As filed with the Securities and Exchange Commission on April 28, 2015May 14, 2018
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 20-F
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20142017
Commission file number: 001-14668
COMPANHIA PARANAENSE DE ENERGIA – COPEL
(Exact Name of Registrant as Specified in its Charter)
Energy Company of Paraná (Translation of Registrant’s Name into English) | The Federative Republic of Brazil (Jurisdiction of Incorporation or Organization) |
Rua Coronel Dulcídio, 800
80420-170 Curitiba, Paraná, Brazil
(Address of Principal Executive Offices)
Luiz Fernando Leone ViannaJonel Nazareno Iurk
+55 41 3222 2027 – ri@copel.com
Rua Coronel Dulcídio, 800, 3rd floor – 80420 – 17080420.170 Curitiba, Paraná, Brazil
(Name, telephone, e-mail and/or facsimile number and address of company contact person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered |
Preferred Class B Shares, without par value* | New York Stock Exchange |
American Depositary Shares (as evidenced by American Depositary Receipts), each representing one Preferred Class B Share | New York Stock Exchange |
* Not for trading, but only in connection with the listing of American Depositary Shares on the New York Stock Exchange.
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the Issuer’s classes of capital or common stock as of December 31, 2014:2017:
145,031,080 Common Shares, without par value
380,291328,627 Class A Preferred Shares, without par value
128,244,004128,295,668 Class B Preferred Shares, without par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yesx No¨
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes¨ Nox
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yesx No¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
N/A
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.filer, or an emerging growth company. See definitionthe definitions of “large accelerated filer,” “accelerated filer,” and large accelerated filer””emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934. (Check one):
Large accelerated filerx Accelerated filer¨
Non-accelerated filer¨ Emerging growth company¨
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP ¨ IFRS x Other¨
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
N/A
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).
Yes¨ Nox
Table of Contents
Presentation of Financial and Other |
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Business. | 29 | ||
Concessions. | 55 | ||
Competition. | 62 | ||
Environment | 64 | ||
Plant, Property and Equipment | 65 | ||
The Expropriation Process. | 66 | ||
The Brazilian Electric Power Industry. |
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Critical Accounting Policies. | 91 | ||
Analysis of Electricity Sales and Cost of Electricity Purchased. | |||
Results of Operations for the Years Ended December 31, 2017, 2016 and 2015. | 97 | ||
Liquidity and Capital Resources. | 107 | ||
Contractual Obligations. | 112 | ||
Item 6. | Directors, Senior Management and Employees. |
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Board of Directors. | 113 | ||
Board of Executive Officers. | 117 | ||
Fiscal Council | 119 | ||
Audit Committee. | 120 | ||
Compensation of Directors, Officers, Fiscal Council Members and Audit Committee Members. | 121 | ||
Employees. | 122 | ||
Share Ownership. | 123 | ||
Item 7. |
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Major Shareholders. | 124 | ||
Related Party Transactions. |
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Financial Information. |
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Statement Experts. | 148 | ||
Documents on Display. |
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Material Modifications to the Rights of Security Holders and Use of Proceeds. |
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PRESENTATION OF FINANCIAL AND OTHER INFORMATION
In this annual report, we refer to Companhia Paranaense de Energia ‒ Copel, and, unless the context otherwise requires, its consolidated subsidiaries as “Copel”, the “Company”, “we” or “us”.
References to (i) the “real”, “reais” or “R$” are to Brazilianreais (plural) and the Brazilianreal (singular) and (ii) “U.S. dollars”, “dollars” or “US$” are to United States dollars. We maintain our books and records in reais.reais. Certain figures included in this annual report have been subject to rounding adjustments.
Our consolidated financial statements as of December 31, 2014, 20132017 and 2012, of2016, and for each of the three years ended December 31, 2014, have been audited, as stated in the report appearing herein,2017, 2016 and 2015, are included in this annual report. We prepared our consolidated financial statements included in this annual report in accordance with International Financial Reporting Standards, or IFRS, as issued by the International Accounting Standards Board, or IASB.
The selected financial data as of December 31, 2016 and 2015 reflects the restatement of our Income Statement for the year ended December 31, 2015, and the restatement of our financial statements as of and for the year ended December 31, 2016. For more information, see Note 4.1 to our audited financial statements for December 31, 2017.
References in this annual report to the “Common Shares”, “Class A Shares” (or “Class A”) and “Class B Shares” (or “Class B”) are to our common shares, class A preferred shares and class B preferred shares, respectively. References to “American Depositary Shares” or “ADSs” are to American Depositary Shares, each representing one Class B Share. The ADSs are evidenced by American Depositary Receipts (“ADRs”).
Certain terms are defined the first time they are used in this annual report. As used herein, all references to “GW” and “GWh” are to gigawatts and gigawatt hours, respectively, references to “kW” and “kWh” are to kilowatts and kilowatt hours, respectively, references to “MW” and “MWh” are to megawatts and megawatt hours, respectively, and references to “kV” are to kilovolts. These and other technical terms are defined in the “Technical Glossary” that begins on page 111.160.
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This annual report contains forward-looking statements. We may also make written or oral forward-looking statements in our annual report to shareholders, in our offering circulars and prospectuses, in press releases and other written materials and in oral statements made by our officers, directors or employees. These statements are not historical facts and are based on management’s current view and estimates of future economic circumstances, industry conditions, company performance and financial results. The words “anticipates”, “believes”, “estimates”, “expects”, “plans” and similar expressions, as they relate to the company, are intended to identify forward-looking statements. Statements regarding the declaration or payment of dividends, the implementation of principal operating and financing strategies and capital expenditure plans, the direction of future operations and the factors or trends affecting the financial condition, liquidity or results of operations are examples of forward-looking statements. Forward-looking statements speak only as of the date they are made, and we undertake no obligation to update publicly any of them in light of new information or future events.
Forward-looking statements involve only the current view of management and are subject to a number of inherent risks and uncertainties. There is no guarantee that the expected events, trends or results will actually occur. We caution you that a number of important factors could cause actual results to differ materially from those contained in any forward-looking statement. Such factors include, but are not limited to:
· Brazilian political and economic conditions;
· economic conditions in the State of Paraná;
· developments in other emerging market countries;
· our ability to obtain financing;
· lawsuits;
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· technical and operational conditions related to the provision of electricity services;
· changes in, or failure to comply with, governmental regulations;
· competition;
· electricity shortages; and
· other factors discussed below under “Item 3.Key Information―Risk Factors”.
All forward-looking statements are expressly qualified in their entirety by this cautionary statement, and you should not place undue reliance on any forward-looking statement contained in this annual report.
Item 1. Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2. Offer Statistics and Expected Timetable
Not applicable.
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This section contains selected consolidated financial data presented inreais and derived from our consolidated financial statements that were prepared in accordance with IFRS as of and for each of the five years ended December 31, 2017, 2016, 2015, 2014 and 2013.
The information set forth in this sectionfollowing selected financial data should be read in conjunction with our consolidated annualaudited financial statements (including the notes thereto) and, “Presentation of Financial and Other Data” andInformation”, “Item 5. Operating and Financial Review and Prospects” and “Item 8 – Financial Information”.
WeThe selected financial data as of December 31, 2017, 2016, and 2015 and for the years ended December 31, 2017, 2016 and 2015 have been derived from our audited financial statements, prepared in accordance with IFRS, and included informationin this annual report. The selected financial data as of December 31, 2014 and 2013 and for the years ended December 31, 2014 and 2013, have been derived from our audited financial statements, prepared in accordance with respect toIFRS, which is not included in this annual report.
The selected financial data as of December 31, 2016 and 2015 reflects the dividends and interest attributable to shareholders’ equity paid to holdersrestatement of our common sharesIncome Statement for the year ended December 31, 2015, and preferred shares since January 1, 2010 under “Item 8. Financial Information—Dividend Payments—Paymentthe restatement of Dividends”.our financial statements as of and for the year ended December 31, 2016. For more information, see Note 4.1 to our audited financial statements for December 31, 2017.
