Innergex reports year-end 2015 results

TRETHEWAY COMMISSIONING - DIVIDEND INCREASES 3%

  • Board of Directors declares a dividend increase of $0.02 to $0.64 per common share on an annual basis
  • Construction and commissioning of the Tretheway Creek hydroelectric project were completed ahead of time and savings of $8.0 million has been realized
  • Savings of $28.0 million is expected over the previously estimated total Development Projects costs
  • Production increases 1% to 2,988 GWh for the year and reaches 98% of long-term average ("LTA")
  • Revenues increase 2% to $246.9 million for the year
  • Adjusted EBITDA increases 2% to $183.7 million for the year

LONGUEUIL, QC, Feb. 24, 2016 /CNW Telbec/ - Innergex Renewable Energy Inc. (TSX: INE) ("Innergex" or the "Corporation") today released its operating and financial results for the year ended December 31, 2015.

"After a positive start to 2015, thanks to strong production performances from our wind and solar farms, we ended the year on a high note with the announcement of the acquisition of Walden North, a 16 MW hydroelectric facility, in partnership with the Cayoose Creek Band" declared Michel Letellier, President and Chief Executive Officer of the Corporation.

"We have made good on our objectives for 2015," Mr. Letellier said. "Construction is well under way at the Mesgi'g Ugju's'n wind farm in Quebec and at the Big Silver Creek hydro facility in BC, and we are making up for lost time at the Upper Lillooet River and Boulder Creek hydroelectric projects after a two-month halt due to a forest fire last summer. We refinanced the convertible debenture at a lower interest rate and closed over 1 billion dollars of financing at better-than-anticipated terms. We are starting 2016 with optimism and continuing with the proactive and efficient management of our projects and our international development efforts."

OPERATING RESULTS

 




Amounts shown are in thousands of Canadian dollars except as noted otherwise.

Three months ended December 31

Year ended December 31

2015


2014


2015


2014


Power generated (MWh)

647,062


819,903


2,987,637


2,962,450


Long-term average (MWh)

690,932


685,852


3,054,642


2,964,070


Revenues

56,291


68,215


246,869


241,834


Adjusted EBITDA1

38,819


48,748


183,738


179,562


Net loss

(34,391)


(27,568)


(48,383)


(84,378)


Net loss, $ per share2

(0.31)


(0.21)


(0.37)


(0.63)
















Year ended December 31






2015


2014


Free Cash Flow1





74,386


67,744


Payout Ratio1





86

%

88

%

1

Please refer to the "Non-IFRS measures disclaimer" for the definition of Adjusted EBITDA, Free Cash Flow and Payout Ratio.

2

Net loss per share is calculated as net loss attributable to owners of the parent, less dividends declared on preferred shares, divided by the weighted average number of common shares outstanding.

Three-month period ended December 31, 2015

During the three-month period ended December 31, 2015, the Corporation's facilities produced 94% of the LTA, more precisely 647 GWh compared with the 691 GWh expected. Overall, the production of the hydroelectric facilities and the wind farms was below-average (respectively, 94% and 92% of the LTA). The Stardale solar farm produced 109% of its LTA.

In the fourth quarter, the Corporation recorded revenues of $56.3 million, compared with $68.2 million in 2014, due mainly to average water flows in British Columbia and to below-average water flows and wind regimes in Quebec. The Corporation recorded Adjusted EBITDA of $38.8 million, compared with $48.7 million in 2014, due mainly to lower revenues.

For the three-month period ended December 31, 2015, the Corporation recorded a net loss of $34.4 million (basic and diluted net loss per share of $0.31), compared with a net loss of $27.6 million in 2014 (basic and diluted net loss per share of $0.21). This difference is in part due to a lower Adjusted EBITDA, as explained above. Furthermore, the Corporation recorded an impairment expense with respect to project development costs in the amount of $51.7 million and a $2.0 million unrealized net gain on derivative financial instruments giving a total net impact on the net loss of $49.7 million. In the fourth quarter ended December 31, 2014, the Corporation recorded a $49.6 million unrealized net loss on derivative financial instruments due to a decrease in the benchmark interest rates.

