- Innergex cumulative results for the first nine-months of 2016 exceeded long-term projections despite a more modest quarter
- Production was 106% of the long-term average ("LTA") for the nine-months of 2016 and 90% of the LTA for Q3
- Revenues increased 15% to $219.5 million for the first nine-months and increased 10% to $69.3 million in Q3 compared with 2015
- Adjusted EBITDA rose 14% to $165.7 million for the 2016 first nine-months and increased 5% to $51.2 million in Q3 compared with 2015
- In British Columbia, the 40.6 MW Big Silver Creek hydroelectric facility began commercial operation one month earlier than expected and construction costs were on budget
- Construction of the Upper Lillooet River and Boulder Creek hydroelectric facilities and the Mesgi'g Ugju's'n wind farm is progressing at a good pace
LONGUEUIL, QC, Nov. 9, 2016 /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, 2016.
"Innergex has successfully begun commercial operation at its 43rd facility," said Michel Letellier, President and Chief Executive Officer of the Corporation. "We are very proud to have commissioned the 40.6 MW Big Silver Creek hydroelectric facility located in British Columbia. We have done it one month earlier than expected and within our budget. We have now a gross installed capacity totaling 1,359 MW, which reinforces our position as one of the leader amongst independent power producers in British Columbia and in Canada.
"We have maintained a steady, rigorous pace of construction activities at the Mesgi'g Ugju's'n wind farm in Quebec and at the Upper Lillooet River and Boulder Creek hydroelectric projects in British Columbia and we continue to invest time and effort on our international development, about which we are very optimistic," he added.
OPERATING RESULTS
| Amounts shown are in thousands of Canadian dollars except as noted otherwise. |
Three months ended September 30 |
Nine months ended September 30 |
|||||
| 2016 |
2015 |
2016 |
2015 |
||||
| Power generated (MWh) |
831,840 |
777,975 |
2,672,678 |
2,340,575 |
|||
| Long-term average (MWh) |
924,439 |
849,747 |
2,526,725 |
2,363,711 |
|||
| Revenues |
69,255 |
62,680 |
219,520 |
190,578 |
|||
| Adjusted EBITDA1 |
51,176 |
48,550 |
165,720 |
144,920 |
|||
| Net earnings (loss) |
409 |
1,316 |
23,282 |
(13,988) |
|||
| Net earnings (loss), $ per share - basic and diluted |
0.02 |
0.04 |
0.20 |
(0.06) |
|||
| Trailing 12 months ended September 30 |
|||||||
| 2016 |
2015 |
||||||
| Free Cash Flow1 |
75,847 |
84,217 |
|||||
| Payout Ratio1 |
89 % |
74 % |
|||||
| 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 September 30, 2016, the Corporation's facilities produced 832 GWh of electricity or 90% of the LTA of 924 GWh. Overall, the hydroelectric facilities produced 87% of their LTA due to below- average water flows in all markets. Overall, the wind farms produced 102% of their LTA due to the above-average wind regime in Quebec, partly offset by the below-average wind regime in France. The Stardale solar farm produced 111% of its LTA due to an above-average solar regime. The 7% production increase over the same period last year is due mainly to production that was above last year's levels at most of the British Columbia ("BC") hydroelectric facilities during the quarter and, to a lesser extent, to the contribution of the recently commissioned or acquired facilities, namely the BC Tretheway Creek hydro facility commissioned in November 2015, the BC Walden North hydroelectric facility acquired in February 2016, the seven French entities acquired in April 2016 and the BC Big Silver Creek hydro facility commissioned in July 2016, which were partly offset by lower production from the hydro and wind regimes in Quebec and the hydro regime in Ontario.
During the nine-month period ended September 30, 2016, the Corporation's facilities produced 2,673 GWh of electricity or 106% of the LTA of 2,527 GWh. Overall, the hydroelectric facilities produced 107% of their LTA due mainly to above-average water flows in all markets but Ontario. Overall, the wind farms produced 100% of their LTA due to the above-average wind regime in Quebec and below-average wind regime in France. The Stardale solar farm produced 112% of its LTA due to an above-average solar regime. The 14% production increase over the same period last year is due mainly to higher water flows in BC, partly offset by lower water flows in Quebec and Ontario and the lower wind regime in Quebec.