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| As of and for the year ended December 31, | ||||
| 2014 | 2013 | 2012 | 2011 | 2010(1) |
| (R$ million) | ||||
Statement of income data: |
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Operating revenues | 13,919 | 9,180 | 8,493 | 7,776 | 6,901 |
Cost of sales and services provided | (11,165) | (7,038) | (6,540) | (5,457) | (4,976) |
Gross profit | 2,754 | 2,142 | 1,953 | 2,319 | 1,925 |
Operational expenses/income | (1,044) | (916) | (953) | (961) | (893) |
Profit before financial results and taxes | 1,710 | 1,226 | 1,000 | 1,358 | 1,032 |
Financial results | 148 | 280 | (27) | 226 | 348 |
Profit before income tax and social contribution | 1,858 | 1,506 | 973 | 1,584 | 1,380 |
Income tax and social contribution on profit | (522) | (405) | (246) | (407) | (370) |
Net income for the year | 1,336 | 1,101 | 727 | 1,177 | 1,010 |
Statement of financial position data: |
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Current assets | 5,218 | 4,680 | 4,682 | 3,700 | 4,158 |
Recoverable rate deficit (CRC)(2) | 1,344 | 1,381 | 1,384 | 1,346 | 1,341 |
Non-current assets | 8,261 | 7,224 | 6,297 | 5,656 | 4,805 |
Property, plant and equipment, net | 8,304 | 7,984 | 7,872 | 7,209 | 6,664 |
Total assets | 25,618 | 23,111 | 21,209 | 18,837 | 17,859 |
Loans and financing and debentures (current) | 1,299 | 1,015 | 274 | 116 | 704 |
Current liabilities | 4,055 | 3,348 | 2,833 | 2,058 | 2,537 |
Loans and financing and debentures (non-current) | 4,755 | 3,517 | 2,988 | 2,058 | 1,281 |
Non-current liabilities | 7,880 | 6,835 | 6,014 | 4,701 | 4,027 |
Equity | 13,683 | 12,929 | 12,362 | 12,078 | 11,296 |
Attributable to controlling shareholders | 13,331 | 12,651 | 12,097 | 11,835 | 11,030 |
Attributable to non-controlling interest | 352 | 277 | 265 | 243 | 266 |
Share capital | 6,910 | 6,910 | 6,910 | 6,910 | 6,910 |
| As of and for the year ended December 31, |
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| 2017 | 2016 restated | 2015 restated | 2014 | 2013 | ||||
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Statement of income data(1): |
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Operating revenues. | 14,025 | 13,102 | 14,946 | 13,996 | 9,288 | ||||
Cost of sales and services provided | (10,666) | (10,234) | (11,799) | (11,289) | (7,159) | ||||
Gross profit | 3,359 | 2,868 | 3,147 | 2,707 | 2,129 | ||||
Operational expenses/income | (1,217) | (879) | (1,025) | (903) | (784) | ||||
Profit before financial results and taxes | 2,141 | 1,989 | 2,121 | 1,804 | 1,345 | ||||
Financial results | (748) | (595) | (428) | 54 | 161 | ||||
Profit before income tax and social contribution | 1,393 | 1,394 | 1,694 | 1,858 | 1,506 | ||||
Income tax and social contribution on profit. | (275) | (520) | (532) | (522) | (405) | ||||
Net income for the year. | 1,118 | 874 | 1,162 | 1,336 | 1,101 | ||||
Statement of financial position data(1): |
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Current assets. | 5,702 | 4,237 | 6,822 | 5,218 | 4,680 | ||||
Recoverable rate deficit (CRC)(2) | 1,516 | 1,523 | 1,383 | 1,344 | 1,381 | ||||
Non-current assets | 8,608 | 8,313 | 4,952 | 8,261 | 7,224 | ||||
Property, plant and equipment, net | 9,829 | 8,934 | 8,693 | 8,304 | 7,984 | ||||
Total assets. | 33,162 | 30,289 | 28,844 | 25,618 | 23,111 | ||||
Loans and financing and debentures (current) | 2,417 | 2,602 | 1,233 | 1,299 | 1,015 | ||||
Current liabilities. | 6,110 | 5,656 | 4,789 | 4,055 | 3,348 | ||||
Loans and financing and debentures (non-current) | 7,414 | 6,235 | 6,528 | 4,755 | 3,517 | ||||
Non-current liabilities. | 11,542 | 9,655 | 9,574 | 7,880 | 6,835 | ||||
Equity. | 15,510 | 14,978 | 14,480 | 13,683 | 12,929 | ||||
Attributable to controlling shareholders. | 15,208 | 14,718 | 14,162 | 13,331 | 12,651 | ||||
Attributable to non-controlling interest. | 302 | 260 | 318 | 352 | 277 | ||||
Share capital | 7,910 | 7,910 | 6,910 | 6,910 | 6,910 |
(1) Not comparable with the current GAAP. Data for 2010 has not been restated in application of IAS 19 – Employee Benefits (as revised in 2011) and IFRS 11 – Joint Arrangements. In particular, data for 2010The information contained herein reflects the resultsrestatement of our financial statements for the joint-venture Dominó Holdings S.A through proportional consolidation in 2010, as opposed toyears 2016 and 2015. For more information about the equity methodrestatement of accounting applicable in 2014, 2013, 2012our income statement, see “RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 and 2011.2015 – Results of Operations for 2017 Compared with 2016” and “– Results of Operations for 2016 Compared with 2015”.
(2)This item includes both current and non-current CRC Account receivables. Amounts due from the State of Paraná that were included in current assets totaled R$167.1 million in 2017, R$111.7 million in 2015, R$94.6 million in 2014 and R$85.5 million in 2013, R$75.9 million in 2012, R$65.9 million in 2011 and R$58.8 million in 2010.2013. Amounts due from the State of Paraná that were included in long-term assets totaled R$1,349.3 million in 2017, R$1,522.7 million in 2016, R$1,271.6 million in 2015, R$1,249.5 million in 2014 and R$1,295.1 million in 2013, R$1,308.4 million2013. In 2016 the entire amount due by the State of Paraná was included in 2012, R$1,280.6 million in 2011 and R$1,282.4 million in 2010.long-term assets due to the negotiation of the Amendment to the CRC Agreement. See Note 8 to our audited consolidated financial statements. This item includes both current and non-current CRC Account receivables.
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| 2017 | 2016 | 2015 | 2014 | 2013 |
| (R$, except for number of shares) | ||||
Basic and diluted earnings per share(1): |
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Common Shares | 3.61 | 3.13 | 3.87 | 4.21 | 3.74 |
Class A Preferred Shares | 3.97 | 3.44 | 4.26 | 4.63 | 4.49 |
Class B Preferred Shares | 3.97 | 3.44 | 4.26 | 4.63 | 4.12 |
(Number of shares outstanding at year end in thousands:) |
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Common Shares | 145,031 | 145,031 | 145,031 | 145,031 | 145,031 |
Class A Preferred Shares | 329 | 349 | 380 | 380 | 381 |
Class B Preferred Shares | 128,295 | 128,275 | 128,244 | 128,244 | 128,243 |
Total | 273,655 | 273,655 | 273,655 | 273,655 | 273,655 |
(Dividends per share at year end:) |
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Common Shares | 1.01 | 0.99 | 1.14 | 2.17 | 1.96 |
Class A Preferred Shares | 2.89 | 2.89 | 2.53 | 2.53 | 2.53 |
Class B Preferred Shares | 1.11 | 1.08 | 1.25 | 2.39 | 2.15 |
(1)The information contained herein reflects the restatement of our financial statements for the years 2016 and 2015. For more information see “RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 and 2015 – Results of Operations for 2017 Compared with 2016” and “– Results of Operations for 2016 Compared with 2015”.
| 2017 | 2016 | 2015 | 2014 | 2013 |
| (US$¹, except for number of shares) | ||||
Basic and diluted earnings per share(2): |
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Common Shares | 1.09 | 0.97 | 0.99 | 1.58 | 1.60 |
Class A Preferred Shares | 1.20 | 1.06 | 1.09 | 1.74 | 1.92 |
Class B Preferred Shares | 1.20 | 1.06 | 1.09 | 1.74 | 1.76 |
Number of shares outstanding at year end (in thousands): |
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Common Shares | 145,031 | 145,031 | 145,031 | 145,031 | 145,031 |
Class A Preferred Shares | 329 | 349 | 380 | 380 | 381 |
Class B Preferred Shares | 128,295 | 128,275 | 128,244 | 128,244 | 128,243 |
Total | 273,655 | 273,655 | 273,655 | 273,655 | 273,655 |
Dividends per share at year end: |
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Common Shares | 0.31 | 0.30 | 0.29 | 0.82 | 0.83 |
Class A Preferred Shares | 0.87 | 0.89 | 0.65 | 0.95 | 1.08 |
Class B Preferred Shares | 0.34 | 0.33 | 0.32 | 0.90 | 0.92 |
(1)This information is presented in U.S. dollars at the exchange rate in effect as of the end of each year.