Electricity Production

During the year ended December 31, 2015, the Corporation's facilities produced 2,988 GWh of electricity or 98% of the LTA of 3,055 GWh. Overall, the hydroelectric facilities produced 96% of their LTA, due mainly to below-average water flows in all markets. Overall, the wind farms produced 105% of their LTA, due mainly to above-average wind regimes. The Stardale solar farm produced 104% of its LTA, due mainly to above-average solar regimes. The production increase of 1% compared with the same period last year is attributable to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and to the better performance of the wind farms, partially offset by below-average water flows in Ontario, British Columbia and the United-States.

Revenues

For the year ended December 31, 2015, the Corporation recorded revenues of $246.9 million, compared with $241.8 million in 2014. This 2% increase is attributable mainly to the full-year contribution of the SM-1 hydroelectric facility acquired in June 2014 and to the higher wind regimes in Quebec, partially offset by lower water flows in British Columbia.

Adjusted EBITDA

For the year ended December 31, 2015, the Corporation recorded Adjusted EBITDA of $183.7 million, compared with $179.6 million for the same period last year. This 2% increase is due mainly to the increase in production and revenues explained above. As a result, the Adjusted EBITDA Margin rose from 74.3% to 74.4%.

Net Loss

Excluding the unrealized net gain or loss on Derivatives, the realized loss on Derivatives, the impairment of project development costs and the related income taxes, the net earnings for the year ended December 31, 2015, would have been $19.7 million, compared with net earnings of $16.4 million in 2014.

For the year ended December 31, 2015, the Corporation recorded a net loss of $48.4 million (basic and diluted net loss of $0.37 per share), compared with a net loss of $84.4 million (basic and diluted net loss of $0.63 per share) in 2014. This is attributable mainly to an impairment of project development costs of $51.7 million and to a smaller negative impact of Derivatives, namely a $119.6 million realized loss on Derivatives partly offset by a $81.4 million unrealized gain on Derivatives, compared with a $8.4 million realized loss and a $121.7 million unrealized loss on Derivatives last year.

Free Cash Flow and Payout Ratio

For the year ended December 31, 2015, the Corporation generated Free Cash Flow of $74.4 million, compared with $67.7 million for the same period last year. This increase is due mainly to higher adjusted EBITDA resulting in greater cash flows. The realized losses on derivative financial instruments were not funded from operations but from the project-level financings put in place in 2015. During the year, the Corporation used $12.4 million of its Free Cash Flows to purchase for cancellation 1,190,173 common shares under its normal course issuer bid.

The Payout Ratio represents the dividends declared on common shares divided by Free Cash Flow. The Corporation believes it is a measure of its ability to sustain current dividends and dividend increases and its ability to fund its growth. For the year ended December 31, 2015, the dividends on common shares declared by the Corporation corresponded to 86% of Free Cash Flow, compared with 88% for the corresponding prior 12-month period. This positive change is due mainly to the increase in Free Cash Flow explained above, which more than offset the increase in dividends resulting from the higher number of common shares outstanding by virtue of the Dividend reinvestment plan, the issuance of 4,027,051 common shares of the Corporation in June 2014 to pay for the acquisition of the SM-1 hydroelectric facility and the issuance of 3,653,422 common shares of the Corporation upon conversion, at the holders' request, of convertible debentures bearing interest at a rate of 5.75%.

