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Innergex: Generating Solid Results Through Expertise and Leadership

  • Revenues from continuing operations up 23% to $142.8 million in Q3 2019 compared with Q3 2018.
  • Revenues Proportionate up 19% to $179.8 million in Q3 2019 compared with Q3 2018.
  • Adjusted EBITDA for continuing operations rose 28% to $107.4 million in Q3 2019 compared with Q3 2018.
  • Adjusted EBITDA Proportionate rose 24% to $135.8 million in Q3 2019 compared with Q3 2018.
  • Commissioning of the Foard City wind farm.
  • Ramp-up of sales at the Phoebe solar project ahead of full commissioning.

 


All amounts are in Canadian dollars, except as noted.

 

LONGUEUIL, QC , Nov. 12, 2019 /CNW Telbec/ - Innergex Renewable Energy Inc. (TSX: INE) ("Innergex" or the "Corporation") today released its operating and financial results for the third quarter ended September 30, 2019. The increases in revenues and Adjusted EBITDA for continuing operations are mainly due to the acquisition of the remaining 62% in the Cartier Wind Farms in October 2018 .

"We completed the commissioning of our largest wind farm to-date in less than a year and are poised to commission the largest solar project in Texas for which sales of energy have already begun. Additionally, construction activities have commenced at the Innavik hydroelectric site in northern Quebec that will provide renewable energy to this remote Inuit community for at least 40 years," said Michel Letellier , President and Chief Executive Officer of Innergex. "With our strong financial position and large portfolio of development and prospective projects, we remain on track to continue pursuing our growth organically as well as through acquisition opportunities."

OPERATING RESULTS

On May 23, 2019 , Innergex announced completion of the sale of its wholly owned subsidiary Magma Energy Sweden A.B. ("Magma Sweden") which owns an equity interest of approximately 53.9% in HS Orka hf ("HS Orka"), owner of  two geothermal facilities in operations, one hydro project in development and prospective projects in Iceland , which are now treated as discontinued operations. As a result, the comparative figures have been restated. The figures presented in this press release are for the continuing operations unless otherwise indicated.

 



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

Three months ended
September 30

Nine months ended
September 30

2019

2018

2019

2018



Restated 2,3


Restated 2,3

Production (MWh)

1,665,362

1,236,722

4,715,820

3,689,774

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

1,765,093

1,390,458

4,835,085

3,897,904

Revenues

142,814

116,464

413,926

343,166

Adjusted EBITDA1

107,351

83,683

305,842

248,909

Net earnings (loss) from continuing operations

9,896

5,989

(4,977)

7,399

Net earnings

9,703

9,456

16,194

11,477

Net earnings (loss) from continuing operations attributable to owners, $ per share - basic and diluted

0.10

0.06

(0.04)

0.09

Net earnings attributable to owners, $ per share - basic and diluted

0.09

0.07

0.10

0.10



Production Proportionate (MWh)1

2,149,151

1,652,413

5,875,960

4,603,304

Revenues Proportionate1

179,816

151,151

490,830

402,651

Adjusted EBITDA Proportionate1

135,796

109,553

356,311

291,311








Trailing twelve months ended
September 30




2019

2018




Restated 2

Restated 2

Free Cash Flow1



100,455

98,502

Payout Ratio1



93%

87%



1.

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

2.

For more information on the restatement, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

3.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.

 

Three-month period ended September 30, 2019
Production increased 35% and Production Proportionate increased 30% compared with the same quarter last year.

  • Production was 94% of the LTA:

The 23% increase in revenues and 28% in Adjusted EBITDA mainly stem from the contribution of the 62% remaining interest in the Cartier Wind Farms acquired in October 2018 , the higher revenues at the French facilities and to ramp-up of production at the Phoebe solar project.

The Adjusted EBITDA Margin increased from 71.9% to 75.2% for the three-month period due mainly to a higher margin in the hydro segment due to lower operating costs at most facilities and higher revenues in British Columbia and a higher margin in the wind segment explained mainly by lower operating costs.