| 2014 | 2013 | 2012 | 2011 | 2010 |
| (R$) | ||||
Basic and diluted earnings per share: |
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Common Shares | 4.21 | 3.74 | 2.44 | 4.04 | 3.45 |
Class A Preferred Shares | 4.63 | 4.49 | 4.17 | 5.33 | 5.20 |
Class B Preferred Shares | 4.63 | 4.12 | 2.69 | 4.44 | 3.79 |
Number of shares outstanding at year end (in thousands): |
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Common Shares | 145,031 | 145,031 | 145,031 | 145,031 | 145,031 |
Class A Preferred Shares | 380 | 381 | 381 | 384 | 390 |
Class B Preferred Shares | 128,244 | 128,243 | 128,243 | 128,240 | 128,234 |
Total | 273,655 | 273,655 | 273,655 | 273,655 | 273,655 |
Dividends per share at year end: |
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Common Shares | 2.17 | 1.96 | 0.94 | 1.47 | 0.98 |
Class A Preferred Shares | 2.53 | 2.53 | 2.53 | 2.53 | 2.53 |
Class B Preferred Shares | 2.39 | 2.15 | 1.03 | 1.62 | 1.08 |
(2) The information contained herein reflects the restatement of our financial statements for the years 2016 and 2015. For more information see “RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2017, 2016 and 2015 – Results of Operations for 2017 Compared with 2016” and “– Results of Operations for 2016 Compared with 2015”.
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The following table provides information on the selling exchange rate, expressed inreais per U.S. dollar (R$/US$), for the periods indicated.
| Exchange rate of Brazilian currency per US$1.00 | Exchange rate of Brazilian currency per US$1.00 | ||||||
Year | Low | High | Average(1) | Year-end | Low | High | Average(1) | Year-end |
2010 | 1.6554 | 1.8811 | 1.7589 | 1.6662 | ||||
2011 | 1.5345 | 1.9016 | 1.6709 | 1.8758 | ||||
2012 | 1.7024 | 2.1121 | 1.9588 | 2.0435 | ||||
2013 | 1.9528 | 2.4457 | 2.1741 | 2.3426 | 1.9528 | 2.4457 | 2.1741 | 2.3426 |
2014 | 2.1974 | 2.7403 | 2.3599 | 2.6562 | 2.1974 | 2.7403 | 2.3599 | 2.6562 |
2015 | 2.5754 | 4.1949 | 3.3876 | 3.9048 | ||||
2016 | 3.1193 | 4.1558 | 3.4500 | 3.2591 | ||||
2017 | 3.0510 | 3.3807 | 3.2031 | 3.3080 |
Source:Central Bank.
(1) Represents the average of the exchange rates on the last day of each month during the relevant period.
Month | Low | High |
December 2014 | 2.5607 | 2.7403 |
January 2015 | 2.5754 | 2.7107 |
February 2015 | 2.6894 | 2.8811 |
March 2015 | 2.8655 | 3.2683 |
April 2015 (until April 14, 2014) | 3.0466 | 3.1556 |
Month | Low | High |
October 2017 | 3.1315 | 3.2801 |
November 2017 | 3.2136 | 3.2920 |
December 2017 | 3.2322 | 3.3332 |
January 2018 | 3.1391 | 3.2697 |
February 2018 | 3.1730 | 3.2821 |
March 2018 | 3.2246 | 3.3380 |
April, 2018 | 3.3104 | 3.5040 |
May, 2018 (until May 11, 2018) | 3.5308 | 3.5943 |
Source:Central Bank.
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Risks Relating to Our Company and our Operations
We are controlled by the State of Paraná, the policies and priorities of which directly affect our operations and may conflict with the interests of our investors.
We are controlled by the State of Paraná, which holds 58.6% of our outstanding common voting shares as of the date of this annual report, and whose interests may differ from other shareholders. As a major shareholder, the State of Paraná has the power to control all of our operations, including the power to elect a majority of the members of our Board of Directors and determine the outcome of any action requiring common shareholder approval, including transactions with related parties and corporate reorganizations.
Our operations have had and will continue to have an important impact on the commercial and industrial development of the State of Paraná. In the past, the State of Paraná has used, and may in the future use, its status as our controlling shareholder to decide whether we should engage in certain activities and make certain investments aimed, principally, to promote its public policies or social objectives and not necessarily to meet the objective of improving our business and/or operational results.
In October 2018, an election will be held to appoint the governor and members of the legislature of the State of Paraná. It is not possible to predict the outcome of this election and whether it will result in changes to the interests and decisions of the majority shareholder with respect to the Company's goals.
The construction and expansion of our transmission and power generation projects involve significant risks that may have an adverse effect on us.
In connection with the development of transmission and generation projects, we generally must obtain feasibility studies, governmental concessions or authorizations, permits and approvals, condemnation agreements, equipment supply agreements, engineering, procurement and construction contracts, sufficient equity and debt financing and site agreements, each of which involves the consent of third parties over which we have no control. In addition, project development is subject to environmental, engineering and construction risks that can lead to cost overruns, delays and other impediments to timely complete within a project’s budget. We cannot assure you that all required permits and approvals for our projects will be obtained, that we will be able to secure private sector partners for any of our projects, that we or any of our partners will be able to obtain adequate financing for our projects or that financing will be available on a non-recourse basis to us.
If we are unable to complete a project, whether at the initial development phase or after construction has commenced, or if the completion of a project is delayed, this may decrease our expected financial return from the project, which may lead to impairment. If we experience these or other problems relating to the expansion of our electricity transmission and power generation capacity, we may be exposed to increased costs, or we may fail to achieve the revenues we planned in connection with such expansion projects, which may have an adverse effect on our financial condition and results of operations.
We are involved in several lawsuits that could have a material adverse effect on our business if their outcome is unfavorable to us.
We are the defendant in several legal proceedings, mainly relating to civil, administrative, labor and tax claims. The outcome of these proceedings is uncertain and, if determined against us, may result in obligations that could materially affect our results of operations. On December 31, 2017, our provisions for probable (more likely than not) and reasonably estimated losses were R$1,503.9 million. For additional information, see “Item 8. Financial Information—Legal Proceedings”.
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We are subject to limitations regarding the amount and use of public sector financing, which couldprevent us from obtaining financing and implanting our investment plan.
Our current budget anticipates capital expenditures for expansion, modernization, research, infrastructure and environmental projects of approximately R$2,928.6 million in 2018. As a state-controlled company, we are subject to Brazilian Central Bank Resolution no. 4,589/2017(Resolução nº 4,589/2017 do Banco Central do Brasil), which defines the limit of exposure and the annual global limit of credit to public sector entities to be observed by financial institutions and other institutions authorized to operate by the Brazilian Central Bank. The annual global limit that can be contracted in credit operations, with and without guarantee of the Union, by the bodies and entities of the public sector with the financial institutions and other institutions authorized to operate by the Brazilian Central Bank is defined by the National Monetary Council by means of inclusion of an annex to Brazilian Central Bank Resolution no. 4,589/2017, establishing, until the end of each fiscal year, the limit for the following year. The maximum amounts defined for the 2018 financial year are up to R$17.0 billion forUnion guaranteed operations and up to R$7.0 billion for operations without Union guarantee. As a result of these limits, we may have difficulty in obtaining financing from Brazilian and international financial institutions, which could create difficulties in the implementation of our investment plan. Additionally, some of our concession contracts have provisions that limit our permitted level of indebtedness, which could also affect our ability to obtain necessary financing. As a result of these regulations and provisions, our capacity to incur debt from certain sources is limited, which could negatively affect the implementation of our investment plan.
Cyber attacks or breach of security of our data center may result in disruption of our operations or leakage of confidential information of the Company, our customers, third parties or interested parties and may cause financial losses, legal exposures and damage to our reputation.
We are the managers and owners of various confidential information related to our business and operations. In our ordinary course of business, we collect and store personal data of our customers in our data centers.
