Innergex reports its 2017 fourth quarter and year-end results

WIND FARM ACQUISITIONS AND FACILITIES COMMISSIONING - DIVIDEND INCREASED BY 3%

• Board of Directors declares a dividend increase of $0.02 to $0.68 per common share on an annual basis.
• Annual revenues increased 37% to $400.3 million compared with last year.
• Annual Adjusted EBITDA rose 38% to $298.7 million compared with last year.
• Innergex completed its largest acquisition to date, Alterra Power Corp., for an aggregate consideration of $1.1 billion.

(All amounts are in Canadian dollars, except as noted.)

LONGUEUIL, QC, Feb. 21, 2018 /CNW Telbec/ - Innergex Renewable Energy Inc. (TSX: INE) ("Innergex" or the "Corporation") today released its operating and financial results for the fourth quarter and year ended December 31, 2017.

"Our list of achievements in 2017 is impressive. In addition to having reached commercial operation at two major hydro projects in British Columbia, we have significantly increased our presence in France through acquisitions and we have undertaken several development activities in Canada and internationally," said Michel Letellier, President and Chief Executive Officer of Innergex.

"With the acquisition of Alterra Power Corp. in the first quarter of 2018 and the combination of both talented teams, we are a strong renewable power producer with solid capabilities to seize numerous opportunities concurrently and to accelerate our growth in the United States, Canada and Europe," he added.

OPERATING RESULTS
Amounts shown are in thousands of Canadian dollars except as noted otherwise.	Three months ended December 31				Year ended December 31
	2017		2016		2017			2016
Power generated (MWh)	1,106,060		848,967		4,394,210			3,521,645
Long-term average (MWh) ("LTA")	1,133,041		838,051		4,763,836			3,364,907
Revenues	107,973		73,265		400,263			292,785
Adjusted EBITDA^1	80,059		50,264		298,728			215,983
Adjusted EBITDA Proportionate^1	83,199		51,495		308,343			224,368
Net earnings	3,513		8,765		19,668			32,043
Net earnings, $ per share - basic and diluted	0.05		0.08		0.22			0.28
					Year ended December 31
					2017			2016
Free Cash Flow^1					87,207			75,702
Payout Ratio^1					82		%	91	%

^1	Please refer to the Non-IFRS Measures Disclaimer for the definition of Adjusted EBITDA, Adjusted EBITDA Proportionate, Free Cash Flow and Payout Ratio.

Three-Month Period Ended December 31, 2017

During the three-month period ended December 31, 2017, the Corporation's facilities produced 1,106 GWh of electricity or 98% of the LTA of 1,133 GWh. Overall, the hydroelectric facilities produced 88% of their LTA due to challenging post-commissioning activities currently being addressed at the Upper Lillooet River facility and below-average water flows at most of the British Columbia facilities. The wind farms produced 108% of their LTA due to the above-average wind regime in Quebec and to compensation received from the manufacturer for non-availability of equipment at the Mesgi'g Ugju's'n facility, partly offset by the below-average wind regime in France. The solar farm produced 97% due to the average solar regime.

In the fourth quarter, the Corporation recorded revenues of $108.0 million compared with $73.3 million for three-month period ended December 31, 2016. This increase is attributable mainly to the contribution of the recently commissioned Mesgi'g Ugju's'n, Upper Lillooet River and Boulder Creek facilities as well as to the acquisition of the Montjean, Theil-Rabier, Yonne, Rougemont 1-2, Vaite, Plan Fleury and Les Renardières facilities. The increase was partly offset by lower production at most of the British Columbia hydro facilities. The Corporation recorded Adjusted EBITDA of $80.1 million compared with $50.3 million in 2016 mainly due to higher revenues net of expenses. The Corporation recorded Adjusted EBITDA Proportionate of $83.2 million compared with $51.5 million in 2016 due mainly to higher Adjusted EBITDA and a higher share of Adjusted EBITDA of joint ventures stemming from higher production and revenues at the Umbata Falls and Viger-Denonville facilities.

