to Northland shares. As a result, we are initiating coverage with an Outperform rating and $25.00 target price which equates to a 24% total return. Exhibit 12: Independent Power Producer Comp Table ` 4/19/2016 North American Power Producer Comp Table Recent Market Net Total Net 2017E Dividend Ticker Price Target Return Shares Cap Debt EV Debt EBITDA EV/EBITDA Target Yield Company Symbol Rating 4/18/2016 Price* (%) o/s ($ mln) ($ mln) ($ mln) (%) 2014A 2015A 2016E 2017E 2015A 2016E 2017E EV/EBITDA (%) Atlantic Power Corporation* TSX:ATP - $ 3.31 $ % ,043 47% x 9.7x 9.5x 5.8x 0.0% Boralex Inc. TSX:BLX Outperform $ $ % 65 1,053 1,528 2,425 0% x 9.4x 8.8x 10.5x 3.5% Brookfield Renewable Energy Partners LP* NYSE:BEP Outperform $ $ % 276 8,069 9,745 23,383 42% 1,139 1,177 1,872 1, x 12.5x 11.7x 13.0x 6.1% Capital Power Corporation TSX:CPX Market Perform $ $ % 96 1,719 1,563 3,799 41% x 8.2x 8.3x 8.5x 8.2% Etrion Corporation* TSX:ETX - $ 0.33 $ % % x 17.1x 14.0x 11.1x 0.0% Innergex Renewable Energy Inc. TSX:INE Strong Buy $ $ % 108 1,468 2,340 3,958 59% x 18.7x 12.5x 14.0x 4.7% Maxim Power Corp.* TSX:MXG - $ 2.95 $ % % x 9.2x 5.8x 6.6x 0.0% Northland Power Inc. TSX:NPI Outperform $ $ % 171 3,591 5,274 3, % x 7.5x 5.4x 17.9x 5.2% Pattern Energy Group Inc.* NASDAQ:PEGI Outperform $ $ % 75 1,523 1,676 4,187 40% x 13.2x 11.0x 12.0x 7.5% TransAlta Renewables Inc. TSX:RNW Outperform $ $ % ,191 67% x 3.1x 2.8x 10.5x 7.0% Averages 13.1x 10.9x 9.0x 11.0x 4.1% *Note: Atlantic Power, Maxim Power, and Etrion Corp. not covered by Raymond James Ltd - estimates and target price reflect Capital IQ consensus average. Pattern Energy and Brookfield Renewable Energy covered by Raymond James Ltd. Analyst Frederic Bastien. Source: Capital IQ, Company Reports, Raymond James Ltd. Exhibit 13: Northland Power Theoretical Equity Value Sensitivity Table Northland Power Theoretical Equity Value Sensitivity to Assumed Multiple & EBITDA Estimate Assumed EV/EBITDA Multiple Source: Raymond James Ltd.

82 Canada Research Page 82 of 115 Appendix I: Financial Statements Exhibit 14: Northland Power Income Statement ( E, $ mln unless otherwise noted) Income Statement Fiscal Year E 2017E Filing Currency: CAD Total Revenue ,123.1 Ops. and Maintenance Selling General & Admin Exp Depreciation & Amort. - Total Other Operating Exp Total Operating Exp Operating Income Net Interest Exp. (350.5) (107.2) Currency Exchange Gains (Loss) 0.6 (2.4) - - Other Non-Operating Inc. (Exp.) (47.2) (93.4) 12.0 (22.0) EBT Excl. Unusual Items (187.7) Impairment of Goodwill (0.9) (12.7) - - Gain (Loss) on Sale of Invest. (3.1) Asset Writedown (41.3) (8.1) - - Other Unusual Items - (6.4) - - EBT Incl. Unusual Items (233.0) Income Tax Expense (55.5) (12.5) Earnings from Cont. Ops. (177.5) Diluted EPS (0.82) 0.16 $ 0.97 $ 1.28 Source: Northland Power Inc., Raymond James Ltd.