The 19% increase in Revenues Proportionate and 24% increase in Adjusted EBITDA Proportionate are mainly due to higher revenues from the British Columbia and Chile facilities stemming from higher production, partly offset by lower revenues at the Shannon and Flat Top wind facilities in Texas .

For the three-month period ended September 30, 2019, the Corporation recorded net earnings from continuing operations of $9 .9 million (basic and diluted net earnings from continuing operations of $0.10 per share), compared with net earnings from continuing operations of $6.0 million (basic and diluted net earnings from continuing operations of $0.06 per share) for the corresponding period in 2018. The $3.9 million variation can be explained by a $23.7 million increase in Adjusted EBITDA, a $5 .0 million increase in the share of earnings of joint ventures and associates and a $4.2 million increase in other net revenues. These items were partly offset by a $12.1 million increase in depreciation and amortization, a $11 .5 million increase in finance costs, a $4.1 million unfavourable variation in unrealized net loss (gain) on financial instruments and a $1 .3 million increase in income tax expenses.

Nine-month period ended September 30, 2019
Production increased 28% and Production Proportionate increased 28% compared with the same quarter last year.

  • Production was 98% of the LTA:

The 21% increase in revenues and 23% in Adjusted EBITDA mainly stem from the contribution of the 62% remaining interest in the Cartier Wind Farms acquired in October 2018 , higher production at the Mesgi'g Ugju's'n facility and ramp-up of production at the Phoebe solar project.

The Adjusted EBITDA Margin increased from 72.5% to 73.9% for the nine-month period mainly explained by changes in the mix of segments as wind generation now represents a higher proportion of Adjusted EBITDA. Wind activities typically have a better return on revenues than hydro due to lower operating costs. The increase can also be explained by a higher margin from the Quebec wind facilities explained mainly by lower operating costs. These items were partly offset by a lower margin from the French facilities.

The 22% increase in Revenues Proportionate and 22% increase in Adjusted EBITDA Proportionate are mainly due to the investment in Energía Llaima and to higher revenues from the British Columbia facilities.

For the nine-month period ended September 30, 2019, the Corporation recorded a net loss from continuing operations of $5.0 million (basic and diluted net loss from continuing operations of $0.04 per share), compared with net earnings from continuing operations of $7.4 million (basic and diluted net earnings from continuing operations of $0.09 per share) for the corresponding period in 2018. The $12.4 million variation can be explained by a $32.6 million increase in depreciation and amortization, a $29.9 million increase in finance costs, a $13.1 million unfavourable variation in unrealized net loss (gain) on financial instruments, a $1.1 million increase in the share of loss of joint ventures and associates and a $0.6 million increase in income tax expenses. These items were partly offset by a $56.9 million increase in Adjusted EBITDA and a $8.0 million increase in other net revenues.

Free Cash Flow and Payout Ratio
For the trailing twelve-month period ended September 30, 2019, the Corporation generated Free Cash Flow of $100 .5 million, compared with $98 .5 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 working capital items and the income tax paid towards the taxable gain realized following an intercompany transaction related to the introduction of a tax equity investor in the Phoebe solar project; and the recovery of maintenance capital expenditures and prospective project expenses, net of attribution to non-controlling interests. These items were partly offset by greater scheduled debt principal payments, mainly from the acquisition of the Cartier Wind Farms and the French projects that reached term conversion in 2018.

For the trailing twelve-month period ended September 30, 2019, the dividends on common shares declared by the Corporation amounted to 93% of Free Cash Flow, compared with 87% for the corresponding period last year. This change results mainly from higher dividend payments as a result of the issuance of 24,327,225 shares on February 6, 2018, related to the Alterra acquisition; an increase in the quarterly dividend and additional shares issued under the Dividend Reinvestment Plan ("DRIP"). This item was partly offset by a $2.0 million increase in Free Cash Flow.

THIRD QUARTER OPERATIONAL HIGHLIGHTS

Debenture Redemption

On September 5, 2019 , the Corporation issued a notice of redemption and expiry of conversion privilege regarding the aggregate outstanding principal amount of $100 million of the 4.25% convertible unsecured subordinated debentures that were due to mature on August 31, 2020 (the "4.25% Convertible Debentures"). Of that principal amount, $45.7 million was converted at the holders' request into 3,049,530 common shares of the Corporation at a conversion price of $15 per share.