For the three-month period ended December 31, 2017, the Corporation recorded a net earnings of $3.5 million (basic and diluted net earnings of $0.05 per share), compared with net earnings of $8.8 million (basic and diluted net earnings of $0.08 per share) in 2016. The decrease is explained mainly by the $14.2 million increase in finance costs, the $8.9 million increase in depreciation and amortization and the $5.7 million decrease in income tax recovery. Net earnings were also impacted by the recognition of an unrealized net loss on derivative financial instruments compared with a gain for the three-months ended December 31, 2016, and to a lower share of earnings of joint ventures compared with the same quarter in 2016. These factors were partly offset by the $29.8 million increase in Adjusted EBITDA.

Electricity Production

During the year ended December 31, 2017, the Corporation's facilities produced 4,394 GWh of electricity or 92% of the LTA of 4,764 GWh. Overall, the hydroelectric facilities produced 93% of their LTA due mainly to lower production from challenging post-commissioning activities currently being addressed at the Upper Lillooet River facility and below-average water flows in British Columbia, partly offset by above-average water flows in Quebec and Ontario. The wind farms produced 91% of their LTA due to lower production from post-commissioning activities currently being addressed at the Mesgi'g Ugju's'n facility and below-average wind regimes in France. Wind regimes in France have lately trended well below the historical average, which explains the lower production. The solar farm produced 106% of its LTA due to an above-average solar regime. The 25% production increase over the same period last year is due mainly to the contribution of the facilities commissioned in 2016 and 2017 and the wind farms acquired in France in 2016 and in 2017 and to higher production at some of our Quebec and Ontario hydro facilities, which was partly offset by lower production at our British Columbia hydro facilities.

Revenues

For the year ended December 31, 2017, the Corporation recorded revenues of $400.3 million, compared with $292.8 million for the year ended December 31, 2016. This 37% increase is attributable mainly to the facilities commissioned in 2016 and 2017 and the wind facilities acquired in 2016 and 2017 in France as well as to higher production at all of our Ontario hydro facilities, which was partly offset by lower production at our British Columbia hydro facilities.

Adjusted EBITDA

For the year ended December 31, 2017, the Corporation recorded Adjusted EBITDA of $298.7 million compared with  $216.0 million last year. This increase of 38% is due mainly to production and revenues from new facilities, partly offset by higher operating expenses, general and administrative expenses and prospective project expenses. The Adjusted EBITDA Margin increased from 73.8% to 74.6% for the year due mainly to the increase in revenues net of expenses, partly offset by the payment related to water rights for 2011 and 2012 in British Columbia made in the first quarter of 2017.

Adjusted EBITDA Proportionate

For the year ended December 31, 2017, the Corporation recorded Adjusted EBITDA Proportionate of $308.3 million compared with $224.4 million last year. This 37% increase is due mainly to higher Adjusted EBITDA and a higher share of Adjusted EBITDA of joint ventures stemming from higher production at the Umbata Falls and Viger-Denonville facilities.

Net Earnings

For the year ended December 31, 2017, the Corporation recorded net earnings of $19.7 million (basic and diluted net earnings of $0.22 per share), compared with net earnings of $32.0 million (basic and diluted net earnings of $0.28 per share) in 2016. The $12.4 million decrease in net earnings is attributable mainly to this year's below-average production compared with last year's above-average production and to challenging post-commissioning activities currently being addressed at the Upper Lillooet River and Mesgi'g Ugju's'n facilities, which explains the decrease in net earnings as opposed to the increase in revenues. As a result, the $51.5 million increase in finance costs, the $39.1 million increase in depreciation and amortization and the $2.4 million increase in income taxes were only partly offset by the $82.7 million increase in Adjusted EBITDA, and the $2.1 million increase in share of earnings of joint ventures.