Revenues
For the three-month period ended September 30, 2016, the Corporation recorded revenues of $69.3 million, compared with $62.7 million for the three-month period ended September 30, 2015. This 10% increase is attributable mainly to better results from most of the British Columbia hydroelectric facilities compared with the same period last year and to the contribution of the recently commissioned or acquired facilities (the BC Tretheway Creek hydro facility commissioned in November 2015, the BC Walden North hydroelectric facility acquired in February 2016, the seven French entities acquired in April 2016 and the BC Big Silver Creek facility commissioned this quarter), which were partly offset by lower revenues from the hydro and wind regime in Quebec and the hydrologic regime in Ontario. The higher rate of increase for revenues than for production is explained by the fact that some production is sold at a higher price.
For the nine-month period ended September 30, 2016, the Corporation recorded revenues of $219.5 million, compared with $190.6 million for the nine-month period ended September 30, 2015. This 15% increase is attributable mainly to better results in all hydroelectricity markets except Ontario and to the contribution of the recently commissioned or acquired facilities, which were partly offset by lower revenues from the wind regime in Quebec.
Adjusted EBITDA
Adjusted EBITDA, which is defined as revenues less operating expenses, general and administrative expenses and prospective project expenses, is a key performance indicator when evaluating the Corporation's financial results.
For the three- and nine-month periods ended September 30, 2016, the Corporation recorded Adjusted EBITDA of $51.2 million and $165.7 million, compared with $48.6 million and $144.9 million for the same period last year. This increase of 5% for the quarter and 14% for the nine-month period is due mainly to the increase in production and revenues, partly offset by higher operating expenses and prospective project expenses. The adjusted EBITDA Margin decreased from 77.5% to 73.9% for the quarter and from 76.0% to 75.5% for the nine-month period due mainly to the increase in operating expenses and to more resources being devoted to prospective project expenses.
Net Earnings (Loss)
Net earnings of $0.4 million (basic and diluted net earnings of $0.02 per share), compared with net earnings of $1.3 million (basic and diluted net earnings of $0.04 per share), were recorded by the Corporation in the quarter. The $0.9 million decrease in net earnings is explained mainly by the increased expenses arising mainly from the recently commissioned or acquired facilities and the increase in prospective expenses, which were partly offset by the $6.6 million increase in revenues, the lower net loss on derivatives and the lower income tax expense. As specifically regards the impact of the derivatives, the Corporation recognized a $27.0 million realized loss on derivatives in the same period last year, which was partly offset by a $24.3 million unrealized net gain on financial instruments, compared with no realized net gain and a $1.3 million unrealized net loss on derivatives in the present quarter.
For the nine-month period ended September 30, 2016, the Corporation recorded net earnings of $23.3 million (basic and diluted net earnings of $0.20 per share), compared with a net loss of $14.0 million (basic and fully diluted net loss of $0.06 per share) in 2015. The $37.3 million increase in net earnings can be explained mainly by the $28.9 million increase in revenues and the lower net loss on derivatives, which were partly offset by the increase in expenses due mainly to the recently commissioned or acquired facilities, the $2.5 million increase in prospective expenses and the $11.1 million increase in the income tax expense. As specifically regards the impact of the derivatives, the Corporation recognized a $119.6 million realized loss on derivatives in the same period last year, which was partly offset by a $79.4 million unrealized net gain on derivative financial instruments, compared with a $2.1 million unrealized net gain on derivatives in the present nine-month period.
Free Cash Flow and Payout Ratio
For the trailing 12 months ended September 30, 2016, the Corporation generated Free Cash Flow of $75.8 million, compared with $84.2 million for the same period last year. This decrease in Free Cash Flow is due mainly to higher cash flows from operations in 2016 before changes in non-cash operating working capital items and realized losses on derivative financial instruments, which were more than offset by greater scheduled debt principal payments.
For the trailing 12 months ended September 30, 2016, the dividends on common shares declared by the Corporation amounted to 89% of Free Cash Flow, compared with 74% for the corresponding prior 12-month period. This negative change is due mainly to the decrease in Free Cash Flow explained above and to the higher number of common shares outstanding due to the issuance of shares to three Desjardins Group-affiliated entities under a private placement of common shares to finance part of the seven French entities acquired.
DEVELOPMENT PROJECTS & COMMISSIONING ACTIVITIES
Commissioning activities
Big Silver Creek
On July 29th, 2016, the Big Silver Creek hydroelectric facility began commercial operation In British Columbia.
In the third quarter, the Corporation began commercial operation of the 40.6 MW Big Silver Creek run-of-river hydroelectric facility located in British Columbia. The Big Silver Creek facility is located on crown land approximately 40 km north of Harrison Hot Springs, British Columbia. Construction began in June 2014 and was completed in July 2016, earlier than expected and on budget. The Commercial Operation Date ("COD") certificate has been approved by BC Hydro with an effective commissioning date of July 29, 2016. Big Silver Creek's average annual production is estimated to reach 139,800 MWh, enough to power more than 12,700 households.