83 Canada Research Page 83 of 115 Exhibit 15: Northland Power Balance Sheet ( E, $ mln unless otherwise noted) Balance Sheet Balance Sheet as of: E 2017E Filing Currency: CAD ASSETS Cash And Equivalents Accounts Receivable Inventory Prepaid Exp Restricted Cash Other Current Assets Total Current Assets Net Property, Plant & Equipment 3, , , ,887.9 Goodwill Other Intangibles Long-term Investments Accounts Receivable Long-Term Deferred Tax Assets, LT Deferred Charges, LT Other Long-Term Assets Total Assets 4, , , ,321.4 LIABILITIES Accounts Payable Curr. Port. of LT Debt Other Current Liabilities Total Current Liabilities Long-Term Debt 3, , , ,454.2 Def. Tax Liability, Non-Curr Other Non-Current Liab., Total Total Liabilities 3, , , ,738.6 Common Stock 1, , , ,419.3 Additional Paid In Capital Retained Earnings (1,319.7) (1,524.6) (1,557.3) (1,549.0) Comprehensive Inc. and Other (31.6) Total Common Equity Minority Interest Total Equity 1, , , ,582.7 Total Liabilities And Equity 4, , , ,321.4 Source: Northland Power Inc., Raymond James Ltd.

84 Canada Research Page 84 of 115 Exhibit 16: Northland Power Cash Flow Statement ( E, $ mln unless otherwise noted) Cash Flow Fiscal Year E 2017E Filing Currency: CAD Net Income (106.6) Depreciation & Amort., Total (Gain) Loss On Sale Of Invest Total Asset Writedown Change in Non Cash Operating Assets - Net (54.8) 15.1 Other Operating Activities Cash from Ops Capital Expenditures (1,814.6) (1,936.4) (1,500.0) (825.0) Sale of Property, Plant and Equipment Cash Acquisitions (37.8) (84.2) - - Deferred Charges (46.0) (73.3) - - Total Other Investing Activities 89.6 (154.6) Cash from Investing (1,808.9) (2,237.7) (1,498.0) (823.0) Net Debt Issued 1, , , Issuance of Common Stock Common Dividends Paid (115.3) (137.9) (183.7) (197.3) Other Financing Activities (145.7) (142.0) (142.0) Cash from Financing 1, , Foreign Exchange Rate Adj. (26.8) Net Change in Cash 55.0 (41.5) (108.4) 74.6 Source: Northland Power Inc., Raymond James Ltd.

85 Canada Research Page 85 of 115 Appendix II: Management Team John Brace, CEO With Northland since 1988, and CEO since 2005, Mr. Brace has held numerous roles within the company including positions in risk management, development, construction and operations. Mr. Brace is also Chair and President of the Association of Power Producers of Ontario and a member of the Electricity Conservation and Supply Task Force. Mr. Brace has a Bachelor of Science in Engineering Physics from Queen s University. Paul Bradley, CFO Mr. Bradley joined Northland as CFO in April His prior roles include Managing Director and Head of Power and Utilities (Corporate Finance) at Macquarie Capital Markets, VP-Electricity Resources at the Ontario Power Authority, Executive Director at CIBC s Global Power and Utilities Group and positions in development and finance at Duke Energy. Mr. Bradley is a graduate of Boston College. Sam Mantenuto, Vice Chair and COO Mr. Mantenuto s previous roles within Northland include Chief Development Officer during a period where Northland almost tripled their portfolio from 480 MW in 2009 to 1,329 MW in His prior roles include a 17 year career with Ontario Hydro in areas including power system operations, finance, regulatory hearings, the executive office and power marketing. Mr. Mantenuto s education includes an honours Bachelor of Science Degree in electrical engineering and an MBA from the University of Toronto. Mike Crawley, EVP-Development Mr. Crawley joined Northland in July 2015 in his current role as EVP-Development. His prior roles include CEO of AIM PowerGen where he led the company s growth from concept to one of the largest renewable power developers in Canada prior to the company being purchased by GDF Suez Canada, where he served as President. Mr. Crawley holds a Bachelor of Arts from the University of Western Ontario. Michael Shadbolt, VP & General Counsel Joining NPI in his current role in January 2011, Mr. Shadbolt s prior roles include 18 years as a partner at Macleod Dixon LLP and Borden Ladner Gervais LLP. During his career Mr. Shadbolt has focused on development of electricity and thermal generation projects. He holds a BA (economics) from McMaster University, an MA (economics), LLB and MBA from the University of Western Ontario and a LLM from Osgoode Hall Law School.