Debenture Offering
On September 30, 2019 , the Corporation completed its bought deal offering of convertible unsecured subordinated debentures (the "Debentures") for an aggregate principal amount of $125 million at a price of $1,000 per $1,000 principal amount of Debenture, bearing interest at a rate of 4.65% per annum, payable semi-annually, in arrears on October 31 and April 30 each year, commencing on April 30, 2020 (the "4.65% Debentures").

The net proceeds of the 4.65% Debenture offering was used to initially prepay indebtedness under the Corporation's revolving term credit facility, which was then available to be drawn, as required, to finance the redemption of all outstanding 4.25% Debentures. The remaining net proceeds will be available to be drawn, as required, to fund development projects and other growth opportunities or as general corporate purposes.

Construction Activities

Phoebe Solar Project ( Texas )
In the third quarter of 2019, the contractor completed project construction and the facility reached its full output. The operation and maintenance building was completed and the First Solar operations team assumed operation of the facility. Project demobilization commenced with project clean-up of the site laydown and office areas and final deficiency work. ERCOT Part 3 testing commenced in September and was completed in November. The project is expected to begin commercial operation in November 2019 .

Innavik Hydro Project ( Quebec )
In the third quarter of 2019, the Ministère de l'Environnement et de la Lutte contre les changements climatiques issued the project's authorization certificate. A Limited Notice to Proceed was signed in August 2019 . The first construction equipment were delivered in September and construction is planned to start in Q2 2020. Worker's camp on-site is being finalized. A 40-year PPA was signed with Hydro-Quebec Distribution on May 27, 2019 , which is expected to begin in the fourth quarter of 2022. The PPA is pending approval by the Régie de l'énergie of Quebec expected in Q1 2020.

Commissioning Activities

Foard City Wind Project ( Texas )
In the third quarter of 2019, the Corporation completed commercial operation of the 350.3 MW Foard City wind farm, that benefits from a 12-year power purchase agreement with Vistra Energy for 300 MW of its installed capacity. The remainder of the project's output will receive a merchant market price.

Foard City is expected to produce a gross estimated long-term average of 1,303 GWh, annual projected revenues of approximately US$19.7 million (CAN$26.1 million) and annual projected Adjusted EBITDA of approximately US$9.1 million (CAN$12.1 million), excluding PAYGO payment. Annual projected revenues and annual projected Adjusted EBITDA were reviewed to take into consideration revised assumptions regarding transmission congestion. Previous projections were revenues of US$21.8 million (CAN$28.9 million) and Adjusted EBITDA of US$14.1 million (CAN$18.7 million).

SUBSEQUENT EVENT

Over-Allotment Option
On October 2, 2019 , the Corporation announced that it has issued an additional $18.75 million aggregate principal amount of 4.65% Debentures following the exercise in full of the over-allotment option granted (the "Over-Allotment Option") to the underwriters in connection with the 4.65% Debentures offering.

After taking into account the Over-Allotment Option, the Corporation raised aggregate gross proceeds of $143 .75 million under the offering, of which $13.3 million was used to redeem the 4.25% Convertible Debentures.

Debenture Redemption
Subsequent to September 30, 2019 , and up to October 7 , $40.9 million of the remaining outstanding principal amount of the 4.25% Convertible Debentures was converted at the holders' request into 2,727,265 common shares of the Corporation at a conversion price of $15 per share. The remaining principal amount of $13.3 million was redeemed at par on October 8, 2019 , at a price of a thousand dollars per convertible debenture, plus accrued and unpaid interest up to, but excluding, October 8, 2019 . The redemption was financed with drawings under the Corporation's revolving term credit facility. On October 8, 2019 , the 4.25% Convertible Debentures were delisted from the TSX.

Yonne Project Loan Refinancing
Subsequent to September 30, 2019 , Innergex refinanced the Yonne project loan facilities.