Free Cash Flow and Payout Ratio

For the year ended December 31, 2017, the dividends on common shares declared by the Corporation amounted to 82% of Free Cash Flow, compared with 91% last year. This positive change results mainly from the recent commissioning of the Mesgi'g Ugju's'n, Upper Lillooet River and Boulder Creek facilities and the acquisition of wind facilities in 2016 and 2017 which generated higher Free Cash Flow, partly offset by higher dividend payments as a result of the increase in annual dividend, higher number of common shares outstanding due to the issuance of 3,906,250 shares to three Desjardins Group-affiliated entities under a private placement of Innergex common shares in April 2016 and to additional shares following the exercise of stock options and issued under the Dividend Reinvestment Plan ("DRIP").

2017 HIGHLIGHTS

• On January 31, 2017, the $197.2 million non-recourse construction and term project financing closed by Big Silver Creek Power Limited Partnership on June 22, 2015, for the Big Silver Creek River run-of-river hydroelectric project, was converted into a 39.5-year term loan.
• On February 10, 2017, Innergex and Desjardins Group Pension Plan ("Desjardins") raised €8.5 million of subordinated debt from a French infrastructure fund through their French subsidiaries created for the acquisition of wind farms in France in April 2016. The subordinated loan carries an interest rate of 7.25% and has an eight-year tenor; its principal will be reimbursed at maturity.
• On February 21, 2017, Innergex completed the acquisition of the 44 MW Yonne wind farm located in northern France. This wind farm acquisition was announced simultaneously to the acquisition of seven wind farms in 2016. At the time, the facility was under construction and its acquisition was to be concluded once the commissioning was completed. The commissioning activities began in the fourth quarter of 2016 and were completed at the end of January 2017. The total purchase price amounts to €35.2 million ($49.0 million) subject to certain adjustments and includes €3.8 million ($5.3 million) of working capital. A €10.0 million ($13.9 million) deposit had already been provided by the Corporation when the acquisition was first announced in March 2016. Innergex owns a 69.55% interest in the wind farm and Desjardins owns the remaining 30.45%.
• On February 21, 2017, Innergex executed a Fifth Amended and Restated Credit Agreement of its then existing $425 million revolving credit facilities. These amendments give the Corporation flexibility in borrowing in euros using EURIBOR loans. The Corporation also extended its revolving term from 2020 to 2021 (except for one lender of $42.5 million, whose commitment remained in effect until 2020) to provide greater financing flexibility. Moreover, a Letter of Credit Facility of up to $30 million guaranteed by Export Development Canada (EDC) has been added and put in place. 
  
  On October 31, 2017, the Corporation announced that it had increased its revolving credit facilities by $50 million and added a new lender to the syndicate of lenders. It also extended the maturity of its revolving facility from December 2021 to December 2022 for all its lenders to provide greater flexibility.
  
  
• On May 24, 2017, Innergex completed the acquisition of three wind projects in France's Bourgogne-Franche-Comté region with an aggregate capacity of 119.5 MW. The equity's purchase price was approximately €51.4 million ($76.2 million), subject to certain adjustments. Innergex owns a 69.55% interest in the wind farms while Desjardins owns the remaining 30.45%.
• On August 15, 2017, Innergex announced that it has received approval from the Toronto Stock Exchange (TSX) to proceed with a normal course issuer bid on its common shares (the "Bid"). Under the Bid, the Corporation may purchase for cancellation up to 2,000,000 of its common shares, corresponding to approximately 1.84% of the 108,640,790 issued and outstanding common share of the Corporation as at August 14, 2017. The Bid commenced on August 17, 2017, and will terminate on August 16, 2018. 
  
  On November 14, 2017, the Corporation announced that it has received approval from the Toronto Stock Exchange (TSX) to implement an automatic purchase plan under the Bid. The Corporation has entered into an automatic purchase plan agreement with a designated broker to allow for purchases of its common shares during times when it would ordinarily not be permitted to do so due to self-imposed black-out periods or regulatory restrictions.
  