In its first full year of operation, it is expected to generate revenues and Adjusted EBITDA of circa $17.2 million and $14.5 million respectively. All the electricity it produces is covered by a 40-year fixed-price power purchase agreement with BC Hydro, which was obtained under that province's 2008 Clean Power Call Request for Proposals and which provides for an annual adjustment to the selling price based on a portion of the Consumer Price Index. On June 22, 2015, the Corporation announced the closing of a $197.2 million non-recourse construction and term project financing for this project.
Construction activities
Upper Lillooet River and Boulder Creek
The construction of the Upper Lillooet River and Boulder Creek hydroelectric facilities began in October 2013. On March 17, 2015, the Corporation announced the closing of a $491.6 million non-recourse construction and term project financing for both these projects, which has received the Clean Energy BC's Finance Award for 2015 and the 2016 Hydro Power Deal of the Year from the World Finance Magazine.
As at the date of this press release, the Upper Lillooet tunnel invert, final lining and rock trap are now complete. The hydro-mechanical progress on the intake was delayed due to landslide hazard shutdowns and is now expected to be completed in November. The powerhouse turbine and generation equipment installation is nearly complete with only the auxiliary equipment and controls remaining. The transformer and switchyard are nearly complete. The Upper Lillooet Leave to Commence Diversion ("LTCD") application is under review by the agencies concerned and approval is expected by mid-November.
The Boulder Creek tunnel excavation was completed at the end of August and invert cleaning and final support works are well under way. The steel liner work is scheduled to commence in mid-November. The intake civil and hydro-mechanical work is complete with only the electrical work and controls remaining. The LTCD package has been submitted to the agencies concerned for approval.
The joint transmission line is nearly completed and will be commissioned by mid-November.
The insurance claims process for the fire continues with interim progress payments being made. The insurer has hired a consultant to review the project schedules and progress. In any case, the Corporation expects to be indemnified and to suffer no significant adverse financial consequences from the forest fire.
Mesgi'g Ugju's'n
Construction of this wind farm began in May 2015. On September 28, 2015, the Corporation and its partner, the three Mi'gmaq communities of Quebec, announced the closing of a $311.7 million non-recourse construction and term project financing for this project.
As at the date of this press release, all access roads, crane pads, wind turbines generator ("WTG") foundations and electrical collector system have been completed. All wind turbines have been delivered and all major turbine components erected. Turbine electrical and mechanical completion work and commissioning of the wind turbines is ongoing. The twin transformer electrical interconnection station has been completed and energized. The Corporation expects the project to reach commercial operation, on budget, by the end of 2016.
As reported in the previous quarter's press release, the Corporation has revised the annual forecast for the Gross estimated LTA energy yield upward from 515 GWh to 562.5 GWh, which corresponds approximately to a 9% increase. The revised Gross estimated LTA of the Mesgi'g Ugju's'n wind farm will result in a $3.2 million increase in Projected Free Cash Flow allocated to Innergex. Innergex is entitled to approximately 70% of the total free cash flows that will be generated by the project for the year 2017.
DIVIDEND DECLARATION
The following dividends will be paid by the Corporation on January 16, 2017:
| Date of announcement |
Record date |
Payment date |
Dividend per common share |
Dividend per Preferred Share |
Dividend per Series C Preferred Share |
| November 9, 2016 |
December 30, 2016 |
January 16, 2017 |
$0.1600 |
$0.2255 |
$0.359375 |
On February 24, 2016, the Board of Directors increased the annual dividend that the Corporation intends to distribute from $0.62 to $0.64 per common share, payable quarterly.
CONFERENCE CALL REMINDER
The Corporation will hold a conference call tomorrow, Thursday, November 10, 2016, at 9:00 a.m. ET. Its 2016 third-quarter results, nine-month 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.
About Innergex Renewable Energy Inc.
Innergex Renewable Energy Inc. (TSX: INE) is a leading Canadian independent renewable power producer. Active since 1990, the Corporation develops, owns and operates run-of-river hydroelectric facilities, wind farms and solar photovoltaic farms and carries out its operations in Quebec, Ontario and British Columbia, Canada, in Idaho, USA, and in France. Its portfolio of assets currently consists of: (i) interests in 43 operating facilities with an aggregate net installed capacity of 817 MW (gross 1,359 MW), including 29 hydroelectric facilities, 13 wind farms and one solar farm; (ii) interests in three projects under construction with an aggregate net installed capacity of 146 MW (gross 257 MW), for which power purchase agreements have been secured; and (iii) prospective projects with an aggregate net capacity totaling 3,280 MW (gross 3,530 MW). Innergex Renewable Energy Inc. is rated BBB- by S&P.
