Innergex reports its first quarter 2017 results

INNERGEX'S 81.4 MW LARGEST HYDROELECTRIC FACILITY COMMISSIONED ACQUISITION OF A 44 MW WIND FARM IN FRANCE

  • Revenues increased 19% to $74.5 million compared with the same period last year.
  • Adjusted EBITDA rose 7% to $50.9 million compared with the same period last year.
  • Innergex and Desjardins Group Pension Plan completed the acquisition of the 44 MW Yonne wind farm, which was under construction when Innergex announced the acquisition of 8 French wind farms in March 2016.
  • In British Columbia, the 81.4 MW Upper Lillooet River hydroelectric facility began commercial operation on March 30, 2017.

LONGUEUIL, QC, May 9, 2017 /CNW Telbec/ - Innergex Renewable Energy Inc. (TSX: INE) ("Innergex" or the "Corporation") today released its operating and financial results for the first quarter ended March 31, 2017.

"Innergex is proud to have completed the commissioning of its largest hydroelectric facility and acquired a 44 MW wind farm in France during the quarter as well as to have announced its intention to acquire three additional wind projects in France after the quarter," said Michel Letellier, President and Chief Executive Officer of the Corporation. "Our recent commissioning and acquisitions demonstrate our ability to meet our growth objectives and expand our geographical presence and energy source diversification to further solidify our business by mitigating unpredictable weather scenarios."

"Despite overall lower production than the long-term average ("LTA") this quarter, we have been able to post strong results and deliver on our commitments while distributing a solid dividend to our shareholders," he added.

 

OPERATING RESULTS




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

Three months ended March 31

2017

2016

Power generated (MWh)

722,273

664,387

Long-term average (MWh)

820,634

557,022

Revenues

74,527

62,481

Adjusted EBITDA1

50,942

47,681

Net (loss) earnings

(2,334)

7,197

Net earnings, $ per share - basic and diluted

0.01

0.07




Trailing 12 months ended March 31


2017

2016

Free Cash Flow1

73,659

77,217

Payout Ratio1

95%

84%

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

 

Electricity Production

During the three-month period ended March 31, 2017, the Corporation's facilities produced 722 GWh of electricity or 88% of the LTA of 821 GWh. Overall, the hydroelectric facilities produced 93% of their LTA due mainly to below-average water flows in all markets except Quebec. The wind farms produced 84% of their LTA due to the below-average wind regimes in Quebec and France. The solar farm produced 109% of its LTA due to an above-average solar regime. The 9 % production increase over the same period last year is due mainly to the contribution of the recently commissioned or acquired facilities, which was partly offset by lower water flows in British Columbia and lower wind regimes in Quebec.

Revenues

For the three-month period ended March 31, 2017, the Corporation recorded revenues of $74.5 million, compared with $62.5 million in 2016. This 19% increase is attributable mainly to the contribution of the Mesgi'g Ugju's'n wind farm and the Big Silver Creek hydro facility commissioned in 2016 and to the acquisition of 10 wind facilities in France in 2016 and 2017, which was partly offset by lower production at our hydro facilities in British Columbia and at our Quebec wind farms.

Adjusted EBITDA

For the three-month period ended March 31, 2017, the Corporation recorded Adjusted EBITDA of $50.9 million, compared with $47.7 million for the same period last year. This increase of 7% is due mainly to the production and revenues from new facilities, partly offset by higher operating expenses, general and administrative expenses and prospective project expenses. The Adjusted EBITDA Margin decreased from 76.3% to 68.4% for the quarter due mainly to the payment related to water rights for 2011 and 2012 in British Columbia, which were reassessed, and to lower production at our hydro facilities in British Columbia and at our Quebec wind farms.

Net (Loss) Earnings

For the three-month period ended March 31, 2017, the Corporation recorded net loss of $2.3 million (basic and diluted net earnings of $0.01 per share), compared with net earnings of $7.2 million (basic and diluted net earnings of $0.07 per share) in 2016. The $9.5 million decrease in net earnings can be explained mainly by the $9.8 million increase in finance costs and the $10.1 million increase in depreciation and amortization, partly offset by a $3.3 million increase in Adjusted EBITDA and a $3.8 million unrealized net gain on derivative financial instruments.

Free Cash Flow and Payout Ratio

For the trailing twelve-month period ended March 31, 2017, the Corporation generated Free Cash Flow of $73.7 million, compared with $77.2 million for the corresponding period last year. This small decrease in Free Cash Flow is due mainly to greater scheduled debt principal payments and higher free cash flows attributed to non-controlling interests, which were partly offset by higher cash flows from operating activities before changes in non-cash operating working capital items and realized losses on derivative financial instruments. The realized loss on derivative financial instruments in the prior period was related to the settlement of the Big Silver and Mesgi'g Ugju's'n bond forwards contracts at the closing of the projects' financing. The Corporation also committed to invest more to pursue growth opportunities in new international markets.