  
• On August 25, 2017, Innergex completed the acquisition of two wind projects in France's Champagne-Ardenne region with an aggregate capacity of 43 MW. The equity's purchase price was €27.4 million ($40.8 million), subject to certain adjustments. Innergex owns a 69.55% interest in the wind farms while Desjardins owns the remaining 30.45%.
• On October 30, 2017, the Corporation and Alterra Power Corp. announced that they had entered into an arrangement agreement pursuant to which Innergex would acquire at a price of $8.25 per share all of the issued and outstanding common shares of Alterra for an aggregate consideration of $1.1 billion, including the assumption of Alterra's debt (the "Alterra Transaction"). The Alterra Transaction was subject to approval by Alterra's shareholders and other customary closing conditions. Pursuant to the Transaction, Alterra shareholders would receive an aggregate consideration, which would consist of approximately 25% in cash and 75% in common shares of Innergex.
  
  On February 6, 2018, Innergex completed the Alterra Transaction.
  
  
• On November 27, 2017, the $311.7 million non-recourse construction and term project financing closed by Mesgi'g Ugju's'n (MU) Wind Farm, L.P. on September 24, 2015, for the Mesgi'g Ugju's'n wind farm was converted into a 19.5-year term loan.

DEVELOPMENT PROJECTS

Commissioning Activities

Les Renardières
In the fourth quarter, the Corporation began commercial operation of the 21.0 MW Les Renardières wind facility located in Champagne-Ardenne, France. Construction began prior to its acquisition by Innergex and was completed in November 2017. The Declaration of COD under the purchase agreement with EDF shows an effective commissioning date of November 18, 2017. The Les Renardières facility's average annual production is estimated to reach 52,427 MWh, enough to power more than 11,200 French households.

In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of approximately €4.4 million ($6.4 million) and €3.6 million ($5.3 million) respectively. All the electricity the facility produces is covered by an initial 15-year fixed-price power purchase agreement ("PPA") with EDF, with a portion of the price being adjusted according to inflation indexes.

Rougemont-2
In the fourth quarter, the Corporation began commercial operation of the 44.5 MW Rougemont-2 wind facility located in Bourgogne-Franche-Comté, France. Construction began prior to its acquisition by Innergex and was completed in November 2017. The Declaration of COD under the purchase agreement with EDF shows an effective commissioning date of December 1, 2017. The Rougemont-2 facility's average annual production is estimated to reach 100,340 MWh, enough to power more than 21,400 French households.

In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of approximately €8.4 million ($12.4 million) and €6.5 million ($9.6 million) respectively. All the electricity the facility produces is covered by an initial 15-year fixed-price PPA with EDF, with a portion of the price being adjusted according to inflation indexes. 

Construction activities

Flat Top 
The Flat Top wind project was acquired in the first quarter of 2018 as part of the Alterra acquisition. Construction was already under way at the time of the acquisition. 

As of the date of this press release, construction for the 200 MW wind farm continues on time and on budget, with all road construction, turbine foundations and collector lines now completed. All 100 turbines have been delivered to site and the majority have been fully erected. Commissioning is under way to allow connection to the grid and the project has begun delivering limited test power. The Corporation expects commercial operations to commence in the first quarter of 2018. 

The funding of the tax equity investment and retirement of the credit facility are expected to occur on or near the commercial operation date. The Corporation does not expect to make any further equity contributions towards the Flat Top project, which is currently being funded solely by the construction loan facility and equity contributions by our sponsor equity partner.

Brúarvirkjun
The Brúarvirkjun hydro project was acquired in the first quarter of 2018 as part of the Alterra acquisition. Site preparation work was already under way at the time of the acquisition.

As of the date of this press release, site preparation work, including laydown areas and access roads to the powerhouse and intake and supply of the owner's site camp, had been completed. Construction of the project is scheduled to start in 2018 following receipt of the final construction permit with commissioning expected to occur in early 2020.

SUBSEQUENT EVENTS

Acquisition of Alterra Power Corp.