2015 HIGHLIGHTS

  • The Corporation closed $1,000.5 million of Project Financings. It completed the project financings for the Boulder Creek, Upper Lillooet River and Big Silver Creek hydroelectric projects located in British Columbia, for a total amount of $688.8 million. It also closed the project financing of $311.7 million for the Mesgi'g Ugju's'n wind project located in Quebec. The Big Silver Creek and Mesgi'g Ugju's'n projects should achieve commercial operation in 2016, while the Upper Lillooet and Boulder Creek projects should achieve commercial operation in the first and second quarter of 2017 respectively (collectively "the Development Projects").
  • The Corporation reviewed the total anticipated project costs to achieve the completion of the Tretheway Creek project and the Development Projects. Savings of $36.0 million are expected over the previously estimated total project costs.
  • Construction began at the Mesgi'g Ugju's'n wind project in Quebec. The Mesgi'g Ugju's'n project is a 150 MW wind project jointly owned by the three Mi'gmaq First Nations of Quebec, namely the Gesgapegiag, Gespeg and Listuguj nations, and by Innergex.
  • The Corporation issued $100.0 million of convertible debentures bearing interest at 4.25% and redeemed $41.6 million and converted $38.0 million of an outstanding principal of $80.5 million of convertible debentures bearing interest at 5.75%.
  • Innergex and the Cayoose Creek Band signed an agreement for the joint acquisition of the Walden North Hydroelectric project in British Columbia for $9.2 million. The Walden North Hydroelectric project is a 16 MW facility located on private land in Cayoosh Creek near Lillooet, in British Columbia.
  • The Corporation signed a memorandum of understanding with the Comisión Federal de Electricidad ("CFE") to jointly study a number of renewable energy project opportunities in Mexico with the aim of jointly developing selected projects.
  • The Corporation's normal course issuer bid was amended to increase the maximum number of shares that may be repurchased and to implement an automatic purchase plan. As at December 31, 2015, the Corporation had purchased for cancellation 1,190,173 common shares at an average price of $10.36.

DEVELOPMENT PROJECTS

Tretheway Creek hydroelectric project

The construction of this hydroelectric facility began in October 2013. Construction and commissioning activities were completed ahead of time. The costs of the Tretheway Creek project have been revised downward by an amount of $8.0 million and are currently estimated at $103.5 million (compared with $111.5 million in 2014). The estimate of the total project costs was revised mainly to take into account a reduction in the unused contingencies on the construction costs.

The facility began commercial operations with an effective commissioning date of October 27, 2015. Tretheway Creek's average annual production is estimated to reach 81,000 MWh, enough to power more than 7,300 BC households. In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of approximately $8.7 million and $7.2 million respectively (compared with $9.0 million and $7.5 million in 2014). The $0.3 million reduction in these estimates compared with prior guidance reflects a lower inflation rate in adjusting the expected selling price for electricity. All of the electricity the facility produces is covered by a 40-year fixed-price power purchase agreement with BC Hydro, which was obtained under that province's 2008 Clean Power Call Request for Proposals and which provides for an annual adjustment to the selling price based on a portion of the Consumer Price Index.

Upper Lillooet River and Boulder Creek hydroelectric projects ("ULHP")

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 $491.6 million non-recourse construction and term project financing for both these projects.

The construction activities have resumed after being halted for two months due to a forest fire that swept through the area on July 4. Damage to the project site from the fire was very limited and all structures and equipment remained intact, except for a portion of the transmission line between the two powerhouses. As of the date of this press release, the installation of the joint transmission line, the powerhouses, intakes and tunnels are well under way. Both generators for the Boulder facility were delivered in mid-December and stored in the powerhouse. The Corporation and its contractors are working throughout the winter focusing mainly on both tunnels to make up for some of the time lost due to the forest fire. On December 23, BC Hydro notified the ULHP that it accepted a claim for Force Majeure for the forest fire and confirmed that the commissioning date could be extended by 98 Force Majeure days. The insurance claims process is ongoing and will take time to complete. In any case, the Corporation expects to be indemnified and to suffer no significant adverse financial consequences from the forest fire.

The costs of the Upper Lillooet and Boulder Creek hydroelectric facilities were revised upward by an amount of $17.0 million ($12.1 million for the Upper Lillooet project and $4.9 million for the Boulder Creek project). The total project costs for the Upper Lillooet facility are currently estimated at $327.1 million (compared with $315.0 million in 2014) while they are reassessed at $124.1 million (previously $119.2 million in 2014) for the Boulder Creek facility. The estimates of the total projects costs have been revised to take into account incremental costs associated with the geological conditions in the tunnels and additional interest expenses from the higher amount of project financing.

Big Silver Creek hydroelectric project

Construction of this hydroelectric facility began in June 2014. On June 22, 2015, the Corporation announced the closing of a $197.2 million non-recourse construction and term project financing for this project. The civil works for the intake, tunnel, penstock, powerhouse and tailrace have been completed. The majority of the turbines and generators have been delivered to site and their installation is under way. The transmission line construction continued for both the terrestrial line and the submarine cables. Procurement and delivery of the electrical equipment were under way.

