May 15, 2018 - 12:59 PM EDT
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Innergex Reports its 2018 First Quarter Results

Canada NewsWire

SIGNIFICANT INCREASES IN FINANCIAL RESULTS DUE TO ACQUISITIONS AND COMMISSIONINGS

  • Innergex completed its largest acquisition to date, Alterra Power Corp., with participation in nine operating facilities
  • Revenues increased 58% to $117.9 million compared with the same period last year.
  • Adjusted EBITDA rose 56% to $79.3 million compared with the same period last year.
  • Adjusted EBITDA Proportionate rose 59% to $84.7 million compared with the same period last year.
  • The 200 MW Flat Top wind farm in Texas, U.S. reached commercial operation on March 23, 2018.

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

LONGUEUIL, QC, May 15, 2018 /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, 2018.

"We were successful this past quarter at integrating the activities of our largest acquisition to date, reaching commercial operation at a 200 MW wind farm in the United States and making progress with our prospective projects," said Michel Letellier, President and Chief Executive Officer of Innergex.

"We are very pleased with our recent announcement regarding Foard City, a US wind project to be developed later this year for which a 12-year power purchase agreement was obtained," added Letellier. "It demonstrates our commitment to take advantage of the opportunities ahead of us and to reach and even exceed our objective of 2,000 MW of net installed capacity by 2020."

 

OPERATING RESULTS



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

Three months ended March 31

2018


2017

Power generated (MWh)

1,136,345


722,273

Long-term average (MWh) ("LTA")

1,182,591


820,634

Revenues

117,881


74,527

Adjusted EBITDA1

79,343


50,942

Adjusted EBITDA Proportionate1

84,675


53,192

Net loss

(14,588)


(2,496)

Net (loss) earnings, $ per share - basic and diluted

(0.07)


0.01






Trailing twelve months ended
March 31


2018


2017

Free Cash Flow1

96,233


73,659

Payout Ratio1

79%


95%

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

 

Electricity Production

During the three-month period ended March 31, 2018, the Corporation's facilities produced 1,136 GWh of electricity or 96% of the LTA of 1,183 GWh. Overall, the hydroelectric facilities produced 92% of their LTA due mainly to below-average water flows in British Columbia, outages at several British Columbia facilities caused by maintenance activities and winter hazards and to lower production from challenging post-commissioning activities currently being addressed at the Upper Lillooet River facility, partly offset by slightly above-average water flows in Quebec, Ontario and Idaho.The wind farms produced 97% of their LTA due mainly to below-average wind regimes in Quebec and challenging post-commissioning activities currently being addressed at the Mesgi'g Ugju's'n facility, partly offset by above-average wind regimes in France. The geothermal facilities produced 100% of their LTA. The solar farm produced 92% of its LTA due to a below-average solar regime.

Revenues

In the first quarter of 2018, the Corporation recorded revenues of $117.9 million compared with $74.5 million for the three-month period ended March 31, 2017. The increase is attributable mainly to the contribution of the acquisitions of Alterra and wind facilities in France in 2017 as well as to revenue compensation received from a manufacturer for low-availability of equipment at a wind farm, higher production at the Mesgi'g Ugju's'n facility and higher production at all the French wind facilities, partly offset by lower production at the British Columbia hydro facilities.

Adjusted EBITDA

In the first quarter  of 2018, the Corporation recorded Adjusted EBITDA of $79.3 million compared with $50.9 million in 2017. This increase is due mainly to higher production and revenues from the facilities commissioned and acquired in 2017 and 2018, partly offset by higher operating expenses, general and administrative expenses and prospective project expenses. The Adjusted EBITDA Margin decreased from 68.4% to 67.3% for the three-month period due mainly to a larger increase in expenses as opposed to the increase in revenues resulting from the integration of the HS Orka geothermal operations, which generate a lower margin related to its higher maintenance, daily operations and power purchasing costs, and to challenging post-commissioning activities at the Upper Lillooet River facility.

Adjusted EBITDA Proportionate

The Corporation recorded Adjusted EBITDA Proportionate of $84.7 million in the first quarter of 2018 compared with $53.2 million in 2017. The increase is due mainly to higher Adjusted EBITDA and a higher share of Adjusted EBITDA of joint ventures and associates stemming from the addition of the facilities acquired in 2018.

Net Loss

For the three-month period ended March 31, 2018, the Corporation recorded net loss of $14.6 million (basic and diluted net loss of $0.07 per share) compared with net loss of $2.5 million (basic and diluted net earnings of $0.01 per share) for the corresponding period in 2017. The $12.1 million increase in net loss can be explained by the $17.2 million increase in unrealized net loss on financial instruments, the $16.2 million increase in finance costs, the $9.6 million increase in depreciation and amortization and the $2.5 million increase in other net expenses (revenues), partly offset by the $28.4 million increase in Adjusted EBITDA, the $2.4 million increase in the share of earnings of joint ventures and associates and $2.6 million recovery in income taxes.

