Innergex reports its second quarter 2017 results

COMMISSIONING OF INNERGEX 31ST HYDRO FACILITY
ACQUISITION OF THREE WIND FARMS IN FRANCE FOR 119.5 MW

  • Revenues increased 25% to $109.5 million compared with the same period last year.
  • Adjusted EBITDA rose 29% to $85.9 million compared with the same period last year.
  • Innergex and Desjardins Group Pension Plan completed the acquisition of the Rougemont 1-2 and Vaite wind facilities in France with a total aggregate installed capacity of 119.5 MW.
  • In British Columbia, the 25.3 MW Boulder Creek hydroelectric facility began commercial operation on May 16, 2017.

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

LONGUEUIL, QC, Aug. 3, 2017 /CNW Telbec/ – Innergex Renewable Energy Inc. (TSX: INE) (“Innergex” or the “Corporation”) today released its operating and financial results for the second quarter ended June 30, 2017.

“The last quarter was exhilarating for the Innergex team with the commissioning of our 31st hydro facility in Canada, the completion of a 119.5 MW acquisition and the signing of a final agreement to purchase two additional wind farms in France,” said Michel Letellier, President and Chief Executive Officer of the Corporation. “We deliver on our promise to pursue growth in Canada and internationally both by acquiring and developing projects.”

“Our second quarter results were impacted by lower production than the long-term average (“LTA”) mainly due to challenging post-commissioning activities at Upper Lillooet River, Boulder Creek and Mesgi’g Ugju’s’n facilities. Engineering and operational adjustments are being made to rectify the situation and we should reach full potential in the coming months. Our current geographic diversification and the complementarity of hydroelectric, wind and solar power generation nonetheless mitigated the impact of the lower production on our results and should continue to benefit us in the long-term,” he added.

OPERATING RESULTS

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

Three months ended June 30

Six months ended June 30

2017

2016

2017

2016

Power generated (MWh)

1,322,781

1,176,451

2,045,053

1,840,838

Long-term average (MWh)

1,437,100

1,045,265

2,257,734

1,602,286

Revenues

109,530

87,784

184,056

150,265

Adjusted EBITDA1

85,920

66,863

136,861

114,542

Net earnings

14,100

15,677

11,766

22,873

Net earnings, $ per share – basic and diluted

0.12

0.12

0.13

0.19

Free Cash Flow1

75,888

78,939

Payout Ratio1

93

%

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 June 30, 2017, the Corporation’s facilities produced 1,323 GWh of electricity or 92% of the LTA of 1,437 GWh. Overall, the hydroelectric facilities produced 95% of their LTA due mainly to lower production from post-commissioning activities at the Upper Lillooet River and Boulder Creek facilities during the quarter, partly offset by above-average water flows in Quebec and Ontario. The wind farms produced 84% of their LTA due to lower production from post-commissioning activities at the Mesgi’g Ugju’s’n facility and to the below-average wind regimes in Quebec and France. The solar farm produced 101% of its LTA due to an average solar regime. The 12 % 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 production at most of our British Columbia hydro facilities and to lower production at our Quebec wind farms.

During the six-month period ended June 30, 2017, the Corporation’s facilities produced 2,045 GWh of electricity or 91% of the LTA of 2,258 GWh. Overall, the hydroelectric facilities produced 94% of their LTA due mainly to lower production from post-commissioning activities at the Upper Lillooet River and Boulder Creek facilities during the period and below-average water flows in British Columbia, partly offset by above-average water flows in Quebec and Ontario. The wind farms produced 84% of their LTA due to lower production from post-commissioning activities at the Mesgi’g Ugju’s’n facility and below-average wind regimes in Quebec and France. The solar farm produced 104% of its LTA due to an above-average solar regime. The 11% 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 production at most of our British Columbia hydro facilities and to lower production at our Quebec wind farms.

Revenues

For the three-month period ended June 30, 2017, the Corporation recorded revenues of $109.5 million, compared with $87.8 million for three-month period ended June 30, 2016. This 25% increase is attributable mainly to the contribution of the Mesgi’g Ugju’s’n wind farm and Big Silver Creek hydro facility commissioned in 2016 and of the Upper Lillooet River and Boulder Creek hydro facilities commissioned in 2017 as well as to the acquisition of the Montjean, Theil-Rabier, Yonne, Rougemont 1-2 and Vaite wind facilities in France in 2016 and 2017, which was partly offset by lower production at our British Columbia hydro facilities and at our Quebec wind farms.