On February 6, 2018, Innergex announced the completion of the acquisition of Alterra by way of an arrangement agreement pursuant to which Innergex acquired all of the issued and outstanding common shares of Alterra for an aggregate consideration of $1.1 billion, including the assumption of Alterra's debt. Pursuant to the Alterra Transaction, Alterra shareholders had the right to elect to receive either $8.25 in cash ("Cash Alternative") or 0.5563 Innergex common shares ("Share Alternative") for each Alterra common share, subject in each case to the pro-ration, such that the aggregate consideration paid to all Alterra shareholders consisted of approximately 25% in cash and 75% in Innergex common shares.

The Innergex common shares that were issuable to Alterra shareholders with the transaction represent an ownership of approximately 18% of the combined corporation. One member of the Board of Directors of Alterra joined the Board of Directors of Innergex at the closing of the Transaction.

Support from la Caisse de dépôt et placement du Québec

Concurrently with the closing of the Alterra acquisition, Innergex closed a $150 million subordinated unsecured 5-year term loan at a competitive interest rate with la Caisse de dépôt et placement du Québec. 

Increase to the revolving credit facilities

On February 6, 2018, the Corporation announced that it had increased its revolving credit facilities by $225 million to $700 million and added a new lender to the syndicate of lenders. The maturity of the revolving credit facilities remains December 2022.

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on April 16, 2018:

Date of announcement	Record date	Payment date	Dividend per common share	Dividend per Series A Preferred Share	Dividend per Series C Preferred Share
February 21, 2018	March 30, 2018	April 16, 2018	$0.170	$0.2255	$0.359375

On February 21, 2018, the Board of Directors increased the quarterly dividend from $0.165 to $0.170 per common share, corresponding to an annual dividend of $0.68 per common share. This is the fifth consecutive $0.02 annual dividend increase.

CONFERENCE CALL AND WEBCAST REMINDER

The Corporation will hold a conference call and webcast tomorrow, Thursday, February 22, 2018, at 9 AM (EST). Its 2017 fourth quarter and year-end review and outlook will be presented by Michel Letellier, President and Chief Executive Officer of Innergex, and Jean Perron, Chief Financial Officer. Investors and financial analysts are invited to access the conference call by dialing 1 888 231-8191 or 647 427-7450. You can access the webcast via http://bit.ly/2DKzAPv or the Corporation's website at innergex.com. Media and the public may also access this conference call and webcast in listen-only mode. A replay of the conference call will be available later the same day on the Corporation's website.

About Innergex Renewable Energy Inc.

The Corporation develops, acquires, owns and operates run-of-river hydroelectric facilities, wind farms, solar photovoltaic farms and geothermal power generation plants. As a global player in the renewable energy sector, Innergex conducts operations in Canada, the United States, France and Iceland. Innergex manages a large portfolio of assets currently consisting of interests in 63 operating facilities with an aggregate net installed capacity of 1,502 MW (gross 2,686 MW), including 34 hydroelectric facilities, 24 wind farms, three solar farms and two geothermal facilities. It also includes interests in two projects under construction with a net installed capacity of 107 MW (gross 210 MW) and prospective projects at different stages of development with an aggregate net capacity totalling 8,530 MW (gross 9,200 MW). Innergex Renewable Energy Inc. is rated BBB- by S&P. The Corporation's strategy for building shareholder value is to develop or acquire high-quality facilities that generate sustainable cash flows and provide an attractive risk-adjusted return on invested capital and to distribute a stable dividend.

Non-IFRS measures disclaimer

The consolidated financial statements for the the three- and twelve-month periods ended December 31, 2017, have been prepared in accordance with International Financial Reporting Standards ("IFRS"). However, some measures referred to in this press release are not recognized measures under IFRS and therefore may not be comparable to those presented by other issuers. Innergex believes that these indicators are important, as they provide management and the reader with additional information about the Corporation's production and cash generation capabilities, its ability to sustain current dividends and dividend increases and its ability to fund its growth. These indicators also facilitate the comparison of results over different periods. Adjusted EBITDA, Adjusted EBITDA Margin, Adjusted EBITDA Proportionate, Free Cash Flow and Payout Ratio are not measures recognized by IFRS and have no standardized meaning prescribed by IFRS.