DIVIDEND DECLARATION
The following dividends will be paid by the Corporation on January 15, 2020:

 


Date of
announcement

Record date

Payment date

Dividend per
common share

Dividend per
Series A

Preferred Share

Dividend per
Series C
Preferred Share

November 12, 2019

December 31, 2019

January 15, 2020

$0.1750

$0.2255

$0.359375

 

ADDITIONAL INFORMATION
Innergex's 2019 third quarter unaudited condensed interim consolidated financial statements, the notes thereto and the Management's Discussion and Analysis can be obtained on SEDAR at www.sedar.com and in the "Investors" section of the Corporation's website at www.innergex.com.

CONFERENCE CALL AND WEBCAST
The Corporation will hold a conference call and webcast on Tuesday November 12, 2019 , at 2:30 PM (EST) . Investors and financial analysts are invited to access the conference by dialing 1 888 231-8191 or 647 427-7450 or via https://bit.ly/329Dh9q or the Corporation's website at www.innergex.com. Journalists as well as the public may access this conference call via a listen mode only. A replay of the conference call will be available after the event on the Corporation's website.

About Innergex Renewable Energy Inc.
The Corporation is an independent renewable power producer which develops, acquires, owns and operates hydroelectric facilities, wind farms and solar farms. As a global corporation, Innergex conducts operations in Canada , the United States , France and Chile . Innergex manages a large portfolio of assets currently consisting of interests in 67 operating facilities with an aggregate net installed capacity of  2,338 MW (gross 3,238 MW), including 37 hydroelectric facilities, 26 wind farms and four solar farms. Innergex also holds interests in seven projects under development with a net installed capacity of 546 MW (gross 628 MW), two of which are currently under construction and prospective projects at different stages of development with an aggregate gross capacity totaling 7,767 MW. Respecting the environment and balancing the best interests of the host communities, its partners, and its investors are at the heart of the Corporation's development strategy. Its approach for building shareholder value is to generate sustainable cash flows, provide an attractive risk-adjusted return on invested capital and to distribute a stable dividend. Innergex Renewable Energy Inc. is rated BBB- by S&P.

Non-IFRS measures disclaimer
The unaudited condensed interim consolidated financial statements for the three- and nine-month periods ended September 30, 2019, 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. Production Proportionate, Revenues Proportionate, Adjusted EBITDA, Adjusted EBITDA Margin, Adjusted EBITDA Proportionate, Free Cash Flow, Adjusted Free Cash Flow, Payout Ratio and Adjusted Payout Ratio are not measures recognized by IFRS and have no standardized meaning prescribed by IFRS.

Revenues Proportionate
References in this document to "Innergex's share of Revenues of joint ventures and associates" are to Innergex's ownership interest in the equity or in the sponsors' equity, when applicable, of the Revenues of the joint ventures and associates. Readers are cautioned that Innergex's share of Revenues of joint ventures and associates should not be construed as an alternative to Revenues, as determined in accordance with IFRS.

References in this document to "Revenues Proportionate" are to Revenues plus Innergex's share of Revenues 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 Revenues Proportionate should not be construed as an alternative to Revenues, as determined in accordance with IFRS. Please refer to the "Operating Results" section for more information.

 




Three months ended
September 30

Nine months ended
September 30


2019

2018

2019

2018



Restated 1,2


Restated 1,2

Revenues

142,814

116,464

413,926

343,166

Innergex's share of Revenues of joint ventures and associates:





Toba Montrose (40%) 3

17,197

15,136

25,170

23,263

Shannon (50%) 3,5

1,013

1,556

5,558

4,834

Flat Top (51%) 4,5

582

2,376

6,305

5,129

Dokie (25.5%) 3

1,712

1,589

5,465

4,679

Jimmie Creek (50.99%)3

7,677

6,271

9,974

8,567

Umbata Falls (49%)

490

705

2,773

2,954

Viger-Denonville (50%)

1,017

1,195

4,175

4,200

Duqueco (50%)6,7

6,370

5,123

14,499

5,123

Guayacán (50%)6,7

469

323

1,479

323

Pampa Elvira (50%)6,7

475

413

1,506

413


37,002

34,687

76,904

59,485

Revenues Proportionate

179,816

151,151

490,830

402,651



1.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

2.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.