86 Canada Research Page 86 of 115 Risks Ability to identify and acquire or develop attractive growth opportunities Part of Northland s strategy includes expanding its fleet of renewable and gas powered assets either by development or acquisition. In some cases Northland must make some capital expenditures prior to a project reaching an advanced stage of development which could be lost should a project not go ahead. Should the company have difficulty finding or executing on such projects going forward this would negatively impact the business. Financing and interest rate risk Consistent with Northland s goal of expanding, the company may from time to time require cash for new projects which would come from either operational cash flows or external sources such as raising additional equity or debt on public markets. The inability to source sufficient cash by these methods to expand and maintain Northland s business represents a risk to this strategy. In addition, increased interest rates on the company s floating rate facilities or difficulties in refinancing existing debt could arise, materially impacting the business. Northland also has certain financial restrictions and debt covenants as part of its existing loan/security agreements which, if not met by the company, could result in issues in refinancing debt or sourcing sufficient liquidity to withstand downturns in the business. Similarly, the company s dividend could also be reduced or eliminated should the company s business enter a downturn of some kind. Currency risk As the company maintains international operations in Germany and The Netherlands, Northland can be exposed to the risk that the company s cash flows in Canadian dollar terms will be affected by fluctuations in Euro/CAD exchange rates or USD/CAD exchange rates. Liquidity risks related to derivative financial instruments From time to time Northland employs the use of derivative contracts to hedge exposure to foreign exchange rates, interest rates and other uncertainties. Failure on the part of the counterparties to these contracts could have a material negative impact on the business. Variability of renewable energy sources The fuel for Northland s renewable power facility generally comes in the form of wind, solar irradiation or hydrology each of which are variable both seasonally and on a daily basis. A lack of water flow, wind, or sun availability could negatively impact the company s revenues. Delays and cost overruns of construction projects Northland has numerous current and future renewable power facilities under construction as part of its ongoing business. As such, delays, cost overruns, or mechanical breakdowns would have a negative impact on the business. Moreover, until such time as these facilities are up and running, there exists a risk that they may not run as predicted by management, or face unexpected regulatory issues/costs. Health and safety risk Should any of the employees working either operating or building Northland s facilities be injured this could result in fines, orders to remedy unsafe conditions, increased compliance costs or issues with licenses/permits required to operate these facilities. In addition, failure to ensure the safety of these facilities could result in the company being in contravention of environmental, health, and safety laws, or face civil liability. Permitting risk In order to build and run its power facilities Northland requires certain licenses and permits including environmental approvals. Failure, or material delays in receiving these permits/licenses could materially impact the business. Performance of facilities in relation to PPAs The power purchase agreements Northland signs with the local electrical utilities require that the company deliver a certain amount of power. If the facility is unable to generate sufficient power either due to operational or other issues, the company may incur financial penalties under the terms of the PPAs. In addition, as PPAs expire there exists a risk that due to competition or other reasons, Northland may not be able to renew its PPAs on attractive terms, or at all.