For the trailing twelve-month period ended March 31, 2017, the dividends on common shares declared by the Corporation amounted to 95% of Free Cash Flow, compared with 84% for the corresponding period last year. This negative impact is due mainly to a slightly lower Free Cash Flow than in 2016 and 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 Innergex common shares and to the issuance of 94,000 shares following the exercise of stock options and 368,104 shares related to the Dividend Reinvestment Plan ("DRIP").

BUSINESS ACQUISITION

Completion of the Acquisition of the Yonne wind farm

On February 21, 2017, Innergex completed the acquisition of the 44 MW Yonne wind farm located in northern France. Innergex owns a 69.55% interest in the wind farm and Desjardins Group Pension Plan owns the remaining 30.45%.

The total purchase price amounts to €35.2 million (equivalent to $49.0 million), subject to certain adjustments and includes €3.8 million (equivalent to $5.3 million) of working capital. A €10.0 million (equivalent to $13.9 million) deposit had already been provided by the Corporation when the acquisition was first announced in March 2016. Innergex's net investment to pay for the purchase amounts to €10.7 million (equivalent to $14.9 million) and it fulfills its obligation to pay its portion of the purchase price through available funds. The remaining portion of the purchase price is paid by Desjardins Group Pension Plan for an amount of  €6.2 million (equivalent to $8.6 million) and with the funds generated by the financing of two French subsidiaries on February 10, 2017 for an amount of €8.4 million (equivalent to $11.6 million).

DEVELOPMENT PROJECTS

Commissioning Activities

Upper Lillooet River

In the first quarter, the Corporation began commercial operation of the 81.4 MW Upper Lillooet River run-of-river hydroelectric facility located in British Columbia. Construction began in October 2013 and was completed in March 2017. The Commercial Operation Date (COD) Certificate delivered to BC Hydro indicates an effective commissioning date of March 30, 2017. The Upper Lillooet River facility's average annual production is estimated to reach 334,000 MWh.

Construction activities

Boulder Creek

The construction of the Boulder Creek hydroelectric facility began in October 2013.

As at the date of this press release, the construction of the Boulder Creek hydroelectric facility is now fully completed. The tunnel has been filled mid-April and the commissioning activities are on-going and COD is expected in May 2017.

The insurance claims process for the fire continues, with interim progress payments being made. The Corporation expects to receive an indemnity, which should cover most of the financial consequences from the fire. 

SUBSEQUENT EVENTS

Final Agreement to Acquire Three Wind Projects in France

On May 3, 2017, the Corporation and Desjardins Group Pension Plan announced that a final agreement has been signed with Velocita Energy Developments (France) Limited (affiliate of Riverstone Holdings LLC) to purchase three wind projects in France, with a total aggregate installed capacity of 119.5 MW. The electricity to be produced will be sold under power purchase agreements at fixed price, of which a portion is adjusted according to inflation indexes, for an initial term of 15 years, with Electricité de France. The purchase price of the equity is approximately €51.4 million (or $76.2 million), subject to certain adjustments. Innergex's net share of the purchase price will amount to €31.3 million (or $46.4 million) and will be paid through available funds under its corporate revolving credit facility. Non-recourse debts related to the projects, which are already in place, will amount to €174.3 million (or $258.4 million) at the end of construction and will remain at the project level. The Corporation will reduce its exposure to exchange rate fluctuations by entering into long-term currency hedging instruments. Innergex will have a 69.55% interest in the wind farms and Desjardins Group Pension Plan will own the remaining 30.45%.

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on July 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

May 9, 2017

June 30, 2017

July 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, Wednesday, May 10, 2017, at 9:00 a.m. EDT. Its 2017 first quarter 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 48 operating facilities with an aggregate net installed capacity of 994 MW (gross 1,658 MW), including 30 hydroelectric facilities, 17 wind farms and one solar farm; (ii) interests in one project under construction with a net installed capacity of 17 MW (gross 25 MW), for which a power purchase agreement has 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 three-month period ended March 31, 2017, 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, Adjusted EBITDA Margin, 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 in this document to "Adjusted EBITDA Margin" are to Adjusted EBITDA divided by revenues.

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.

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 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; 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 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; 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.

For further information: Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 1239, jperron@innergex.com; Karine Vachon, Director - Communications, 450 928-2550, ext. 1222, kvachon@innergex.com

RELATED LINKS
www.innergex.com

Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890