3.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and February 6, 2018, to September 30, 2018.

4.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and March 23, 2018, to September 30, 2018.

5.

Ownership interest is in the sponsor equity of Shannon and Flat Top. However, tax equity partners hold 100% of the tax equity interests.

6.

Innergex owns a 50% interest in Energía Llaima which owns the Guayacán (69.47% interest) and the Pampa Elvira (55% interest) facilities and Duqueco which includes the Mampil (100% interest) and Peuchén (100% interest) facilities.

7.

For the period from July 1, 2019 to September 30, 2019 and for the period from July 3, 2018 or July 5, 2018 to September 30, 2018 and for the period from January 1, 2019 to September 30, 2019 and from July 3, 2018 or July 5, 2018 to September 30, 2018.



 

Adjusted EBITDA and Adjusted EBITDA Margin
References in this document to "Adjusted EBITDA" are to net earnings (loss) from continuing operations to which are added (deducted) provision (recovery) for income tax expenses, finance cost, depreciation and amortization, other net expenses, share of (earnings) loss of joint ventures and associates and unrealized net (gain) loss on financial instruments. 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.

 




Three months ended
September 30

Nine months ended
September 30


2019

2018

2019

2018



Restated 1,2


Restated 1,2

Net earnings (loss) from continuing operations

9,896

5,989

(4,977)

7,399

Income taxes expenses

3,749

2,466

1,164

579

Finance costs

59,474

47,939

170,704

140,814

Depreciation and amortization

48,343

36,271

141,558

108,971

EBITDA

121,462

92,665

308,449

257,763

Other net (revenues) expenses

(3,917)

313

(2,639)

5,319

Share of earnings of joint ventures and associates

(16,225)

(11,192)

(9,193)

(10,276)

Unrealized net loss (gain) on financial instruments

6,031

1,897

9,225

(3,897)

Adjusted EBITDA

107,351

83,683

305,842

248,909

Adjusted EBITDA margin

75.2%

71.9%

73.9%

72.5%



1.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

2.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.

 

Adjusted EBITDA Proportionate
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.

 





Three months ended
September 30

Nine months ended
September 30


2019

2018

2019

2018



Restated 1,2


Restated 1,2

Adjusted EBITDA

107,351

83,683

305,842

248,909

Innergex's share of Adjusted EBITDA of joint ventures and associates:





Toba Montrose (40%) 3

15,030

13,004

20,046

18,883

Shannon (50%) 3,5

(872)

492

1,237

1,820

Flat Top (51%) 4,5

(1,213)

909

711

1,813

Dokie (25.5%) 3

1,095

1,062

3,799

3,305

Jimmie Creek (50.99%)3

6,908

5,738

8,278

7,395

Umbata Falls (49%)

315

609

2,178

2,630

Viger-Denonville (50%)

868

946

3,418

3,446

Duqueco (50%)6,7

5,454

3,134

9,115

3,134

Guayacán (50%)6,7

469

38

1,022

38

Pampa Elvira (50%)6,7

391

(62)

665

(62)


28,445

25,870

50,469

42,402

Adjusted EBITDA Proportionate

135,796

109,553

356,311

291,311



1.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

2.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.

3.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and February 6, 2018, to September 30, 2018.

4.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and March 23, 2018, to September 30, 2018.

5.

Ownership interest is in the sponsor equity of Shannon and Flat Top. However, tax equity partners hold 100% of the tax equity interests.

6.

Innergex owns a 50% interest in Energía Llaima which owns the Guayacán (69.47% interest) and the Pampa Elvira (55% interest) facilities and Duqueco which includes the Mampil (100% interest) and Peuchén (100% interest) facilities.

7.

For the period from July 1, 2019 to September 30, 2019 and for the period from July 3, 2018 or July 5, 2018 to September 30, 2018 and for the period from January 1, 2019 to September 30, 2019 and from July 3, 2018 or July 5, 2018 to September 30, 2018.