87 Canada Research Page 87 of 115 Fuel supply, transportation & price Some of Northland s natural-gas fired facilities could be affected by the availability of stable fuel supply at reasonable prices. While these are generally factored into PPA agreements the mechanisms by which fuel costs are matched may fully remove this risk. The company is dependent on third party suppliers under natural gas supply agreements fulfilling their obligations. Operational risk As part of the normal course of business, Northland s facilities are subject to operational risk due to premature weak or failure of major equipment due to defects, materials, or workmanship. In some cases Northland also relies on third parties for operations and maintenance and therefore relies on these companies to fulfill their obligations. Labour relations A labour disruption or dispute, such as a strike or lockout could negatively impact Northland s operations as some of the company s facilities are unionized.

88 Canada Research Page 88 of 115 TransAlta Renewables Inc. April 21, 2016 RNW-TSX David Quezada CFA Independent Power Producers Accretive Drop-down Acquisitions to Fuel Dividend Growth Recommendation We are initiating coverage of TransAlta Renewables (RNW) with an Outperform rating and $13.50 target price. Our constructive stance is a product of the company s low risk core business, growth visibility via drop-down transactions from sponsor TransAlta Corp., strong EBITDA and FCF growth, attractive dividend yield with upside, and a relatively inexpensive valuation. Analysis Low risk core business with visibility on growth With fully contracted revenues, 15 year weighted average remaining PPA contract life and a diversified asset base we take a positive view of RNW s stable existing operations. Meanwhile, we continue to expect further drop-down transactions from majority shareholder TransAlta Corp. coming from 1.3 GW portfolio of already-identified potential assets RNW could end up with a stake in. Significant forecast EBITDA and FCF growth fuels dividend We currently forecast RNW s EBITDA improving an impressive 62% between while improved AFFO of $264 mln in 2016E (+32% y/y) and $327 mln in 2017E (+24% y/y) drives CAFD of $0.94/sh and $1.12/sh in 2016 and 2017 respectively. As such, we believe RNW is capable of meeting guidance of a 6-7% increase in the company s dividend (to $ /share) upon completion of the South Headland gas facility in mid Attractive valuation and dividend yield At 7.0% RNW sports a yield above the peer group average (currently at 6.0%) of dividend paying equities in the sector with upside based on company guidance of a 6-7% increase as of mid-2017 when the South Headland gas project comes on line. For reference, a $0.935/share dividend (the mid-point of guidance) and a 6.0% yield in-line with the peer group would imply a share price of just over ~$15.50/share. We also highlight that, at a 10.0x 2017E EV/EBITDA, RNW is trading at a discount to the 10.5x peer group average. Potential opportunities from Alberta Climate Leadership Plan With a planned phase-out of coal-fired electricity generation by 2030, we expect the Alberta Climate Leadership Plan will represent a significant opportunity for renewable power producers in the form of a large scale procurement of gas and renewable power projects. With roughly 6 GW of coal power generation capacity to be retired and indications it will be replaced by 2/3 renewables and 1/3 natural gas there will be large investments required in each of these areas. With a significant presence in Alberta already we regard RNW as well positioned to capitalize on this opportunity. Valuation Our $13.50 target is based on a 10.5x 2017E EV/EBITDA, in-line with the average target multiple of the independent power producers at 10.6x (see Exhibit 8). EPS 1Q 2Q 3Q 4Q Full Revenues EBITDA Mar Jun Sep Dec Year (mln) (mln) 2015A C$0.17 C$0.04 C$0.32 C$0.56 C$1.10 C$236 C$ E E Source: Raymond James Ltd., Thomson One Company Report - Initiation of Coverage Outperform 2 C$13.50 target price Current Price ( Apr ) C$12.52 Total Return to Target 15% 52-Week Range C$ C$8.99 Suitability Medium Risk/Growth Market Data Market Capitalization (mln) C$3,133 Current Net Debt (mln) C$795 Enterprise Value (mln) C$4,216 Shares Outstanding (mln, f.d.) Day Avg Daily Volume (000s) 243 Dividend/Yield C$0.88/7.0% Key Financial Metrics 2015A 2016E 2017E P/E EV/EBITDA 11.4x 16.1x 14.0x 16.2x 11.1x 10.0x FCF/Share C$1.08 C$0.94 C$1.12 Net Debt (%) 19% Company Description TransAlta Renewables is a Canadian Independent Power Producer with assets located in Canada, the US and Australia with total capacity of 2,470 MW across the company's wind, gas, and hydro power facilities