References in this document to "Adjusted EBITDA" are to revenues less operating expenses, general and administrative expenses and prospective project expenses. Innergex believes that the presentation of this measure enhances the understanding of the Corporation's operating performance. Readers are cautioned that Adjusted EBITDA should not be construed as an alternative to net earnings, as determined in accordance with IFRS.

References in this document to "Adjusted EBITDA Margin" are to Adjusted EBITDA divided by revenues. Innergex believes that the presentation of this measure enhances the understanding of the Corporation's operating performance.

References in this document to "Adjusted EBITDA Proportionate" are to Adjusted EBITDA plus Innergex's share of Adjusted EBITDA of the joint ventures. Innergex believes that the presentation of this measure enhances the understanding of the Corporation's operating performance. Readers are cautioned that Adjusted EBITDA Proportionate should not be construed as an alternative to net earnings, as determined in accordance with IFRS.

References to "Free Cash Flow" are to cash flows from operating activities before changes in non-cash operating working capital items, less maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments, preferred share dividends declared and the portion of Free Cash Flow attributed to non-controlling interests, plus cash receipts by the Harrison Hydro L. P. for the wheeling services to be provided to other facilities owned by the Corporation over the course of their power purchase agreement, plus or minus other elements that are not representative of the Corporation's long-term cash generating capacity, such as transaction costs related to realized acquisitions (which are financed at the time of the acquisition), realized losses or gains on derivative financial instruments used to hedge the interest rate on project-level debt or the exchange rate on equipment purchases. Innergex believes that presentation of this measure enhances the understanding of the Corporation's cash generation capabilities, its ability to sustain current dividends and dividend increases and its ability to fund its growth. Readers are cautioned that Free Cash Flow should not be construed as an alternative to cash flows from operating activities, as determined in accordance with IFRS.  

References to "Payout Ratio" are to dividends declared on common shares divided by Free Cash Flow. Innergex believes that this is a measure of its ability to sustain current dividends and dividend increase as well as its ability to fund its growth. 

Forward-looking information disclaimer

This press release contains forward-looking statements within the meaning of applicable securities laws, including, but not limited to, statements relating to sources and impact of funding of the Alterra Transaction, and strategic, operational and financial benefits and accretion expected to result from the Alterra Transaction, Innergex's power production, prospective projects, successful development, construction and financing of the projects under construction and the advanced-stage prospective projects, estimates of recoverable geothermal energy resources, business strategy, future development and growth prospects, business integration, governance, business outlook, objectives, plans and strategic priorities, and other statements that are not historical facts. Forward-looking information can generally be identified by the use of words such as may, will, should, estimate, expect, anticipate, plan, budget, scheduled, forecasts, intend, believe, projected, potential, or other comparable terminology that states that certain events will or will not occur. It represents the estimates and expectations of Innergex relating to their future results and developments as of the date of this press release.

It includes future-oriented financial information or financial outlook within the meaning of securities laws, such as expected production, projected revenues, projected Adjusted EBITDA, projected Free Cash Flow and estimated project costs, to inform readers of the potential financial impact of expected results, of the expected commissioning of Development Projects, of the potential financial impact of the acquisitions, of the Corporation's ability to sustain current dividends and dividend increases and of its ability to fund its growth. Such information may not be appropriate for other purposes.

Forward-looking statements are based on certain key expectations and assumptions made by Innergex, including expectations and assumptions concerning availability of capital resources; economic and financial conditions; project performance and the timing of receipt of the requisite shareholder, court, regulatory and other third-party approvals. Although Innergex believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Innergex can give no assurance that they will prove to be correct.

