Innergex reports its year-end 2016 results

MESGI'G UGJU'S'N COMMISSIONING - DIVIDEND INCREASES BY 3%

• Board of Directors declares a dividend increase of $0.02 to $0.66 per common share on an annual basis
• Innergex cumulative results for the year 2016 exceeded long-term projections
  • Production was 105% of the long-term average ("LTA") in 2016 and 101% of the LTA for Q4
  • Revenues increased 19% to $292.8 million in 2016 and 30% to $73.3 million in Q4 compared with 2015
  • Adjusted EBITDA rose 18% to $216.0 million in 2016 and increased 29% to $50.3 million in Q4 compared with 2015
• In Quebec, the 150-MW Mesgi'g Ugju's'n wind farm began commercial operation in December 2016, on budget
• Construction of the Upper Lillooet River and Boulder Creek hydroelectric facilities is progressing at a good pace

LONGUEUIL, QC, Feb. 23, 2017 /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, 2016.

"Innergex has successfully expanded its international presence in 2016," said Michel Letellier, President and Chief Executive Officer of the Corporation. "The dedication of our team also enabled us to pursue growth by commissioning two facilities, achieving significant progress in constructing our two hydroelectric projects in development and also finalizing three acquisitions, adding nine wind farms and one hydroelectric facility to our portfolio."

"In 2017, as two construction projects become commissioned, we will focus on replenishing our portfolio of development projects and seizing acquisition opportunities, in Canada and abroad. Furthermore, these activities should strengthen our financial capabilities and significantly improve our payout ratio," 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
	2016	2015	2016	2015
Power generated (MWh)	848,967	647,062	3,521,645	2,987,637
Long-term average (MWh)	838,051	690,932	3,364,907	3,054,642
Revenues	73,265	56,291	292,785	246,869
Adjusted EBITDA^1	50,264	38,819	215,983	183,738
Net earnings (loss)	8,765	17,328	32,043	(48,383)
Net earnings (loss), $ per share - basic and diluted	0.08	(0.31)	0.28	(0.37)
			Year ended December 31
			2016	2015
Free Cash Flow^1			75,703	74,386
Payout Ratio^1			91%	86%
^1 Please refer to the Non-IFRS Measures Disclaimer for the definition of Adjusted EBITDA, Free Cash Flow and Payout Ratio.

Three-Month Period Ended December 31, 2016

During the three-month period ended December 31, 2016, the Corporation's facilities produced 849 GWh of electricity or 101% of the LTA of 838 GWh. Overall, the hydroelectric facilities produced 117% of their LTA due to above-average water flows in all markets, except Ontario. Overall, the wind farms produced 75% of their LTA due to the below-average wind regime in Quebec and in France. The solar farm produced 103% of its LTA due to an above-average solar regime.

In the fourth quarter, the Corporation recorded revenues of $73.3 million, compared with $56.3 million in 2015, due mainly to better results from most of the British Columbia hydroelectric facilities compared with the same period last year and to the contribution of the recently commissioned or acquired facilities, which were partly offset by lower revenues from the wind regime in Quebec and the hydrologic and solar regimes in Ontario. The Corporation recorded Adjusted EBITDA of $50.3 million, compared with $38.8 million in 2015, due mainly to higher revenues.

For the three-month period ended December 31, 2016, the Corporation recorded net earnings of $8.8 million (basic and diluted net earnings per share of $0.08), compared with a net loss of $34.4 million in 2015 (basic and diluted net loss per share of $0.31). The difference is mainly explained by the $11.4 million  increase in Adjusted EBITDA and the recognition, in 2015, of an impairment expense by the Corporation in relation to some of its Prospective Projects in the amount of $51.7 million related to its BC Prospective Projects, resulting in an income tax recovery of $13.6 million and a net impact of $38.1 million (nil in 2016). These factors were partly offset by higher finance costs, depreciation and amortization.

Electricity Production

During the year ended December 31, 2016, the Corporation's facilities produced 3,522 GWh of electricity or 105% of the LTA of 3,365 GWh. Overall, the hydroelectric facilities produced 109% of their LTA due mainly to above-average water flows in all markets but Ontario. Overall, the wind farms produced 91% of their LTA due to the below-average wind regimes in Quebec and in France. The solar farm produced 111% of its LTA due to an above-average solar regime. The 18% production increase over the same period last year is due mainly to higher water flows in BC and to the contribution of the recently commissioned or acquired facilities, which were partly offset by lower wind regimes in Quebec and by lower water flows in Ontario.