The Corporation's strategy for building shareholder value is to develop or acquire high-quality facilities that generate sustainable cash flows and provide an attractive risk-adjusted return on invested capital and to distribute a stable dividend.
Non-IFRS measures disclaimer
The consolidated financial statements for the three- and nine-month periods ended September 30, 2016, have been prepared in accordance with International Financial Reporting Standards ("IFRS"). However, some measures referred to in this news release are not recognized measures under IFRS and therefore may not be comparable to those presented by other issuers. Innergex believes that these indicators are important, as they provide management and the reader with additional information about the Corporation's production and cash generation capabilities, its ability to sustain current dividends and dividend increases and its ability to fund its growth. These indicators also facilitate the comparison of results over different periods. Adjusted EBITDA, Free Cash Flow and Payout Ratio are not measures recognized by IFRS and have no standardized meaning prescribed by IFRS.
References in this document to "Adjusted EBITDA" are to revenues less operating expenses, general and administrative expenses and prospective project expenses.
References to "Free Cash Flow" are to cash flows from operating activities before changes in non-cash operating working capital items, less maintenance capital expenditures net of proceeds from disposals, scheduled debt principal payments, preferred share dividends declared and the portion of Free Cash Flow attributed to non-controlling interests, plus cash receipts by the Harrison Hydro Limited Partnership for the wheeling services to be provided to other facilities owned by the Corporation over the course of their PPA, plus or minus other elements that are not representative of the Corporation's long-term cash generating capacity, such as transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and realized losses or gains on derivative financial instruments used to hedge the interest rate on project-level debt or the exchange rate on equipment purchases.
References to "Payout Ratio" are to dividends declared on common shares divided by Free Cash Flow.
Readers are cautioned that Adjusted EBITDA should not be construed as an alternative to net earnings and Free Cash Flow should not be construed as an alternative to cash flows from operating activities, as determined in accordance with IFRS.
Forward-looking information disclaimer
In order to inform readers of the Corporation's future prospects, this press release contains forward-looking information within the meaning of applicable securities laws ("Forward-Looking Information"). Forward-Looking Information can generally be identified by the use of words such as "projected", "potential", "expect", "will", "should", "estimate", "forecasts", "intends", or other comparable terminology that states that certain events will or will not occur. It represents the estimates and expectations of the Corporation relating to future results and developments as of the date of this press release. It includes future-oriented financial information, to inform readers of the potential financial impact of development projects. Such information may not be appropriate for other purposes.
Forward-Looking Information in this press release is based on certain key expectations and assumptions made by the Corporation. The following table outlines Forward-Looking Information contained in this press release, the principal assumptions used to derive this information and the principal risks and uncertainties that could cause actual results to differ materially from this information.
| Principal Assumptions |
Principal Risks and Uncertainties |
| 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 Free Cash Flow The Corporation estimates Free Cash Flow as projected cash flow from operations 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 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. It also adjusts for other elements, which represent cash inflows or outflows that are not representative of the Corporation's long-term cash generating capacity, such as adding back transaction costs related to realized acquisitions (which are financed at the time of the acquisition) and adding back realized losses or subtracting realized gains on derivative financial instruments used to fix the interest rate on project-level debt or the exchange rate on equipment purchases. |
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 Unexpected maintenance capital expenditures |
| Expected closing of the acquisition of the eighth French wind farm under construction The Corporation reasonably expects to complete the acquisition of the eighth French Wind Farm under construction and it has no indication as of today that the closing conditions will not be satisfied by all parties. |
Regulatory and political risks Availability of the Capital Performance of the counterparties |
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; uncertainty surrounding the development of new facilities; variability of installation performance and related penalties; foreign market growth and development risks; sufficiency of insurance coverage limits and exclusions; and the ability to secure new power purchase agreements or to renew existing ones.
Although the Corporation believes that the expectations and assumptions on which Forward-Looking Information is based are reasonable, readers of this press release are cautioned not to rely unduly on this Forward-Looking Information since no assurance can be given that they will prove to be correct. The Corporation does not undertake any obligation to update or revise any Forward-Looking Information, whether as a result of events or circumstances occurring after the date of this press release, unless so required by legislation.
SOURCE Innergex Renewable Energy Inc.
Jean Perron, CPA, CA, Chief Financial Officer, 450 928-2550, ext. 239, [email protected]; Martine Benmouyal, Senior Advisor - Communications, 450 928-2550, ext. 335, [email protected], www.innergex.com
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