Despite our security measures, our information technology and infrastructure may be vulnerable to (i) attacks by hackers, which can access our safety net and steal our information, paralyze our operations or even cause power outages, or (ii) breaches due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss of information could affect our operations and could result in legal claims or proceedings under Brazilian laws that protect the privacy of personal information (among others) and damage our reputation.
If we are unable to conclude our investment program on schedule, the operation and development of our business could be adversely affected.
In 2018, we plan to invest approximately R$743.6 million in our generation and transmission activities (including Baixo Iguaçu HPP, Colíder HPP and SPCs of transmission lines), R$1,051.4 million in wind farms, R$790.0 million in our distribution activities, R$340.2 million in our telecommunications activities and R$3.4 million in others investments. Our ability to complete this investment program depends on multiple factors, including our ability to charge sufficient fees for our services and a variety of regulatory and operational contingencies. There is no assurance that we will have the financial resources to complete our proposed investment program, and our inability to do so may adversely affect the operation and development of our business leading to the imposition of fines levied by ANEEL as well as a reduction in tariff levels.
We are largely dependent upon the economy of the State of Paraná.
Our distribution market for the majority of our sales of electricity is located in the State of Paraná. Although a more competitive market involving possible sales to customers outside Paraná might develop in the future, our business depends and is expected to continue to depend to a very large extent on the economic conditions of Paraná. We cannot assure you that economic conditions in Paraná will be
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favorable to us in the future. The GDP (gross domestic product) of the State of Paraná increased 2.5% in 2017, while Brazil’s GDP increased 1.0% during the same period.
The recessive economic environment of recent years led to the reduction of energy consumption in the State of Paraná and in Brazil as a whole, resulting in leftover energy in the interconnected system, consequently reducing (i) short-term prices and (ii) prices negotiated in the free market. At the same time, prices in the regulated market have risen steadily as a result of supply deficiencies on the part of contracted energy by distributors and high prices in the short-term market in previous years. As a result, consumers consistently migrated into the free market and, therefore, the captive market of distributors suffered a reduction in 2016 and 2017. A reduction in the captive market often leads to distributors selling excess contracted energy in the short-term market. This short-term market is subject to relevant price fluctuations. Whenever the price in the short-term market is lower than the price paid by the distributor in its long-term energy purchase agreement, the sale of energy in the short-term market is made at a loss, which may not be recovered in the future.
Deteriorating economic conditions in the State of Paraná and increasing energy prices may affect both the ability of our distribution costumers to pay amounts they owe us, as well as increase the number of our commercial losses. An increase in our commercial losses or uncollected receivables could materially adversely affect our business, financial condition and results of operations.
An increase in electricity prices, as well as poor economic performance in the State of Paraná, would affect the ability of some of our distributions customers to pay amounts owed to us. As of December 31, 2017, our past due receivables with Final Customers were approximately R$565.0 million in the aggregate, or 12.1% of our revenues from electricity sales to Final Customers for the year ended December 31, 2017, and our allowance for doubtful accounts related to these receivables was R$168.2 million. See Note 7 to our audited consolidated financial statements.
In addition, increased prices and a deteriorating economy could result in a greater number of our distribution customers connecting illegally to our distribution grid, which would decrease our revenue from electricity sales to Final Customers. Furthermore, energy we lose to these illegal connections is considered a commercial loss, and we may incur regulatory penalties if our commercial losses exceed certain established regulatory thresholds.
Disruptions in the operation of, or deterioration of the quality of, our services, or those of our subsidiaries, could have an adverse effect on our business, financial condition and results of operations.
The operation of complex electricity generation, transmission and distribution systems and networks involves various risks, such as operational setbacks and unexpected interruptions, caused by accidents, breakdown or failure of equipment or processes, performance below expected levels of availability and efficiency of assets, or disasters (such as explosions, fires, natural phenomena, landslides, sabotage, vandalism, and similar events). In addition, operational decisions by authorities responsible for the electricity network, environment matters, operations and other issues affecting the electricity generation, transmission or distribution could have an adverse effect on the performance and profitability of the operations of our generation, transmission and distribution systems. If these issues occurred, our insurance may be insufficient to wholly account for the costs and losses that we may incur as a result of the damages caused to our assets, or due to outages.
Further, the revenues that our subsidiaries generate from establishing, operating and maintaining their facilities are related to the availability of equipment and assets, and to the quality of the services (continuity and service in accordance with levels demanded by regulations). Under the related concession contracts, we and our subsidiaries are subject to: (i) a reduction of the distributor revenue as a result of the reduction of the so-called “Portion B” allocation in the revenue calculation formula; (ii) a reduction of the Permitted Annual Revenue - APR (Receita Anual Permitida, or RAP), for the transmission companies; (iii) the effects of the Availability Factor (Fator de Disponibilidade, or FID) and the offtake guarantee levels for the generation facilities; and (iv) the application of penalties and payment ofcompensation amounts, depending on the scope, severity and duration of non-availability of the services and equipment. Therefore, outages or stoppages in our generation, transmission and distribution facilities, or in substations or networks, may cause a material adverse effect on our business, financial situation and results of operations.
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Failures in dams under our responsibility may cause serious damages to the affected communities, to our results and to our reputation.
Dams are important infrastructures to our business, accounting for the majority of our energy generation capacity. However, in any dam, there is an intrinsic risk of ruptures caused by different internal or external factors. Therefore, we are subject to the risk of a dam failure that could have repercussions much greater than just the loss of hydroelectric power generation capacity. A dam failure may result in economic, social, regulatory and environmental damages and potential loss of human life in the communities downstream from the dams, which may have a material adverse effect in the image, business, operational results of operations and financial conditions of the Company.
We are exposed to behaviors that are incompatible with our ethical and compliance standards, and we may be unable to prevent, detect or remediate them in time, which may cause material adverse effects in our operational results, financial condition and reputation.
We have a range of internal rules and controls, including a Governance, Risk and Compliance Office, with the aim to guide our managers, employees and third-party contractors, and to reinforce our ethical principles and rules of professional conduct. However, due to the wide distribution and outsourcing of the production chains of our suppliers, we are not able to control all possible irregularities of the latter and we are not able to ensure that our selection processes will be sufficient to avoid that our suppliers have problems related to compliance with applicable law, sustainability or outsourcing of the production chain under inadequate safety conditions.
Furthermore, we are subject to the risk that our employees, contractors or any person that may do business with us may involve themselves in fraudulent activities, corruption or bribery, circumventing our internal controls and procedures, misappropriating our assets or using them for private benefit to the detriment of the Company’s interests. This risk is increased by the fact that our portfolio includes affiliated companies, such as special purpose companies, some of which we do not hold a controlling interest in.
Our systems may not be effective in all circumstances. Any failure in our capacity to prevent or detect noncompliance with the applicable governance rules or regulatory obligations may cause damages to our reputation or other material adverse effects to our results of operation or financial condition.
The rules for electricity trading and market conditions may affect the sale prices of electricity.
Our energy trading business is strongly affected by regulatory changes that impact the methodology used for short term energy price formation.
We perform trading activities through power purchase and sale agreements, mainly in the Free Market,through our generation and trading companies. Agreements in the Free Market may be entered into with other generation and trading entities andmainly withFreeCustomers.
Energy trading is affected by changes in the methodology used to calculate energy prices in the short-term (PLD). PLD is determined by the results of optimization models of operation of the interconnected systems used by the ONS and by CCEE. In such determination, there may be data entry errors or errors in the model, which may lead to an unexpected change of the PLD and possible future republications of the PLD. Thus, there is a risk for the commercial business with respect to the alteration of these models, data entry errors and republishing of the PLD, which may cause market uncertainty, reduction of liquidity, and financial losses with unexpected price variation.Additionally, any change in the energy trading rules related to the increase of restrictions for the entry of new consumers in the Free Marketmay affect the expansion of our energy trading business.
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Our energy trading companies,Copel Comercializacao and Copel GeT, thatoperate in the Free Market may decide, based on market conditions, to operate in long and short positions and may present financial losses for certain periods.To operate in long positionsmeans thatwe buy electricitythat will be delivered to us only in the future andsell it before the deliveryis due, expectingthe pricetogo up in the short-term market.To operate in short positions means thatwe sell electricitythat needs to be delivered only in the future, butbuy it before the deliveryis dueexpectingthe pricetogo down in the short-term market.