Revenues

For the year ended December 31, 2016, the Corporation recorded revenues of $292.8 million, compared with $246.9 million in 2015. This 19% increase is attributable mainly to better results in all hydroelectricity markets except Ontario and to the contribution of the recently commissioned or acquired facilities, which were partly offset by lower revenues related to wind regime in Quebec wind farms.

Adjusted EBITDA

For the year ended December 31, 2016, the Corporation recorded Adjusted EBITDA of $216.0 million, compared with $183.7 million for the same period last year. This increase of 18% for the year is due mainly to the increase in production and revenues, partly offset by higher operating expenses, general and administrative expenses and prospective project expenses. The adjusted EBITDA Margin decreased from 74.4% to 73.8% for the year due mainly to lower production by the French Entities and to higher prospective project expenses.

Net Earnings (Loss)

For the year ended December 31, 2016, the Corporation recorded net earnings of $32.0 million (basic and diluted net earnings of $0.28 per share), compared with a net loss of $48.4 million (basic and diluted net loss of $0.37 per share), recorded by the Corporation for the year 2015. The $80.4 million increase in net earnings is explained mainly by the $32.2 million increase in Adjusted EBITDA and by a $38.2 million net loss on derivative financial instruments in 2015 compared with a $4.3 million net gain in 2016 and by the recognition, in 2015, of a $51.7 million impairment of project development costs, partly offset by higher finance costs, higher amortization and depreciation costs and net of income tax effect.

Excluding the gains and losses on financial instruments, the impairment of project development costs and the related income taxes, the net earnings for the year ended December 31, 2016, would have been $29.1 million, compared with net earnings of $19.7 million in 2015. The increase is attributable mainly to the $32.2 million increase in Adjusted EBITDA, partly offset by a $12.1 million increase in finance costs and a $14.8 million increase in depreciation and amortization. 

Free Cash Flow and Payout Ratio

For the year ended December 31, 2016, the Corporation generated Free Cash Flow of $75.7 million, compared with $74.4 million for the same period last year. This small increase in Free Cash Flow is due mainly to higher cash flows from operating activities in 2016 before changes in non-cash operating working capital items and realized losses on derivative financial instruments (none in 2016), which were partly offset by greater scheduled debt principal payments and higher free cash flow attributed to non-controlling interests. The Corporation also decided to invest more to pursue growth opportunities in new international markets.

For the year ended December 31, 2016, the dividends on common shares declared by the Corporation amounted to 91% of Free Cash Flow, compared with 86% for the prior year. This change is due mainly to a slightly better Free Cash Flow than in 2015, which was more than offset by higher dividend payments as a result of a 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 common shares of Innergex, and to the issuance of 94,000 shares following the exercise of stock options and 242,706 shares related to the Dividend Reinvestment Plan (DRIP).