Since forward-looking statements address future events and conditions, they are by their very nature subject to inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the renewable energy industry in general such as execution of strategy; ability to develop Innergex's projects on time and within budget; capital resources; derivative financial instruments; current economic and financial conditions; hydrology and wind regimes; geothermal resources and solar irradiation; construction, design and development of new facilities; performance of existing projects; equipment failure; interest rate and refinancing risk; currency exchange rates, variation in merchant price of electricity, financial leverage and restrictive covenants; and relationships with public utilities. There are also risks inherent to the Alterra Transaction, including incorrect assessments of the value of the other entity. There can also be no assurance that the strategic, operational or financial benefits expected to result from the Alterra Transaction will be realized.

Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the operations or financial results of Innergex are included in Innergex's annual information form filed with applicable Canadian securities regulators and may be accessed through the SEDAR website (www.sedar.com).

Forward-Looking Information in this press release is based on certain key expectations and assumptions made by the Corporation. The following table outlines Forward-Looking Information contained in this press release, the principal assumptions used to derive this information and the principal risks and uncertainties that could cause actual results to differ materially from this information.

Principal Assumptions	Principal Risks and Uncertainties
Expected production For each facility, the Corporation determines a long-term average annual level of electricity production ("LTA") over the expected life of the facility, based on engineers' studies that take into consideration a number of important factors: for hydroelectricity, the historically observed flows of the river, the operating head, the technology employed and the reserved aesthetic and ecological flows; for wind energy, the historical wind and meteorological conditions and turbine technology; for solar energy, the historical solar irradiation conditions, panel technology and expected solar panel degradation; and for geothermal power, the historical geothermal resources, natural depletion of geothermal resources over time, the technology used and the potential of energy loss to occur before delivery. Other factors taken into account include, without limitation, site topography, installed capacity, energy losses, operational features and maintenance. Although production will fluctuate from year to year, over an extended period it should approach the estimated long-term average. On a consolidated basis, the Corporation estimates the LTA by adding together the expected LTA of all the facilities in operation that it consolidates (excludes Dokie 1, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls and Viger-Denonville, which are accounted for using the equity method).	Improper assessment of water, wind, sun and geothermal resources and associated electricity production Variability in hydrology, wind regimes, solar irradiation and geothermal resources Natural depletion of geothermal resources Equipment failure or unexpected operations and maintenance activity Natural disaster
Estimated project costs, expected obtainment of permits, start of construction, work conducted and start of commercial operation for Development Projects or Prospective Projects For each development project, the Corporation provides an estimate of project costs based on its extensive experience as a developer, directly related incremental internal costs, site acquisition costs and financing costs, which are eventually adjusted for the projected costs provided by the engineering, procurement and construction ("EPC") contractor retained for the project. The Corporation provides indications regarding scheduling and construction progress for its Development Projects and indications regarding its Prospective Projects, based on its extensive experience as a developer.	Performance of counterparties, such as the EPC contractors Delays and cost overruns in the design and construction of projects Obtainment of permits Equipment supply Interest rate fluctuations and financing risk Relationships with stakeholders Regulatory and political risks Higher-than-expected inflation Natural disaster
Projected Revenues For each facility, expected annual revenues are estimated by multiplying the LTA by a price for electricity stipulated in the power purchase agreement secured with a public utility or other creditworthy counterparty. These agreements stipulate a base price and, in some cases, a price adjustment depending on the month, day and hour of delivery. In most cases, power purchase agreements also contain an annual inflation adjustment based on a portion of the Consumer Price Index. On a consolidated basis, the Corporation estimates annual revenues by adding together the projected revenues of all the facilities in operation that it consolidates (excludes Dokie 1, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls and Viger-Denonville, which are accounted for using the equity method).	Production levels below the LTA caused mainly by the risks and uncertainties mentioned above Unexpected seasonal variability in the production and delivery of electricity Lower-than-expected inflation rate Changes in the purchase price of electricity upon renewal of a PPA