Our management has identified material weaknesses in our internal controls and has concluded that our internal controls over financial reporting, with respect to the issues classified as material weaknesses, were not effective as of December 31, 2017, which may adversely affect our business and our operating results
Our management, fiscal council and internal auditors assess the effectiveness of our controls framework and reporting procedures in accordance with SEC rules, including the effectiveness of our internal controls over financial reporting. This analysis adopts the criteria established in the Internal Control - Integrated Framework (2013) published by the Committee of Sponsoring Organizations of the Treadway Commission – COSO.
During this evaluation, our management identified material weaknesses in our internal controls in 2017. These material weaknesses refer to our internal controls over (i) monitoring and authorizations of certain transactions in non-wholly owned subsidiaries, (ii) financial reporting related to the accounting of bonds and securities and taxes on regulatory assets, (iii) general information technology (IT) controls for the controlled companies, (iv) the review of estimates used in analyzing the impairment of fixed generation assets and (v) the identification of proceedings that may impact the risk provision for contingencies. In view of these weaknesses, our management concluded that our internal control over financial reporting was not effective as of December 31, 2017 with respect to the items classified as material weakness.
Although we have developed plans to remedy these material weaknesses, we cannot be certain that there will be no other material weaknesses in our internal control over financial reporting in the future. Therefore, we may be unable to report our results of operations for future periods accurately and in a timely manner and make our required filings with government authorities, including the SEC. Any of these occurrences could adversely affect our business and operating results and could generate negative market reactions, potentially leading to a decline in the price of our shares, ADSs and debt securities.
Risks Relating to the Brazilian Electricity Sector and Other Sectors that We Operate
We are uncertain as to the renewal of certain of our generation and transmission concessions.
Under Federal Law No. 12,783/2013, or the 2013 Concession Renewal Law, we may only renew our concessions that were in effect as of 1995 (and, in the case of generation facilities, generation concession contracts entered into prior to 2003) for an additional 30-year period (or an additional 20-year period in the case of thermal plants), if we agree to amend the terms of the concession contract that is up for renewal to reflect certain new terms and conditions imposed by the 2013 Concession Renewal Law, which vary depending on whether the concession is for generation, transmission or distribution. If we do not agree to amend the concession contract to reflect these new conditions, the concession contract cannot be renewed and will be subject to a competitive bidding process upon its expiration, which we might not win. If we do not renew our generation and transmission concessions or if they are renewed under less favorable conditions, our financial condition and results of operations could be materially adversely affected.For more information, see “Item 4. Information on the Company—Concessions”.
The concession agreement of our controlled company Compagas is under discussion with the granting authority
Compagas has entered into a concession agreement with the State of Paraná, as Granting Authority, pursuant to which the concession shall expire on July 6, 2024. The purpose of this concession is to provide piped gas distribution services and other related activities, to all segments of the consumer market, either as raw material or for the purpose of power generation or other uses made possible by technological advances.
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The gas concession agreement is part of theo called “bifurcated model”, where part of the investments made by the concessionaire is paid by the users of the public service and the remaining part is indemnified by the granting authority, the State of Paraná, at the end of the concession.
On December 7, 2017, the State of Paraná enacted Complementary Law no. 205, setting forth a new interpretation regarding the expiration date of the concession, leading to the understanding that the new expiration date will be January 20, 2019. The management of Compagas, its controlling shareholder and other shareholders are analyzing and questioning the effects of such law, as they understand that these effects are not consistent with the terms set forth in the current concession agreement.
Therefore, in the event of non-extension of the concession, even if Compagas is entitled to compensation for the investments made in the last 10 years prior to the end of the concession, the financial condition and results of operations of our controlled company may be adversely affected.
Our operating results depend on prevailing hydrological conditions, which have been volatile recently. The impact of water shortages and resulting measures taken by the government to conserve energy may have a material adverse effect on our business, financial condition and results of operations.
We are dependent on the prevailing hydrological conditions throughout Brazil and in the geographic region in which we operate. According to data from ANEEL, approximately 64.0% of Brazil’s installed capacity currently comes from hydroelectric generation facilities. Hydrological conditions in our region, and Brazil in general, are frequently subject to changes because of non-cyclical deviations in average rainfall.
From 2012 to 2015, Brazil experienced a period of low rainfall. Poor hydrological conditions could lead the Brazilian government to institute a rationing program, which would require that our distribution business distribute less energy to Final Customers. Our distribution business would be adversely affected by a mandatory rationing program because its revenues are partially based on the volume of electricity it provides through our distribution grid to Final Customers. However, a mandatory rationing program involves a predictable decrease in energy, which would allow our distribution business to better estimate the amount of electricity it must purchase in order to sell to Final Customers. In addition, in the context of a formal rationing program, our distribution business would be fully compensated for the amount of energy that it purchased prior to the rationing period in excess of the amount of energy it is allowed to distribute under the rationing program, through automatic adjustment in its energy supply contracts.
In contrast, the Brazilian federal government in the past has reacted to poor hydrological conditions not by implementing a formal rationing program, but rather by seeking to reduce the consumption of electricity by Final Customers by other means, for example through general conservation campaigns to raise public awareness. The effect of these campaigns is less predictable, making it difficultfor our distribution business to accurately estimate the volume of energy it needs to purchase for sale to Final Customers.
Furthermore, in the absence of a formal rationing program, our distribution business is not compensated for the amount of energy it had previously contracted that now exceeds the newly-depressed Final Customer demand. Even after a conservation or rationing program ends, it may take several years for demand by Final Customers to fully recover, if at all. Deteriorating hydrological conditions may, therefore, have a material adverse effect on our distribution business.
In 2014 and 2015 the Brazilian Federal Government provided and facilitated various forms of assistance to distribution concessionaires experiencing cash flow difficulties arising from poor hydrological conditions, which had increased their energy acquisitions costs thereby resulting in mismatches of cash flow in the short-term. These forms of assistance included funding from the CDE Account, credit facilities contracted by the CCEE through the ACR Account and the new “Bandeira Tarifária” system. There is no assurance that the Federal Government will continue this assistance, or that the Federal Government will continue it on favorable terms or that it will be sufficient to cover our losses. See “Item 4. Information on the Company—Energy Sector Regulatory Charges—CDE” and “Item 4. Information on the Company—Energy Sector Regulatory Charges—Regulated Market Account – ACR Account”.
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With respect to our generation business, in order to compensate for poor hydrological conditions and to maintain adequate water levels in reservoirs, the ONS may order the reduction of generation from hydroelectric power plants, which would be partially compensated by increased generation by thermoelectric plants. This mechanism for replacing hydroelectric production with thermoelectric production may not provide all of the energy we need to fulfill our obligations under existing energy supply contracts. To compensate for this deficit, our generation business can be required to purchase energy in the spot market, typically at higher prices, and we would not be able to pass on these increased costs. This mechanism impacts all generation companies in Brazil regardless of whether the geographical region in which a specific generator is located is experiencing low rainfall, and could have a material adverse effect on our generation business.
The Generation Scaling Factor, or GSF, is a factor used to adjust the guaranteed power output and represents the ratio between the total power produced by the hydroelectric plants that integrate the Energy Reallocation Mechanism (Mecanismo de Realocação de Energia, or MRE) and their guaranteed power outputs. This represents, on average, the amount of energy committed to energy generation contracts. If there are excessively low flow rates, the GSF equals to less than 1 and the hydroelectric generators that contracted their guaranteed power outputs have to incur additional costs to acquire energy in the spot market to fulfill their obligations. As Brazil experienced an unusually severe drought between 2012 and 2015, its energy generation was below its expected levels.
In 2015, the financial effects of the GSF on the generation companies were discussed. There was a broad sector debate on the effects of, and solutions for the GSF from an administrative, regulatory, business and legal perspective. Accordingly, Law No. 13,203, dated December 8, 2015, and ANEEL Resolution No. 684, dated December 11, 2015, established the criteria for the approval and the conditions for the renegotiation of the hydrological risks borne by certain hydroelectric generation companies. Pursuant to such new rules, the generators could share their hydrologic risks with consumers, through the payment of a “risk premium”. Copel Geração e Transmissão and Elejor filed a request for the renegotiation of the hydrological risk of HPPs Mauá, Foz do Areia, Santa Clara and Fundão, which was consented through ANEEL Decisions No. 84/2016 and 43/2016, respectively. Subsequently, in 2017 Copel Geração e Transmissão filed another request for the renegotiation of the hydrological risk of HPPs Cavernoso II e Baixo Iguaçu, which was consented through ANEEL Decision Nº 4101/2017. For more information, see Note 14.1 to our audited consolidated financial statements.