2016 HIGHLIGHTS

• On February 25, 2016, the Corporation, in partnership with the Cayoose Creek Indian Band, completed the acquisition from FortisBC of the Walden facility located in British Columbia, Canada ("Walden"). Walden is a 16 MW facility commissioned in 1993 and located on private land in Cayoosh Creek. Innergex and Cayoose Creek Development Corporation, the economic arm of the Cayoose Creek Indian Band, have formed the Cayoose Creek Limited Partnership, which in turn has acquired the assets that make up the facility. The transaction closed at a total purchase price of $9.2 million.
• On April 15, 2016, Innergex completed the acquisition of seven operating wind power facilities with an installed capacity of 86.8 MW (the "Seven French Entities"). The purchase price for the Seven French Entities is a net cash consideration of $94.5 million, subject to certain adjustments. Simultaneously, the Corporation committed to acquiring the Yonne project then under construction with an installed capacity of 44.0 MW. An amount of $13.9 million was also paid as a deposit for this project. All power generated from the operating facilities is sold to Electricité de France and S.I.C.A.E Oise. Simultaneously, the Corporation completed a private placement of $50.0 million with three Desjardins Group-affiliated entities.
• On June 10, 2016, Innergex announced the closing of the investment by the Desjardins Group Pension Plan ("Desjardins") in the wind project portfolio acquired in France on April 15, 2016, and a project, which was under construction, acquired on February 21, 2017. Following this investment, the Corporation and Desjardins respectively hold 69.55% and 30.45% of the limited partnership that holds these projects.
• On July 29, 2016, the Corporation began commercial operation of the 40.6 MW Big Silver Creek run-of-river hydroelectric facility located in British Columbia. Construction began in June 2014 and was completed in July 2016, earlier than expected and on budget. In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of circa $17.2 million and $14.5 million respectively.  All the electricity it produces is covered by a 40-year fixed-price power purchase agreement with BC Hydro.
• On December 22, 2016, the Corporation completed the acquisition of two wind power projects from French group BayWa r.e. (the "Two French Entities in Nouvelle-Aquitaine"). With a total capacity of 24 MW, the two projects are located in Nouvelle-Aquitaine, France. Innergex owns a 69.55% interest in the project, and Desjardins Group Pension Plan owns the remaining 30.45%. The purchase price for the Two French Entities in Nouvelle-Aquitaine is a net cash consideration of $22.7 million, subject to certain adjustments and $0.8 million in transaction costs.
• On December 30, 2016, the Corporation and the three Mi'gmaq communities of Quebec began commercial operation at the 150 MW Mesgi'g Ugju's'n wind farm, located in Quebec's Gaspé peninsula. Construction of this wind farm began in May 2015 and was completed in December 2016, on budget. In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of circa $59.6 million and $52.5 million respectively. All the electricity the facility will produce is covered by a 20-year fixed-price power purchase agreement with Hydro-Québec.

DEVELOPMENT PROJECTS

Construction activities

Upper Lillooet River and Boulder Creek

The construction of the Upper Lillooet River and Boulder Creek hydroelectric facilities began in October 2013. On March 17, 2015, the Corporation announced the closing of a $491.6 million non-recourse construction and term project financing for both these projects, which has received the Clean Energy BC's Finance Award for 2015 and the 2016 Hydro Power Deal of the Year from the World Finance Magazine.

As at the date of this press release, civil work had been completed on the Upper Lillooet River facility. At the intake the head-pond filling was successfully completed in early February. The overall weather conditions and high risk of avalanches have pushed back the final completion of the overall facility. The powerhouse turbine and generation equipment installation is nearly complete with only portions of electrical equipment and control remaining to be installed. The transformer and switchyard are complete and currently energized from the transmission line (back feed from BC Hydro). The start of the commissioning activities began mid-February and COD is expected at the end of March 2017.

The Boulder Creek tunnel excavation, cleaning and tunnel plug was completed as of mid-December 2016. The steel liner installation work, including the concrete embedment, is expected to be completed by mid-March 2017. The intake civil, hydro-mechanical is complete with only portions of the electrical and control equipment remaining to be installed. The Leave to commence diversion package has been submitted to the agencies concerned for approval. The start of the commissioning activities of the Boulder Creek facility is expected by the end of March 2017 and COD is expected in the second quarter of 2017.

The joint transmission line is complete, commissioned and energized.

The insurance claims process for the fire continues with interim progress payments being made. In any case, the Corporation expects to be indemnified and to suffer no significant adverse financial consequences from the forest fire.

SUBSEQUENT EVENTS

Big Silver Term Loan
On January 31, 2017, the construction term loan of Big Silver was converted into a 39.5-year term loan.

Financing of Two of the French Subsidiaries
On February 10, 2017, two of the French subsidiaries concluded a €8,5 million subordinated debt financing with a French Infrastructure fund. The subordinated loan carries an interest rate of 7.25%, has an eight year tenor and its principal will be reimbursed at maturity.

Revolving Credit Facility
On February 21, 2017, the Corporation executed a Fifth Amended and Restated Credit Agreement of its existing $425 million revolving credit facility. These amendments add flexibility to the Corporation to borrow in EURO via EURIBOR loans. The Corporation also extended its revolving term from 2020 to 2021 (except for one lender of $42.5 million whose commitment remains until 2020) to provide greater financing flexibility. Moreover, a Letter of Credit Facility of an amount of up to $30 million guaranteed by Export Development Canada (EDC) was added and will be put in place.