Adjusted Net Earnings (Loss) from continuing operations
References to "Adjusted Net Earnings (Loss) from continuing operations" are to net earnings or losses from continuing operations of the Corporation, to which the following elements are added (subtracted): unrealized net (gain) loss on financial instruments; realized (gain) loss on financial instruments; income tax expense (recovery) related to the above items; and the share of unrealized net (gain) loss on derivative financial instruments of joint ventures and associates, net of related tax. Innergex uses derivative financial instruments to hedge its exposure to various risks. Accounting for derivatives under IFRS requires that all derivatives are marked-to-market with changes in the mark-to-market of the derivatives for which hedge accounting is not applied being taken to the profit and loss account. The application of this accounting standard results in a significant amount of profit and loss volatility arising from the use of derivatives that are not designated for hedge accounting. The Adjusted Net Earnings (Loss) from continuing operations of the Corporation aims to eliminate the impact of the mark-to-market rules on derivatives on the profit and loss of the Corporation. Innergex believes that the analysis and presentation of net earnings or loss on this basis enhances understanding of the Corporation's operating performance. Readers are cautioned that Adjusted Net Earnings (Loss) from continuing operations should not be construed as an alternative to net earnings, as determined in accordance with IFRS.





Impact on net earnings (loss) of financial instruments

Three months ended
September 30

Nine months ended
September 30

2019

2018

2019

2018



Restated 1,2


Restated1,2

Net earnings (loss) from continuing operations

9,896

5,989

(4,977)

7,399

Add (Subtract):





Unrealized net loss (gain) on financial instruments

6,031

1,897

9,225

(3,897)

Realized (gain) loss on financial instruments

(1,973)

4

(2,421)

(822)

Income tax expenses (recovery of) related to above items

84

(342)

(690)

2,055

Share of unrealized net (gain) loss on financial instruments of joint ventures and associates, net of related income tax

(453)

7,670

(1,580)

(144)

Adjusted Net Earnings (Loss) from continuing operations

13,585

15,218

(443)

4,591



1.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

2.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.



Free Cash Flow and Payout Ratio
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.

References to "Adjusted Free Cash Flow" are to Free Cash Flow excluding prospective project expenses and non-recurring items.

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

References to "Adjusted Payout Ratio" are to dividends declared on common shares divided by Adjusted Free Cash Flow after the impact of the DRIP.



Free Cash Flow and Payout Ratio calculation

Trailing twelve months ended
September 30

2019

2018


Restated 2

Restated 2

Cash flows from operating activities

213,585

246,761

Add (Subtract) the following items:



Changes in non-cash operating working capital items

6,956

(35,736)

Maintenance capital expenditures net of proceeds from disposals

(10,282)

(8,667)

Scheduled debt principal payments

(112,604)

(85,230)

Free Cash Flow attributed to non-controlling interests1

(18,601)

(22,722)

Dividends declared on Preferred shares

(5,942)

(5,942)

Transaction costs related to realized acquisitions

1,593

10,866

Realized losses (gains) on derivative financial instruments

6,914

(828)

Recovery of maintenance capital expenditures and prospective project expenses on sale of HS Orka, net of attribution to non-controlling interests

8,242

Income tax paid on realized intercompany gain

10,594

Free Cash Flow

100,455

98,502



Dividends declared on common shares

93,258

85,527

Payout Ratio

93%

87%



Adjust for the following items:


Prospective projects expenses

16,945

17,145

Adjusted Free Cash Flow

117,400

115,647



Dividends declared on common shares - DRIP adjusted

90,856

75,598

Adjusted Payout Ratio

77%

65%



1.

The portion of Free Cash Flow attributed to non-controlling interests is subtracted, regardless of whether an actual distribution to non-controlling interests is made, in order to reflect the fact that such distributions may not occur in the period they are generated.

2.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

3.

The sale of HS Orka has allowed for the recovery of maintenance capital expenditures and prospective project expenses incurred thereon since the acquisition of the project in February 2018, totaling $5.7 million and $9.6 million, respectively. An amount of $7.1 million was deducted from the total recovery as it pertains to non-controlling interests.



Production Proportionate
References in this document to "Innergex's share of Production of the joint ventures and associates" are to Innergex's ownership interest in the equity or in the sponsors' equity when applicable of the Production of the joint ventures and associates.