In addition, in an extreme scenario, given the increased presence of thermal generation in the national electric matrix, if a shortage of natural gas were to occur, this would increase the general demand for hydroelectric energy in the market and therefore increase the risk that a rationing program would be instated.
Regarding our energy trading business, the effect of volatility in hydrological conditions is the increase of the variation of energy price , which in turn increases the spot market volatility, thus affecting our operating results.
Spot price (PLD) is determined by mathematical models that consider the prevalence of hydroelectric plants in the Brazilian generation context, hydrological conditions, energy demand, fuel prices, deficit costs, the entry of new projects and the availability of generation and transmission equipment, and aim to find an optimal balance between the present benefit of water usage and the future benefit of its storage, measured in terms of the expected economy of the fuels in thermoelectric plants.
When there is great availability of hydrological resources, the spot price tends to remainat lower levels, which may not be enough to (i) cover the generation costs of this very same energy (when related to our generation business) and (ii) cover the cost of the power purchase and sale agreement in our energy trading business.
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Conversely, if hydrological availability is affected, spot prices tend to increase significantly, in addition to occasionally impacting the GSF, which may adversely impact our costs of energy purchases, as the price set forth in power purchase and sale agreements may not be sufficient.
The construction, expansion and operation of our generation, transmission and distribution facilities and equipment involve significant risks that may cause the loss of revenues or increase of expenses.
The construction, expansion and operation of our generation, transmission and distribution of electricity facilities and equipment involve many risks, including theinability to obtain required governmental permits and approvals,supply interruptions, strikes, climate and hydrological interference, unexpected environmental and engineering problems, increase in losses of electricity (including technical and commercial losses), the unavailability of adequate financing andthe unavailability of equipment.
In the event we experience these or other problems, we might not be able to generate, transmit and distribute electricity in favorable quantities and on favorable terms, which may adversely affect our financial condition and the results of our operations.
ANEEL could penalize us for failing to comply with the terms of our concessions or with applicable laws and regulations, and we may not recover the full value of our investment in the event that any of our concessions are terminated.
Our concessions are for terms of 20 to 35 years and may be extended if certain conditions are met. In the event that we fail to comply with any term of our concessions or applicable law or regulation, ANEEL may impose penalties on us, which may include warnings, the imposition of potentially substantial fines (in some instances, up to 2% of our revenues in the fiscal year immediately preceding the assessment) and restrictions on our operations, among others. ANEEL may also terminate our concessions prior to the expiration of their terms if we fail to comply with their provisions or if they determine that terminating our concessions would be in the public interest, in both cases through an expropriation proceeding. In particular, our renewed distribution concession agreement contains both quality and financial metrics that become more restrictive over time, and that we must meet to ensure that our distribution concession agreement is not terminated. If ANEEL terminates any of our concessions before its expiration, we would not be able to operate the segment(s) of our business that had been authorized by the concession. Furthermore, any compensation that we may receive from the federal government for the unamortized portion of our investment may not be sufficient for us to recover the full value of our investment. The early termination or non-renewal of any of our concessions or the imposition of severe fines or penalties by ANEEL could have a material adverse effect on our financial condition and results of operations. See “Item 4. Information on the Company—The Brazilian Electric Power Industry—Concessions”.
Our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are unfavorable to us.
The tariffs that we charge for sales of electricity to Captive Customers are determined pursuant to a concession agreement with the Brazilian government through ANEEL. ANEEL has substantial discretion to establish the tariff rates we charge our customers, which are determined pursuant to a concession agreement with ANEEL and in accordance with ANEEL’s regulatory decision-making authority.
Our distribution concession agreement and Brazilian law establish a price cap mechanism that permits three types of tariff adjustments: (i) annual adjustment (reajuste anual), (ii) periodic revision (revisão periódica), and (iii) extraordinary revision (revisão extraordinária). We are entitled to apply each year for the annual revision, which is designed to offset some effects of inflation on tariffs and pass through to customers certain changes in our cost structure that are beyond our control, such as the cost of electricity we purchase from certain sources and certain other regulatory charges, including charges for the use of transmission facilities. In addition, ANEEL carries out a periodic revision every five years that is aimed at identifying variations in our costs as well as setting a factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff revision, the effect of which is to ensure that we share the benefits of improved economies of scale with our customers. At any time, we may also request an extraordinary revision of our tariffs in the case of a significant and unexpected event, including if such an event significantly alters our cost structure.
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We cannot assure you that ANEEL will establish tariffs at rates that are favorable to us. To the extent that any of our requests for adjustments are not granted by ANEEL in a timely manner, our financial condition and results of operations may be adversely affected. In addition, ANEEL’s decisions relating to our tariffs may be contested by public authorities or by our customers. Administrative and judicial decisions resulting from these challenges may modify ANEEL’s decisions in a manner that is unfavorable to us, which may adversely affect our financial condition and results of operations.
We are subject to comprehensive regulation of our business, which fundamentally affects our financial performance.
Our business is subject to extensive regulation by various Brazilian legal and regulatory authorities, particularly the MME and ANEEL, which regulate and oversee various aspects of our business and establish our tariffs. Changes to the laws and regulations governing our operations, which have occurred in the past, could adversely affect our financial condition and results of operations.
For example, the Brazilian government has taken action to reduce tariffs in recent years. In order to substantially reduce the price paid by Final Customers for electricity, the Brazilian government enacted the 2013 Concession Renewal Law, which significantly changed the conditions under which concessionaires are able to renew concession contracts. Under the 2013 Concession Renewal Law, most generation, transmission and distribution concessionaires may be renewed at the request of the concessionaire for an additional period of 30 years, but only if the concessionaire agrees to amend the terms of the concession contract to reflect certain new terms and conditions. For more information, see “Item 4. Information on the Company - Concessions”.
If any further regulations or new laws are passed by the Brazilian government to lower electricity prices, these new laws and regulations could have a material adverse effect on our results of operations. If we are required to conduct our business in a manner substantially different from our current operations as a result of regulatory changes, our results of operations and financial condition may be adversely affected.
The regulatory framework under which we operate is subject to legal challenge.
The Brazilian government implemented fundamental changes in the regulation of the electric power industry under the 2004 legislation known as the New Industry Model Law (Lei do Novo Modelo do Setor Elétrico) and, recently, under the 2013 Concession Renewal Law. Challenges to the constitutionality of both laws are still pending before the Brazilian Supreme Court. If all or part of these laws were held to be unconstitutional, it would have uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legalproceedings is difficult to predict, but they could have an adverse impact on the entire energy sector, including our business and results of operations.
Certain customers in our distribution concession area may cease to purchase energy from our distribution business.
Our distribution business generates a large portion of its revenues by selling energy that it purchases from generation companies. Large electricity customers within the geographic area of our concession that meet certain regulatory requirements may qualify as free customers (“Free Customers”). A Free Customer in our distribution concession area is entitled to purchase energy directly from generation companies rather than through our distribution business, in which case that Free Customer would cease to pay our distribution business for that energy that we previously supplied. Therefore, if the number of Free Customers within the geographic area of our concession increases and these Free Customers purchase energy from sources other than our generation business, our revenues and results of operations would be adversely affected. Furthermore, prices in the free market have recently been lower than those in the regulated market in the past years, which has been leading to an increase in the number of Free Customers within the geographic area of our concession.
In addition, ANEEL has recently improved regulations related to micro and mini distributed generation, which has been facilitating customers to purchase or to lease power generation equipment, specially solar photovoltaic modules, to produce energy for their own consumption. Therefore, if the number of customers with micro and mini distributed generation within the geographic area of our concession increases, our revenues and results of operations could also be adversely affected.
We generate a portion of our operating revenues from Free Customers who may seek other energy suppliers upon the expiration of their contracts with us.
As of December 31, 2017, we had 191 Free Customers, representing approximately 5.1% of our consolidated operating revenues and approximately 10.6% of the total volume of electricity we sold to Final Customers.