Acquisition of Yonne
On February 21, 2017, the Corporation and Desjardins completed the purchase of the Yonne wind farm, a 44 MW facility for which the commissioning activities began in the fourth quarter 2016 and were completed at the end of January 2017, and which was part of the French wind projects acquisition concluded in April 2016. The electricity produced by Yonne is sold under a power purchase agreement at fixed price for an initial term of 15 years, to Électricité de France. The total purchase price amounted to €35.2 million (or $49.0 million), subject to certain adjustments. A €10.0 million (or $13.9 million) deposit had already been provided by the Corporation. The project financing of €59.5 million (equivalent to $82.8 million), which is already in place, will remain at the acquired project level. The Corporation reduces its exposure to exchange rate fluctuations by entering into long-term currency hedging instruments. Innergex owns a 69.55% interest in the wind farm and Desjardins Group Pension Plan owns the remaining 30.45%.

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on April 17, 2017:

Date of announcement	Record date	Payment date	Dividend per common share	Dividend per Series A Preferred Share	Dividend per Series C Preferred Share
February 23, 2017	March 31, 2017	April 17, 2017	$0.1650	$0.2255	$0.359375

On February 23, 2017, the Board of Directors increased the annual dividend from $0.64 to $0.66 per common share, payable quarterly.

CONFERENCE CALL REMINDER

The Corporation will hold a conference call tomorrow, Friday, February 24, 2017, at 9:00 a.m. ET. Its 2016 fourth quarter and year-end results 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. Media and the public may also access this conference call 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.

Innergex Renewable Energy Inc. (TSX: INE) is a leading Canadian independent renewable power producer. Active since 1990, the Corporation develops, owns and operates run-of-river hydroelectric facilities, wind farms and solar photovoltaic farms and carries out its operations in Quebec, Ontario and British Columbia, Canada, in France and in Idaho, USA. Its portfolio of assets currently consists of: (i) interests in 47 operating facilities with an aggregate net installed capacity of 939 MW (gross 1,576 MW), including 29 hydroelectric facilities, 17 wind farms and one solar farm; (ii) interests in two projects under construction with an aggregate net installed capacity of 71 MW (gross 107 MW), for which power purchase agreements have been secured; and (iii) prospective projects with an aggregate net capacity totalling 3,560 MW (gross 3,940 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, 2016, have been prepared in accordance with International Financial Reporting Standards ("IFRS"). However, some measures referred to in this news 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, 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.

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 Limited Partnership for the wheeling services to be provided to other facilities owned by the Corporation over the course of their PPA, 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) and 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.

References to "Payout Ratio" are to dividends declared on common shares divided by Free Cash Flow.

Readers are cautioned that Adjusted EBITDA should not be construed as an alternative to net earnings and Free Cash Flow should not be construed as an alternative to cash flows from operating activities, as determined in accordance with IFRS.

Forward-looking information disclaimer

In order to inform readers of the Corporation's future prospects, this press release contains forward-looking information within the meaning of applicable securities laws ("Forward-Looking Information"). Forward-Looking Information can generally be identified by the use of words such as "projected", "potential", "expect", "will", "should", "estimate", "forecasts", "intends", or other comparable terminology that states that certain events will or will not occur. It represents the estimates and expectations of the Corporation relating to 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 French Entities, 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 Information in this press release is based on certain key	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; and for solar energy, the historical solar irradiation conditions, panel technology and expected solar panel degradation. 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 Umbata Falls and Viger-Denonville, which are accounted for using the equity method).	Improper assessment of water, wind and sun resources and associated electricity production Variability in hydrology, wind regimes and solar irradiation 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.	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
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).	Variability of facility performance and related penalties Unexpected maintenance expenditures Changes in the purchase price of electricity upon renewal of a PPA
Projected Free Cash Flow and intention to dividend quarterly   The Corporation estimates Free Cash Flow as projected cash flow from operations 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 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. It also adjusts for other elements, which represent cash inflows or outflows that are not representative of the Corporation's long-term cash generating capacity, such as adding back transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and adding back realized losses or subtracting realized gains on derivative financial instruments used to fix 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; 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; sufficiency of insurance coverage limits and exclusions; and the ability to secure new power purchase agreements or to renew existing ones.

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 Corporation does not undertake any obligation to update or revise any Forward-Looking Information, whether as a result of events or circumstances occurring after the date of this press release, unless so required by legislation.

SOURCE Innergex Renewable Energy Inc.

Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 239, [email protected]; Karine Vachon, Director - Communications, 450 928-2550, ext. 222, [email protected]

Related Links

www.innergex.com