89 Canada Research Page 89 of 115 Table of Contents Investment Overview Company Overview Growth Strategy Financial Analysis & Outlook Valuation & Recommendation Appendix I: Financial Statements Appendix II: Management Team Risks

90 Canada Research Page 90 of 115 Investment Overview Low risk core business With fully contracted revenues maintaining a weighted average remaining contract life of 15 years and good diversification in terms of fuel source, counterparty and geographical location across RNW s 40 asset, 2,470 MW portfolio, we regard TransAlta Renewables core business as very stable. We note PPAs where TransAlta is the counterparty total 401 MW and we generally consider the company s PPA counterparties to be of high quality. Moreover, we note TransAlta Corp. also assumes much of the development and operational risks of RNW s portfolio and, in some cases, RNW maintains a financial (non-direct) ownership stake. Significant forecast cash flow growth We currently forecast RNW s EBITDA improving an impressive 62% between while improved AFFO of $264 mln in 2016E (+32% y/y) and $327 mln in 2017E (+24% y/y) drives CAFD of $0.94/sh and $1.12/sh in 2016 and 2017 respectively. Having already increased the dividend 3 times since the 2013 IPO, we believe RNW is capable of meeting guidance of a 6-7% increase in the company s dividend (to $0.93- $0.94/share) upon completion of the South Headland gas facility in mid In addition, we note these forecasts do not factor in additional acquisitions, something which could imply upside to our estimates. Growth outlook bolstered by drop-downs from sponsor TransAlta Corp. RNW has been highly active over the past year in acquiring assets via drop down transactions from sponsor, TransAlta Corp. driving strong gains in cash flow generation over our forecast horizon. In addition, we note TA/RNW has a pipeline of roughly 1.3 GW worth of assets identified as potential drop-down candidates which should support continued growth opportunities. We regard several of these assets, including ~800 MW of hydro power in Alberta, and 115 MW of wind assets in Canada and the US as a particularly good fit for RNW which would provide further diversification while positioning the company towards renewable fuel sources and potentially resulting in an increased trading multiple. We highlight, with ownership of ~64% of shares outstanding, TransAlta Corp. s interests are aligned with RNW s leading us to expect that future transactions will be accretive to RNW, as they have been in the past. Attractive valuation and dividend yield At 7.0% RNW already boasts a yield above the average of dividend paying equities in the sector with upside based on company guidance as of mid-2017 when the South Headland gas project comes on line. Given RNW s large, diversified, footprint and stable core business, we do not believe the elevated dividend yield will persist, and see the stock appreciating to the point where the dividend yield approaches the 6.0% group average. We note, a $0.935/share dividend (the mid-point of guidance) and a 6.0% yield would imply a share price of over ~$15.50/share. We also highlight that, at a 10.0x 2017E EV/EBITDA, RNW is trading at a discount to the 10.5x peer group average. Strong balance sheet With a 2016E net debt to cap of 25% (the lowest in our coverage universe), a 2016E net debt/ebitda of 2.8x and EBITDA/interest ratio of 7.8x we regard RNW s balance sheet as conservative, particularly in light of the company s high proportion of long term contracted revenues and sponsorship from parent company, TransAlta. We regard RNW as abundantly capable of funding current growth projects as well as additional drop-down opportunities from TA. Potential opportunities from Alberta Climate Leadership Plan While the Alberta CLP is a material risk for coal-fired generators in the province we expect renewable power producers will reap the benefit of a significant required procurement of green energy projects if provincial emissions targets are to be achieved. In fact, assuming the roughly 6 GW of coal power generation capacity that will be retired in Alberta by 2030 will be replaced by 2/3 renewables and 1/3 natural gas there will be significant investment required in each of these areas. Competitor Capital Power has noted that given a lower capacity factor, the equivalent of 4 GW of retired coal capacity in renewable energy terms equates to over 40 renewable power facilities at an estimated capital investment of $12 bln. One of the largest renewable independent power producers (IPP) in Alberta, we see RNW as very well positioned to make the most of this trend.