The costs of the Big Silver Creek project have been revised downward by $10.0 million and are currently estimated at $206.0 million (compared with $216.0 million in 2014). The estimates of the total project costs have been revised, mainly to take into account a reduction in the unused contingencies for the construction costs. Commercial operation is expected to begin in the third quarter of 2016.

Mesgi'g Ugju's'n ("MU") wind project

Construction of this wind farm began in May 2015. On September 28, 2015, the Corporation and its partner announced the closing of $311.7 million non-recourse construction and term project financing for this project. The access roads and wind turbines generator ("WTG") areas have been completed. All the WTG foundations have been completed but one, which will be backfilled in early spring 2016. The electrical works will not be completed during the winter but will resume in 2016 along with other activities. As planned, the other construction activities have been halted for the winter period and will also resume in the spring of 2016.

The cost of the Mesgi'g Ugju's'n wind project is currently estimated at $305.0 million (compared with $340.0 million in 2014). The $35.0 million reduction in the Corporation's estimated project costs reflects the lower cost of project financing and associated financial costs relative to the initial forecasts and the use of larger turbines, which incidentally reduces the number of turbines, equipment costs and civil engineering construction associated costs. The end of construction and the commissioning of the Mesgi'g Ugju's'n wind farm are expected for the end of 2016.

SUBSEQUENT EVENTS

Refinancing of Stardale long-term debt

On February 22, 2016, Stardale has renegotiated its long-term debt to increase its borrowing to $109.0 million and to reduce its applicable credit margin rate by 0.625%.

Revolving term credit facility

On January 18, 2016, the Corporation executed an amending agreement to extend its revolving term credit facility from 2019 to 2020.

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on April 15, 2016:

 







Date of announcement

Record date

Payment date

Dividend per common share

Dividend per Series A
Preferred Share

Dividend per Series C
Preferred Share







February 24, 2016

March 31, 2016

April 15, 2016

$0.16

$0.2255

$0.359375

 

On February 24, 2016, the Board of Directors increased the annual dividend that the Corporation intends to distribute from $0.62 to $0.64 per common share, payable quarterly.

CONFERENCE CALL AND WEBCAST REMINDER

The Corporation will hold a conference call and webcast tomorrow, Thursday, February 25, 2016, at 10:00 a.m. ET. Its year-end 2015 results and 2016 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 647 427-7450 or 1 888 231-8191 and to access the webcast at http://bit.ly/1RomFQG or via the Corporation's website at www.innergex.com. Media and the public may also access this conference call and webcast in listen-only mode.  A replay of the conference call and webcast 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, British Columbia and Idaho, USA. Its portfolio of assets currently consists of: (i) interests in 34 operating facilities with an aggregate net installed capacity of 708 MW (gross 1,216 MW), including 27 hydroelectric operating facilities, six wind farms, and one solar photovoltaic farm; (ii) interests in four projects under development or under construction with an aggregate net installed capacity of 187 MW (gross 297 MW), for which power purchase agreements have been secured; and (iii) prospective projects with an aggregate net capacity totaling 3,280 MW (gross 3,530 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 year ended December 31, 2015, 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 foreign 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, to inform readers of the potential financial impact of development projects. Such information may not be appropriate for other purposes.

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

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 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

 

The material risks and uncertainties that may cause actual results and developments to be materially different from currently expressed Forward-Looking Information are referred to in the "Risk Factors" section of the Corporation's Annual Information Form 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; uncertainty surrounding the development of new facilities; variability of installation performance and related penalties; foreign market growth and development risks; sufficiency of insurance coverage limits and exclusions; the possibility that the corporation may not declare or pay a dividend; the failure to close the acquisition of the Walden hydroelectric project; and the ability to secure new power purchase agreements or 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 it 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 law.

 

SOURCE Innergex Renewable Energy Inc.

For further information: Martine Benmouyal, Senior Advisor - Communications, 450 928-2550, ext. 335, MBenmouyal@innergex.com, www.innergex.com; Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 239, JPerron@innergex.com

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