For the six-month period ended June 30, 2017, the Corporation recorded revenues of $184.1 million, compared with $150.3 million for six-month period ended June 30, 2016. This 22% increase is attributable mainly to the facilities commissioned in 2016 and 2017 and the acquisitions of wind facilities in France in 2016 and 2017, which was partly offset by lower production at most of our British Columbia hydro facilities and at our Quebec wind farms.

Adjusted EBITDA

For the three- and six-month periods ended June 30, 2017, the Corporation recorded Adjusted EBITDA of $85.9 million and $136.9 million, respectively compared with $66.9 million and $114.5 million for the same periods last year. These increases of 29% for three-month period and 19% for the six-month period are due mainly to the production and revenues from new facilities, partly offset by higher operating expenses and general and administrative expenses. The three-month period Adjusted EBITDA was also positively impacted by lower prospective expenses. The Adjusted EBITDA Margin increased from 76.2% to 78.4% for the quarter due mainly to lower prospective expenses and an increase in revenues net of operating expenses. The Adjusted EBITDA Margin decreased from 76.2% to 74.4% for the six-month period due mainly to the payment related to water rights for 2011 and 2012 in British Columbia made in the first quarter of 2017. 

Net Earnings

For the three-month period ended June 30, 2017, the Corporation recorded net earnings of $14.1 million (basic and diluted net earnings of $0.12 per share), compared with net earnings of $15.7 million (basic and diluted net earnings of $0.12 per share) in 2016. The $1.6 million decrease in net earnings can be explained mainly by this year’s below-average production compared with last year’s above-average production, which explains the net earnings decrease as opposed to the increase in revenues. As a result, the $14.5 million increase in finance costs, the $9.8 million increase in depreciation and amortization related primarily to the greater number of operating facilities and the $2.6 million change in the unrealized net loss on derivative financial instruments were only partly offset by the $19.1 million increase in Adjusted EBITDA, the $4.7 million decrease in income tax expenses and the $1.3 million increase in share of earnings of joint ventures.

For the six-month period ended June 30, 2017, the Corporation recorded net earnings of $11.8 million (basic and diluted net earnings of $0.13 per share), compared with net earnings of $22.9 million (basic and diluted net earnings of $0.19 per share) in 2016. The $11.1 million decrease in net earnings can be explained mainly by this year’s below-average production compared with last year’s above-average production, which explains the decrease in net earnings as opposed to the increase in revenues. As a result, the $24.3 million increase in finance costs and the $20.0 million increase in depreciation and amortization were only partly offset by the $22.3 million increase in Adjusted EBITDA, the $6.8 million decrease in income tax expenses and the $2.5 million share of earnings of joint ventures.

Free Cash Flow and Payout Ratio

For the trailing twelve-month period ended June 30, 2017, the Corporation generated Free Cash Flow of $75.9 million, compared with $78.9 million for the same period last year. The decrease in Free Cash Flow is mainly due to greater scheduled debt principal payments and higher free cash flows attributed to non-controlling interests, partly offset by the increase in cash flows before changes in non-cash working capital items and the realized losses on derivative financial instruments. The realized loss on derivative financial instruments in the prior period was related to the settlement of the Mesgi’g Ugju’s’n bond forwards contracts at the closing of the projects’ financing. The Corporation also committed to investing more to pursue growth opportunities in new international markets, which also reduced cash flows from operating activities.

For the trailing twelve-month period ended June 30, 2017, the dividends on common shares declared by the Corporation amounted to 93% of Free Cash Flow, compared with 84% for the corresponding period last year. This negative impact is due mainly to lower free cash flow and 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, 94,000 shares following the exercise of stock options and 377,582 shares under the Dividend Reinvestment Plan (“DRIP”).

BUSINESS ACQUISITION

Acquisition of Rougemont 1-2 and Vaite

On May 24, 2017, Innergex completed the acquisition of three wind projects in France’s Bourgogne-Franche-Comté region with an aggregate capacity of 119.5 MW. Innergex owns a 69.55% interest in the wind farms while Desjardins Group Pension Plan owns the remaining 30.45%.