Free Cash Flow and Payout Ratio

For the trailing twelve-month period ended March 31, 2018, the Corporation generated Free Cash Flow of $96.2 million compared with $73.7 million for the corresponding period last year. The increase in Free Cash Flow is due mainly to higher cash flows from operating activities before changes in non-cash operating working capital items, partly offset by higher maintenance capital expenditures net of proceeds from disposals and higher Free Cash Flow attributed to non-controlling interests and greater scheduled debt principal payments.

For the trailing twelve-month ended March 31, 2018, the dividends on common shares declared by the Corporation amounted to 79% of Free Cash Flow compared with 95% for the corresponding period 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 2017 which generated higher Free Cash Flow, partly offset by higher dividend payments as a result of the issuance of 24,327,225 shares on February 6, 2018, related to the Alterra acquisition, to the increase in the quarterly dividend and to additional shares following the exercise of stock options and issued under the Dividend Reinvestment Plan ("DRIP").

DEVELOPMENT PROJECTS

Commissioning Activities

Flat Top
In the first quarter, the Corporation began commercial operation of the 200 MW Flat Top wind farm located in Texas, U.S. Construction began prior to its acquisition by Innergex and was substantially completed in March 2018. The Commercial Operation Date ("COD") was reached on March 23, 2018. The Flat Top wind farm will sell 100% of its output to the ERCOT power grid and set the power price on the majority of its revenue under a 13-year commodity hedge agreement with an affiliate of a large US-based financial institution, commencing on August 1, 2018. Concurrent with commercial operation, Flat Top completed a US$211.3 million tax equity financing of the project, some of whose proceeds were used primarily to retire the project's construction loan.

Construction activities

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 at the date of this press release, construction work officially started and a public open ceremony took place at the end of February, following the approval by the local government of the construction permit. Together with the Construction Permit, the project has received its Environmental Impact Assessment ("EIA") and obtained all necessary water rights, land contracts, exploration permits, development licence and municipal approvals through a specific local land-use plan.

Development activities

Foard City
The 350 MW Foard City wind project development is progressing very well, with site control complete, as well as other development milestones such as environmental impact assessments and the signing of local property tax abatement agreements. In May 2018, a 12-year power purchase agreement was signed for 300 MW for which sales will start upon the facility reaching commercial operation. The project located in Texas, USA has also executed an interconnection agreement with Electric Transmission Texas, LLC. On-site activities intended to qualify the Foard City wind project for US renewable tax incentives (PTCs) were performed since 2016. Full notice to proceed with construction is expected to be issued in the fourth quarter of 2018 to achieve commercial operation in the third quarter of 2019.

SUBSEQUENT EVENTS

Electricity purchase agreements renewed with BC Hydro

On April 16, 2018, Innergex announced the renewal of the electricity purchase agreement for the Brown Lake hydro facility. The renewed agreement is for a 40-year term and is effective as of April 1, 2018. The agreement is subject to approval by the British Columbia Utilities Commission.

On April 16, 2018, Innergex and Sekw'el'was Cayoose Creek Band announced the renewal of the electricity purchase agreement for the Walden North hydro facility. The renewed agreement is for a 40-year term and is effective as of April 1, 2018. The agreement is subject to approval by the British Columbia Utilities Commission.

First Court rules in favor of HS Orka

Since 2016, a conflict takes place between HS Orka and HS Veitur with regards to termination by HS Veitur of an agreement regarding payments of the pension liability. On April 17, 2018, the First Court of Iceland ruled in favor of HS Orka. HS Veitur has 30 days from April 17, 2018 to file an appeal to the Supreme Court. A claim for $9.9 million was filed and is included in accounts receivable on the balance sheet.

Extension of foreign exchange forward contracts

On April 23, 2018, the Corporation extended all its foreign exchange forward contracts that hedge its exposure to foreign exchange rate on its investment in France. The contracts have been extended for a period of two years following their original expiry date ranging from April 2018 to August 2019.

Acquisition of remaining interests in three hydro facilities

On May 15, 2018, Innergex announced that it has acquired Ledcor Power Ltd,'s 33.3% interest in Creek Power Inc., a company that indirectly owns the Fitzsimmons Creek (7.5 MW), Boulder Creek (25.3 MW) and Upper Lillooet River (81.4 MW) hydro facilities located in British Columbia as well as a portfolio of prospective projects. Innergex already owned the other 67.7% interest in Creek Power Inc. Innergex also owned all the preferred equity for an amount of $98.4 million bearing an annualized after-tax return of 12.9%.