Until March 31, 2018, Copel GeT signed 5 additional agreements with Free Customers in our generation business. Our contracts with Free Customers are typically for periods ranging between two years and five years in our generation business.
Approximately for Copel GeT, 9.4% of the megawatt-hours sold under contracts to Free Customers expired in 2017. These customers represented approximately 2.7% of the total volume of electricity that Copel GeT sold in 2017, and approximately 2.2% of Copel GeT operating revenues from energy sales for that year. There can be no assurance that Free Customers will enter into contracts or extend their current contracts to purchase energy from us.
Additionally, it is possible that our large industrial clients could be authorized by ANEEL to generate electric energy for their own consumption or sale to other parties, in which case they may obtain an authorization or concession for the generation of electric power in a given area, which could adversely affect our results of operations.
Regarding our energy trading company, as of December 31, 2017, we had 139 Free Customers, representing approximately 0.9% of our consolidated operating revenues and approximately 3.2% of the total volume of electricity we sold to Final Customers.
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We may be forced to purchase or sell energy in the spot market at higher or lower prices if our forecasts for energy demand are not accurate, if there is a shortage of energy supply available in the regulated market or if energy we contract is not delivered, and we may not be entitled to pass on any increased costs or incurred losses to our Final Customers in a timely manner, or at all.
Under the New Industry Model Law, electric energy distributors, including us, must contract to purchase, through public bids conducted by ANEEL, 100% of the forecasted electric energy demand fortheir respective distribution concession areas, up to seven years prior to the actual delivery of electric energy. We cannot guarantee that our forecasts for energy demand in our distribution concession area will be accurate. If our forecasts fall short of actual electricity demand, or if we are unable to purchase energy through the regulated market due to lack of energy supply in the market, or if a generation company fails to deliver energy that was previously contracted, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the spot market where we may pay significantly more for energy without being able to pass on these increased costs to our Final Customers. In addition, if we underestimate our distribution energy needs, we may be subject to penalties imposed by the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica, or “CCEE”). Moreover, if our forecasts surpass actual demand by more than the allowed margin (105% of actual demand), including where demand is depressed due to government campaigns in response to poor hydrological conditions or due to reduced economic activity, we will not be able to pass on to our Final Customers the cost of the excess energy that we acquire.
In 2016, as a consequence of the country’s economic crisis and the increase in the number of Free Customers who were attracted by lower prices in the free market, several distribution companies were contracted above 105% of their actual demand. As a result, those companies incurred losses arising from the sale of the excess energy at lower prices in the spot market. On the other hand, facing this same scenario in 2017, the distribution companies sold the surplus energy at a higher price in the spot market, resulting in the possibility of earnings.
On August 28, 2017 the Decree 9.143/2017 was published, recognizing the involuntary nature of energy surplus arising from the migration of consumers to the Free Market and, for the year 2018, this problem is expected to be solved. However, we cannot ensure the results of such new rules and their impact on our operations.
Our equipment, facilities and operations are subject to numerous environmental and health regulations, which may become more stringent in the future and may result in increased liabilities and increased capital expenditures.
Our distribution, transmission and generation activities are subject to comprehensive federal, state and local legislation, as well as supervision by Brazilian governmental agencies that are responsible for the implementation of environmental and health laws and policies. These agencies could take enforcement action against us for our failure to comply with their regulations and with requirements established for the maintenance of our environmental licenses. These actions could result in, among other things, the imposition of fines and revocation of licenses, which could have a material adverse effect on our financial condition and results of operations. It is also possible that enhanced environmental and health regulations will force us to allocate capital towards compliance, and consequently, divert funds away from planned investments. Such a diversion could have a material adverse effect on our financial condition and results of operations.
We are strictly liable for any damages resulting from inadequate provision of electricity services and our insurance policies may not fully cover such damages.
We are strictly liable under Brazilian law for damages resulting from the inadequate provision of electricity distribution services. In addition, our distribution, transmission and generation utilities may be held liable for damages caused to others as a result of interruptions or disturbances arising from the Brazilian generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the National Electric System Operator, theOperador Nacional do Sistema Elétrico (“ONS”). We cannot assure you that our insurance policies will fully cover damages resulting from inadequate rendering of electricity services, which may have an adverse effect on us.
We are the controlling shareholders of a company that operates a gas distribution business (Compagas) and we are consequently exposed to risks inherent to this sector.
We control a business in the gas distribution sector, which is operated by Companhia Paranaense de Gas – Compagas. This company is entitled to exclusive rights with respect to the supply of piped gas in the State of Paraná. The clients of this business are thermoelectric plants, cogeneration plants, gas stations, other companies and residences.
Businesses in the gas distribution sector are subject to a broad set of risks inherent to its operation, including among the main ones:
•Regulatory instability,
•Shortage of natural gas,
•Depending on a single supplier in Brazil,
•Capacity of financing expansion,
•Operational failures and accidents in distribution,
•Performance of outsourced service providers,
•Alternative energy sources,
•Quality in service.
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As a result of these uncertainties, there is no guarantee that the purposes of our gas distribution business will be achieved, which may have an adverse effect on our results of operations and our business.
We are the controlling shareholders of a company that operates a telecommunications business (Copel Telecomunicações S.A.) and we are consequently exposed to the risks inherent to this sector.
We control a business in the telecommunications sector under an authorization granted by the National Telecommunications Agency (Agência Nacional de Telecomunicações – ANATEL). This business provides telecommunications services through the use of fiber optics. It also provides a number of telecommunications services to other companies of the Copel group.
Businesses in the telecommunications sector are subject to a broad set of risks inherent to its operation, such as:
•Regulatory instability,
•Increase in competition,
•Technological changes,
•Capacity of financing our expansion,
•Failures in technological systems and information security,
•Performance of outsourced service providers,
•Exchange rate fluctuations,
•Variation in operating costs,
•Operational failures,
•Quality in service.
As a result of these uncertainties, there is no guarantee that the purposes of our telecommunications business will be achieved, which may have an adverse effect on our results of operations and our business.
Risks Relating to Brazil
Brazilian political and economic conditions could affect our business and the market price of the ADSs and our common shares. In addition, uncertainty regarding such changes could affect our business and the market price of the ADSs and our common shares.
The Brazilian government’sGovernment has significant influence over the Brazilian economy. Brazilian economic policiesand political conditions— and investor perception of these conditions— have in the past involved, among other measures, price controls, currency devaluations, capital controls and limitsa direct impact on imports. Ourour business, financial condition, and results of operations mayoperation and prospects.
Historically, the country’s political situation has influenced the performance of the Brazilian economy, and political crises have affected the confidence of investors and the general public, which resulted in economic deceleration, the downgrading of credit ratings of the Brazilian government and Brazilian issuers, and heightened volatility in the securities issued abroad by Brazilian companies. In August 2016, the Brazilian Congress approved the impeachment of the Brazilian president. Also, ongoing corruption investigations have led to charges against former and current public officials, members of several major political parties and directors and officers of many Brazilian companies. In addition, Brazil’s next presidential and federal legislative election will be adversely affected byin October 2018. We cannot predict the outcome of these elections or whether the elections will result in changes in Brazilian governmental and economic policies or in case they are reinstated. Thesethe Brazilian energy industry. Political instability and other measures could also affect the market priceupcoming elections may aggravate economic uncertainties in Brazil and increase volatility of the ADSs and our common shares.securities of Brazilian issuers.
TheAdditionally, the Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy. Frequenteconomy and significant intervention by the Brazilian government has often changedchanges monetary, tax, credit, tariffexchange and other policies to influence the course of Brazil’s economy. The Brazilian government’s actions to control inflationOur business, financial condition, results of operations and implement other policies have at times involved wage and price controls, devaluation of the real in relation to the U.S. dollar,prospects may be adversely affected by changes in taxgovernment policies, as well as other interventionist measures, suchfactors including, without limitation:
• fluctuations in the exchange rate;
• inflation;
• changes in interest rates;
• exchange control policies;
• fiscal policy and changes in tax laws;
• other political, diplomatic, social and economic developments that may affect Brazil or the international markets;
• controls on capital flows; and/or
• limits on foreign trade.