The equity’s purchase price is approximately €51.4 million (or $76.2 million), subject to certain adjustments. Innergex’s net share of the purchase price amounted to about €31.3 million (or $46.4 million) and was paid through funds available under its corporate revolving credit facility. The remainder of the purchase price was paid by Desjardins Group Pension Plan in the amount of €20.1 million ($29.8 million).

Non-recourse debts related to the projects, which were already in place, will amount to €174.3 million (or $258.4 million) at the end of construction and will remain at each project level.

The aggregate annual power generation is expected to reach 278,200 MWh once the three projects are in commercial operation, enough to power about 58,400 French households. All the electricity produced by these wind farms will be sold under fixed-price power purchase agreements (PPAs), with a portion of the price being adjusted according to inflation indexes, for an initial term of 15 years, with Electricité de France (“EDF”). Innergex is expecting revenues of approximately €23.5 million (or $34.8 million) and Adjusted EBITDA of approximately €18.2 million (or $26.9 million) for the first twelve months of operations.

The Rougemont-1 (36.1 MW) and Vaite (38.9 MW) wind farms are in commercial operation. The remaining wind project, Rougemont-2 (44.5 MW), should be fully commissioned in the fourth quarter of 2017.

DEVELOPMENT PROJECTS

Commissioning Activities

Boulder Creek

In the second quarter, the Corporation began commercial operation of the 25.3 MW Boulder Creek run-of-river hydroelectric facility in British Columbia. Construction began in October 2013. The Commercial Operation Date (COD) Certificate delivered to BC Hydro shows an effective commissioning date of May 16, 2017. The Boulder Creek facility’s average annual production is estimated at 92,500 MWh, enough to power more than 8,500 households.

Construction activities

Rougemont-2

The Rougemont-2 wind project was acquired during the second quarter of 2017. Construction was already underway at the time of the acquisition.

As at the date of this press release, all substantial civil works are complete, eight out of 16 wind turbines have already reached commercial operation, and delivery and installation has commenced on the remaining eight turbines. Full commissioning is expected in the fourth quarter of 2017.

SUBSEQUENT EVENTS

Final Agreement to Acquire Two Wind Projects in France

On July 5, 2017, the Corporation and Desjardins Group Pension Plan announced that a final agreement had been signed with BayWa r.e. to purchase two wind projects in France with a total aggregate installed capacity of 43 MW. The electricity to be produced will be sold under power purchase agreements at a fixed price, a portion of which is adjusted according to inflation indexes, for an initial term of 15 years, with Electricité de France. The equity’s purchase price is approximately €27.2 million (or $39.9 million), subject to certain adjustments. Innergex’s net share of the purchase price will amount to about €16.5 million (or $24.2 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 €72.0 million (or $105.7 million) 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%. The acquisition remains subject to customary closing conditions.

DIVIDEND DECLARATION

The following dividends will be paid by the Corporation on October 16, 2017:

Date of announcement

Record date

Payment date

Dividend per common share

Dividend per Series A

Preferred Share

Dividend per Series C Preferred Share

August 3, 2017

September 29, 2017

October 16, 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 and webcast tomorrow, Friday, August 4, 2017, at 10 AM (EDT). Its 2017 second quarter, mid-year 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 and to access the webcast at /2sdimEC or via the Corporation’s website at www.innergex.com. 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.

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, France and Idaho, USA. Its portfolio of assets currently consists of: (i) interests in 51 operating facilities with an aggregate net installed capacity of 1,063 MW (gross 1,758 MW), including 31 hydroelectric facilities, 19 wind farms and one solar farm; (ii) interests in one project under construction with a net installed capacity of 31 MW (gross 45 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- and six-month periods ended June 30, 2017, 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, 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 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

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 and royalties; these are predictable and relatively fixed, varying mainly with inflation (except for maintenance expenditures).

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 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 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; 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.

 

For further information: Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 1239, [email protected]x.com; Karine Vachon, Director – Communications, 450 928-2550, ext. 1222, [email protected]

www.innergex.com

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