References in this document to "Production Proportionate" are to Production plus Innergex's share of Production of the joint ventures and associates. Innergex believes that the presentation of this measure enhances the understanding of the Corporation's operating performance.

 





Three months ended
September 30

Nine months ended
September 30

(in MWh)

2019

2018

2019

2018



Restated1,2


Restated 1,2

Production

1,665,362

1,236,722

4,715,820

3,689,774

Innergex's share of Production of joint ventures and associates:





Toba Montrose (40%) 3

152,144

137,547

243,782

238,039

Shannon (50%) 3,5

72,155

60,796

252,936

226,192

Flat Top (51%) 4,5

101,347

79,263

332,474

205,549

Dokie (25.5%) 3

13,912

13,983

44,799

42,401

Jimmie Creek (50.99%)3

61,723

51,935

87,944

81,369

Umbata Falls (49%)

6,486

9,360

36,635

37,192

Viger-Denonville (50%)

6,729

7,942

27,626

27,923

Duqueco (50%)6,7

61,864

47,579

109,161

47,579

Guayacán (50%)6,7

4,199

3,990

14,985

3,990

Pampa Elvira (50%)6,7

3,230

3,296

9,798

3,296


483,789

415,691

1,160,140

913,530

Production Proportionate

2,149,151

1,652,413

5,875,960

4,603,304



1.

For more information, please refer to the "Accounting Changes" section of the Management's Discussion and Analysis of the third quarter of 2019.

2.

For more information, please refer to the "Discontinued Operations" section of the Management's Discussion and Analysis of the third quarter of 2019.

3.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and February 6, 2018, to September 30, 2018.

4.

For a complete three-month period in 2019 and 2018 and for the period from January 1, 2019 to September 30, 2019 and March 23, 2018, to September 30, 2018.

5.

Ownership interest is in the sponsor equity of Shannon and Flat Top. However, tax equity partners hold 100% of the tax equity interests.

6.

Innergex owns a 50% interest in Energía Llaima which owns the Guayacán (69.47% interest) and the Pampa Elvira (55% interest) facilities and Duqueco which includes the Mampil (100% interest) and Peuchén (100% interest) facilities.

7.

For the period from July 1, 2019 to September 30, 2019 and for the period from July 3, 2018 or July 5, 2018 to September 30, 2018 and for the period from January 1, 2019 to September 30, 2019 and from July 3, 2018 or July 5, 2018 to September 30, 2018.

 

Forward-Looking Information
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 (including tax equity funding) of the projects under construction and the advanced-stage prospective projects, sources and impact of funding project acquisitions, execution of non–recourse project level financing (including the timing and amount thereof), and strategic, operational and financial benefits and accretion expected to result from such acquisitions, 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", "would", "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 projected Adjusted EBITDA Proportionate, to inform readers of the potential financial impact of expected results, of the expected commissioning of Development Projects, of the potential financial impact of completed and future acquisitions and of the Corporation's ability to sustain current dividends and to fund its growth. Such information may not be appropriate for other purposes.

Forward-looking Information is based on certain key assumptions made by Innergex, including, without restrictions, assumptions concerning  project performance, economic, financial and financial market conditions, expectations and assumptions concerning availability of capital resources and timely performance by third-parties of contractual obligations, receipt of regulatory approvals and the divestiture of select assets. Although Innergex believes that the expectations and assumptions on which such forward-looking information is based are reasonable, under the current circumstances, readers are cautioned not to rely unduly on this forward-looking information as no assurance can be given that they will prove to be correct. The forward-looking information contained in this press release is made as of the date hereof and Innergex 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 hereof, unless so required by law.

Since forward-looking information addresses future events and conditions, it is by its very nature subject to inherent risks and uncertainties. Forward-looking information involves risks and uncertainties that may cause actual results or performance to be materially different from those expressed, implied or presented by the forward-looking information. These include, but are not limited to, the risks associated with the ability of Innergex to execute its strategy for building shareholder value (including through the potential divestiture of selected assets), its ability to raise additional capital and the state of the capital markets, liquidity risks related to derivative financial instruments, variability in hydrology, wind regimes and solar irradiation, uncertainties surrounding the development of new facilities, interest rate fluctuations and refinancing risks, financial leverage and restrictive covenants governing current and future indebtedness, failure to realize the anticipated benefits of such acquisitions, variability of installations performance and related penalties, foreign exchange fluctuations and the fact that revenues from certain facilities will vary based on the market (or spot) price of electricity.