91 Canada Research Page 91 of 115 Company Overview Headquartered in Calgary, Alberta, TransAlta Renewables is a diversified developer owner and operator of renewable power generation facilities with a portfolio of assets consisting of wind, hydro, and natural gas facilities. In North America the company currently owns 18 wind facilities (1,249 MW), 13 hydroelectric (112 MW) and 1 natural gas facility (506 MW) while, in Australia, RNW was 6 operating gas-fired power plants with 425 MW capacity and another under construction (South Hedland) with 150 MW of capacity expected to come on line in mid-2017 (see Exhibits 1 & 2). Overall, RNW has ~2,320 MW currently operational which will rise to ~2,470 MW upon completion of the 150 MW South Hedland project. RNW also has a 43% stake in a 270 km natural gas pipeline in Australia. Founded in August 2013 as a spinoff of large diversified power producer TransAlta Corp. (TA), RNW was created as a vehicle to hold TA s renewable power facilities. RNW s assets are diversified geographically, located in Canada (British Columbia, Alberta, Ontario, Quebec, and New Brunswick) the US (Wyoming) and Western Australia (see Exhibit 1). Parent company TransAlta Corp. owns ~64% of RNW currently and, since RNW s IPO in 2013, the company has completed $2.4 bln in drop-down transactions (including South Hedland) representing RNW s primary method of growth. RNW maintains a long term contracted portfolio with a weighted average remaining contract life of 15 years. Exhibit 1: TransAlta Renewables Geographical Footprint Source: TransAlta Renewables Inc.

92 Canada Research Page 92 of 115 Exhibit 2: TransAlta Renewables Generation Asset Breakdown (LHS) and Corporate Structure (RHS) Gas- Australia (575 MW) 23% Gas - NA (506 MW) 21% Hydro (112 MW) 5% Wind (1,249 MW) 51% Source: TransAlta Renewables Inc., Raymond James Ltd. Share Ownership On a fully diluted basis we calculate there are currently mln shares of RNW outstanding of which TransAlta Corps owns ~64% including Class B shares that will convert to common shares once South Hedland reaches COD. Representing what we believe is a strong vote of confidence, Alberta Investment Management Company (AIMCO) owns ~8% of RNW having made a ~$200 mln investment in the company in Nov The stock maintains a 3 month average daily trading volume of ~380K shares/day. Exhibit 3: TransAlta Renewables Shareholder Summary (as at Apr-15-16) Shareholder Summary Largest Institutional Holders # Shares (mlns) % Outstanding Alberta Inv. Mgmt Co % TD Asset Mgmt % First Eagle Inv. Mgmt % RBC Global Asset Mgmt % Accrued Equities Inc % Hexavest Inc % Other Institutional % Total Institutional % Insiders Largest Insider Holders # Shares (mlns) % Outstanding Transalta Corp. (Common Shares) % Transalta Corp. (Class B) % Paul Jenkins % Brett Gellner (CEO, President & Director) % Allen Hagerman (Chairman) % Total Insider + Corporations % Total Common Shares O/S Source: Capital IQ, Raymond James Ltd. Aimco, 8.2% Public & Other, 23% Institutional, 5% Corporations (TransAlta Corp.), 64%