Partnership and acquisition in Chile

On May 15, 2018, Innergex and Energía Llaima, a renewable energy company located in Chile, are pleased to announce that they have been selected in a bid process to acquire in partnership the Duqueco hydro project (140 MW) which includes two hydro facilities in Chile. The acquisition is subject to certain regulatory approvals in Chile and to reaching a final partnership agreement between the parties. In addition, Innergex has signed an exclusivity agreement with Energía Llaima for a joint venture partnership to acquire a 50% stake in the company. Final agreements should be reached in the coming weeks in respect to this venture. 

The Duqueco hydro project includes two hydro facilities commissioned in 2001, Peuchen (85 MW) and Mampil (55 MW). Innergex is expecting an Adjusted EBITDA of approximately US$21 million ($26.8 million) annually for the Duqueco project. The purchase price, net of an estimated US$10 million ($12.8 million) of cash, is approximately US$210 million ($268 million), subject to certain adjustments and a financing of US$140 million ($178.8 million) is to be granted by a South America bank, Itaú, to cover a portion of the purchase price. Innergex's net share of the remaining purchase price will amount to about US$80 million ($102.2 million). In addition, the Corporation made a deposit to secure financing of US$10 million ($12.8 million). Both amounts will be paid through available funds under its corporate revolving credit facility.

Energía Llaima owns interest in two facilities in operations, a run-of-river hydro facility (12 MW) and a solar thermal facility (34 MW), two run-of-river hydro facilities in development (125 MW) and other early development stage projects. Upon signing a final partnership agreement, Innergex would own 50% of Energía Llaima for a total commitment of US$110 million ($140.5 million) to be invested in the next three years. In addition to the investment in the Duqueco project, Innergex will invest an additional US$10 million ($12.8 million) in Energía Llaima to contribute to its working capital. With these investments, Innergex's commitment would almost be reached. 

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on July 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

May 15, 2018

June 29, 2018

July 16, 2018

$0.1700

$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 REMINDER

The Corporation will hold a conference call and webcast tomorrow, Wednesday, May 16, 2018, at 9 AM (EDT). Its 2018 first quarter 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. 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.

ANNUAL AND SPECIAL MEETING OF SHAREHOLDERS

The Corporation will hold its Annual and Special Meeting of Shareholders on Tuesday, May 15, 2018, at 4 PM (EDT). Shareholders are invited to attend the meeting at the Club St-James, 1145 Union Avenue, Montréal QC  H3B 3C2 or to listen to the meeting via a webcast at https://event.on24.com/wcc/r/1673916/D32BE4D9F5A01A64DF84B095D7B2E11C.

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 64 operating facilities with an aggregate net installed capacity of 1,642 MW (gross 2,886 MW), including 34 hydroelectric facilities, 25 wind farms, three solar farms and two geothermal facilities. Innergex also holds interests in two projects under development with a net installed capacity of 355 MW (gross 360 MW) one of which is currently under construction and prospective projects at different stages of development with an aggregate net capacity totalling 8,180 MW (gross 8,850 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, 2018, 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 "Innergex's share of Adjusted EBITDA of the joint ventures and associates" are to Innergex's ownership interest in the equity or in the sponsors' equity when applicable of the Adjusted EBITDA of the joint ventures and associates.

References in this document to "Adjusted EBITDA Proportionate" are to Adjusted EBITDA plus Innergex's share of Adjusted EBITDA of the joint ventures and associates. 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 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.

Forward-looking information disclaimer

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"), including the Corporation'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 "approximately", "may", "will", "could", "believes", "expects", "intends", "should", "plans", "potential", "project", "anticipates", "estimates", "scheduled" or "forecasts", or other comparable terminology that state that certain events will or will not occur. It represents the projections and expectations of the Corporation relating to future events or results as of the date of this press release.

Forward-Looking Information includes future-oriented financial information or financial outlook within the meaning of securities laws, such as expected production, projected revenues, projected Adjusted EBITDA, 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 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, 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 mainly. These agreements stipulate a base price and, in some cases, a price adjustment depending on the month, day and hour of delivery, except for the Miller Creek hydroelectric facility, which receives a price based on a formula using the Platts Mid-C pricing indices, the Horseshoe Bend hydroelectric facility, for which 85% of the price is fixed and 15% is adjusted annually as determined by the Idaho Public Utility Commission. Revenues at the HS Orka facilities also fluctuates with the price of aluminum, as certain of those PPAs are linked to such price. 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, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls, Viger-Denonville and Blue Lagoon, 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, royalties and cost of power (if applicable); these are predictable and relatively fixed, varying mainly with inflation (except for maintenance expenditures and cost of power ). 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, East Toba, Flat Top, Jimmie Creek, Kokomo, Montrose Creek, Shannon, Spartan, Umbata Falls, Viger-Denonville and Blue Lagoon, 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 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 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, geothermal resources 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.

View original content: http://www.newswire.ca/en/releases/archive/May2018/15/c1850.html

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] CNW Group 2018


Source: Canada Newswire (May 15, 2018 - 12:59 PM EDT)

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