Projected Adjusted EBITDA For each facility, the Corporation estimates annual operating earnings by subtracting from the estimated revenues the budgeted annual operating costs, which consist primarily of operators' salaries, insurance premiums, operations and maintenance expenditures, property taxes and royalties; these are predictable and relatively fixed, varying mainly with inflation (except for maintenance expenditures). On a consolidated basis, the Company estimates annual Adjusted EBITDA by adding together the projected operating earnings of all the facilities in operation that it consolidates (excludes Dokie 1, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls and Viger-Denonville, which are accounted for using the equity method), from which it subtracts budgeted general and administrative expenses, comprised essentially of salaries and office expenses, and budgeted prospective project expenses, which are determined based on the number of prospective projects the Corporation chooses to develop and the resources required to do so.	Lower revenues caused mainly by the risks and uncertainties mentioned above Variability of facility performance and related penalties Unexpected maintenance expenditures
Projected Adjusted EBITDA Proportionate On a consolidated basis, the Company estimates annual Adjusted EBITDA Proportionate by adding to the projected Adjusted EBITDA Innergex's share of Adjusted EBITDA of the joint ventures (Dokie 1, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls and Viger-Denonville).	Lower revenues caused mainly by the risks and uncertainties mentioned above Variability of facility performance and related penalties Unexpected maintenance expenditures
Projected Free Cash Flow and intention to pay dividend quarterly The Corporation estimates Projected Free Cash Flow as projected cash flows from operating activities before changes in non-cash operating working capital items, less estimated maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments, preferred share dividends declared and the portion of Free Cash Flow attributed to non-controlling interests, plus cash receipts by the Harrison Hydro L.P. for the wheeling services to be provided to other facilities owned by the Corporation over the course of their power purchase agreement, plus or minus other elements that are not representative of the Corporation's long-term cash generating capacity, such as transaction costs related to realized acquisitions (which are financed at the time of the acquisition), realized losses or gains on derivative financial instruments used to hedge the interest rate on project-level debt or the exchange rate on equipment purchases. The Corporation estimates the annual dividend it intends to distribute based on the Corporation operating results, cash flows, financial conditions, debt covenants, long term growth prospects, solvency, test imposed under corporate law for declaration of dividends and other relevant factors.	Adjusted EBITDA below expectations caused mainly by the risks and uncertainties mentioned above and by higher prospective project expenses Projects costs above expectations caused mainly by the performance of counterparties and delays and cost overruns in the design and construction of projects Regulatory and political risk Interest rate fluctuations and financing risk Financial leverage and restrictive covenants governing current and future indebtedness Unexpected maintenance capital expenditures Possibility that the Corporation may not declare or pay a dividend

The material risks and uncertainties that may cause actual results and developments to be materially different from current expressed Forward-Looking Information are referred to in the Corporation's Annual Information Form in the "Risk Factors" section and include, without limitation: the ability of the Corporation to execute its strategy for building shareholder value; its ability to raise additional capital and the state of capital markets; liquidity risks related to derivative financial instruments; variability in hydrology, wind regimes and solar irradiation; delays and cost overruns in the design and construction of projects; the ability to secure new power purchase agreements or renew any power purchase agreements on equivalent terms and conditions; uncertainty surrounding the development of new facilities; change in governmental support to increase electricity to be generated from renewable sources by independent power producers; foreign market growth and development risks; and sufficiency of insurance coverage limits and exclusions.

Although the Corporation believes that the expectations and assumptions on which Forward-Looking Information is based are reasonable, readers of this press release are cautioned not to rely unduly on this Forward-Looking Information since no assurance can be given that they will prove to be correct. The forward-looking statements contained in this press release are made as of the date hereof and Innergex undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

SOURCE Innergex Renewable Energy Inc.

Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 1239, [email protected]; Karine Vachon, Director - Communications, 450 928-2550, ext. 1222, [email protected]

Related Links

www.innergex.com