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 LTA.

 

Improper assessment of water, wind and solar resources and associated electricity production

 

Variability in hydrology, wind regimes and solar irradiation

 

Equipment supply risk, including failure or unexpected operations and maintenance activity

 

Natural disasters and force majeure

 

Regulatory and political risks affecting production

 

Health, safety and environmental risks affecting production

 

Variability of installation performance and related penalties

 

Availability and reliability of transmission systems

 

Litigation

Projected revenues
For each facility, expected annual revenues are estimated by multiplying the LTA by a price for electricity stipulated in the PPA secured with a public utility or other creditworthy counterparty mainly. In most cases these PPAs stipulate a base price for electricity produced and, in some cases, a price adjustment depending on the month, day and hour of its delivery. This excludes facilities, which receive revenues, based on the market (or spot) price for electricity, including 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. In most cases, power purchase agreements also contain an annual inflation adjustment based on a portion of the Consumer Price Index.

See principal assumptions, risks and uncertainties identified under "Expected Production"

 

Reliance on PPAs

 

Revenues from certain facilities will vary based on the market (or spot) price of electricity

 

Fluctuations affecting prospective power prices

 

Changes in general economic conditions

 

Ability to secure new Power Purchase Agreements or Renew any Power Purchase Agreement

Projected Adjusted EBITDA
For each facility, the Corporation estimates annual operating earnings by adding (deducting) to net earnings (loss) provision (recovery) for income tax expenses, finance cost, depreciation and amortization, other net expenses, share of (earnings) loss of joint ventures and associates and unrealized net (gain) loss on financial instruments.

See principal assumptions, risks and uncertainties identified under "Expected Production" and "Expected Revenues"

 

Variability of facility performance and related penalties

 

Unexpected maintenance expenditures

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 and Prospective Project, the Corporation may provide (where available) an estimate of potential installed capacity, estimated project costs, project financing terms and each project's development and construction schedule, based on its extensive experience as a developer, in addition to information directly related to incremental internal costs, site acquisition costs and financing costs, which are eventually adjusted for the projected costs and construction schedule provided by the engineering, procurement and construction ("EPC") contractor retained for the project.

The Corporation provides indications based on assumptions regarding its current strategic positioning and competitive outlook, as well as scheduling and construction progress, for its Development Projects and its Prospective Projects, which the Corporation evaluates based on its experience as a developer.

Uncertainties surrounding development of new facilities

 

Performance of major counterparties, such as suppliers or contractors

 

Delays and cost overruns in the design and construction of projects

 

Ability to secure appropriate land

 

Obtainment of permits

 

Health, safety and environmental risks

Relationships with stakeholders

 

Equipment supply

 

Interest rate fluctuations and financing risk

 

Risks related to U.S. PTCs and ITCs, changes in U.S. corporate tax rates and availability of tax equity financing

 

Regulatory and political risks

 

Higher-than-expected inflation

 

Natural disaster

 

Foreign market growth and development risks

 

Outcome of insurance claims

Qualification for PTCs and ITC and Expected Tax Equity Investment Flip Point

For certain Development Projects in the United States, the Corporation has conducted on- and off-site activities expected to qualify its Development Projects for PTCs or ITC at the full rate and to obtain tax equity financing on such a basis. To assess the potential qualification of a project, the Corporation takes into account the construction work performed and the timing of such work. The expected  Tax Equity Flip Point for tax equity investment is determined according to the LTAs and revenues of each such project and is subject in addition to the related risks  mentioned above.

Risks related to U.S. PTCs and ITC, changes in U.S. corporate tax rates and availability of tax equity financing

 

Regulatory and political risks

 

Delays and cost overruns in the design and construction of projects

 

Obtainment of permits

 

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.


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