In the last few years, Brazil faced an economic recession, adverse fiscal developments and political instability. Brazilian GDP grew by 1.0% in 2017 but declined by 3.6% in 2016 and by 3.9% in 2015. Unemployment rate was 12.7% in 2017, 11.5% in 2016 and 6.9% in 2015. Inflation, as nationalization, raisingreported by the consumer price index (IPCA), was 2.95% in 2017, 6.29% in 2016 and 10.67% in 2015. The Brazilian Central Bank’s base interest rates, freezing bank accounts, imposing capital controlsrate (SELIC) was 7.00% on December 31, 2017, 13.75% on December 31, 2016 and inhibiting international trade14.25% on December 31, 2015. Future economic, social and political developments in Brazil. Brazil may impair our business, financial condition or results of operations, or cause the market value of our securities to decline.
Changes in, policy involving tariffs, exchange controls, regulationsor uncertainties regarding the implementation of, the policies above, might generate or contribute to uncertainties in the Brazilian economy. This would increase the volatility of the domestic capital market and taxation couldthe value of Brazilian securities traded abroad, and adversely affect our business, results of operations and financial condition.
Moreover, taking into account the Brazilian presidential system of government, and the considerable influence of the executive power, it is not possible to predict whether the presentgovernment or any successive governments will have an adverse effect on the Brazilian economy, and consequently on our business and financial results of the ADSs and our common shares.business.
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Fluctuations in the value of the Brazilian real against foreign currencies may result in uncertainty in the Brazilian economy and the Brazilian securities market, and theywhich could have a material adverse effect on our net income and cash flow.
In recent years, the Brazilianrealhas fluctuated in value against foreign currencies, and the value of therealmay rise or decline substantially from current levels. For instance, depreciationOver the course of 2015, the value of the Brazilianreal declined more than 48% against the U.S. Dollar, and on September 23, 2015 reached its lowest value since the introduction of the currency. In contrast, in the course of 2016, the Brazilian real appreciated 16.5% against the U.S. Dollar, following a year of intense volatility. In 2017, the Brazilian real was subject to relative stability. As of December 31, 2017, thereal vs. U.S. dollar exchange rate was R$3.31 to US$1.00, depreciating only 1.5% against the U.S. Dollar, compared to the exchance rate recorded on December 31, 2016. Depreciation of therealincreases the cost of servicing our foreign currency-denominated debt and the cost of purchasing electricity from the Itaipu – a hydroelectric facility thatwhich is one of our major suppliers and that adjusts its electricity prices based in part on its U.S. dollar costs. Depreciation of therealalso creates additional inflationary pressurespressure in Brazil that may negatively affect us. DepreciationIndeed, depreciation generally curtails access to international capital markets and may prompt government intervention. It also reduces the U.S. dollar value of our dividends and the U.S. dollar equivalent of the market price of our common shares and the ADSs. For additional information about historical exchange rates, see “Exchange Rates”.
IfInflation and governmental measures to curb inflation may contribute to economic uncertainty in Brazil, experiences substantial inflation in the future,and could reduce our margins and the market price of the Class B Shares and ADSs may be reduced.ADSs.
Brazil has in the past experienced extremely high rates of inflation. More recently, Brazil’s annual rates of inflation, measured in accordance with the variation of theÍndice Geral de Preços-Disponibilidade Interna (“IGP-DI”) index, were2.4%were 0.8% for the three monthsthree-month period ended March 31, 2015, 3.7%2018, (0.4)% in 2014, 5.5%the year 2017, 7.2% in 20132016 and 8.1%10.7% in 2012.2015. 2017 was a year of stabilizing inflation rates. Brazilian inflation rates observed in 2017 were below the government’s desired rate, but this scenario can change abruptly as a consequence of facts beyond our control. The Brazilian government has in the past taken measures to combat inflation, such as raising the basic Selic interest rate to elevated levels, and public speculation about possible future government actions has had significant negative effects on the Brazilian economy. This speculation may increase in 2018, when a new presidential election will occur in Brazil. Although our concession contracts provide for annual readjustmentsadjustments based on inflation indexes, if Brazil experiences substantial inflation in the future, and the Brazilian government adopts inflation control policies similar to those adopted in the past, our costs may increase faster than our revenues, our operating and net margins may decrease and, if investor confidence lags, the price of the Class B Shares and ADSs may fall. Inflationary pressures may also curtail our ability to access foreign financial markets and could lead to further government intervention in the economy, including the introduction of government policies that may adversely affect the overall performance of the Brazilian economy.
Allegations of political corruption against the Brazilian federal government and the Brazilian legislative branch could create economic and political instability.
In the past, members of the federal governmentCurrently, several former and of the Brazilian legislative branch have faced allegations of political corruption. As a result, a number of politicians, including senior federal officialsand congressman, resigned and/or have been arrested. Currently, severalcurrent members of the Brazilian executive and legislative branches of government are being investigated as a result of allegations of unethical and illegal conduct identified by the Operation Car Wash Operation (Operação Lava-Jato) being conducted by the Office of the Brazilian Federal Prosecutor.Prosecutor, and a number of politicians and businessmen have been arrested. The potential outcome of these investigations is unknown, but they have already had an adverse impact on the image and reputation of the investigated companies, in addition to adversely impacting general market perception of the Brazilian economy, including our business, financial condition and results of operations, as well as the trading price of our common shares and ADSs. Moreover, the conclusion of these proceedings or further allegations of illicit conduct could have additional adverse effects inon the Brazilian economy. We cannot predict whether such allegations will lead to further instability or whether new allegations against key Brazilian government officials will arise in the future. In addition, we cannot predict the outcome of any such allegations and their effect on the Brazilian economy.
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TableIn addition, the Brazilian economy continues to be subject to the effects of Contentsthe impeachment of President Dilma Rousseff on August 31, 2016. Vice-President Michel Temer was sworn in as the new President of Brazil until the next presidential election in October 2018, but political uncertainty has remained. We cannot predict the effects of these recent developments and the current ongoing political uncertainties on the Brazilian economy.
Changes in Brazilian tax policies may have an adverse effect on us.
The Brazilian government has in the past changed its tax policies in ways that affect the electricity sector, and it may do so again in the future. These changes include increases in the tax rates affecting energy companies and, occasionally, the collection of temporary taxes related to specific governmental purposes. If we are unable to adjust our tariffs accordingly, we may be adversely affected.
Negative developments in other national economies, especially those in developing countries, may negatively impact foreign investment in Brazil and the country’s economic growth.
International investors generally consider Brazil to be an emerging market. Historically, adverse developments in the economies of emerging markets have resulted in investors’ perception of greater risk from investments in such markets. Such perceptions regarding emerging market countries have significantly affected the market value of securities of Brazilian issuers. Furthermore, although economic conditions are different in each country, investors’ reactions to developments in one country can impact the prices of securities in other countries, including those in Brazil, and this may diminish investors’ interest in securities of Brazilian issuers, including ours.
Risks Relating to Our Company and our Operations
We are controlled by the State of Paraná, the policies and priorities of which directly affect our operations and may conflict with the interests of our investors.
We are controlled by the State of Paraná, which holds 58.6% of our outstanding common voting shares as of the date of this annual report, and whose interests may differ from other shareholders. As a major shareholder, the State of Paraná has the power to control all of our operations, including the power to elect a majority of the members of our Board of Directors and determine the outcome of any action requiring common shareholder approval, including transactions with related parties and corporate reorganizations.
The operations of the Company have had and will continue to have an important impact on the commercial and industrial development of the State of Paraná. In the past, the State of Paraná has used, and may in the future use, its status as our controlling shareholder to decide whether we should engage in certain activities and make certain investments aimed, principally, to promote its public polices or social objectives and not necessarily to meet the objective of improving our business and/or operational results.
We are largely dependent upon the economy of the State of Paraná.
Our distribution market for the majority of our sales of electricity is located in the State of Paraná. Although a more competitive market involving possible sales to customers outside Paraná might develop in the future, our business depends and is expected to continue to depend to a very large extent on the economic conditions of Paraná. We cannot assure you that economic conditions in Paraná will be favorable to us in the future. The GDP (gross domestic product) of the State of Paraná increased 0.8% in 2014, while Brazil’s GDP increased 0.1% during the same period.
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Deteriorating economic conditions in the State of Paraná and increasing energy prices may affect both the ability of our distribution costumers to pay amounts they owe us, as well as the amounts of our commercial losses. An increase in our commercial losses or uncollected receivables could materially adversely affect our business, financial condition and results of operations.
The general economic performance of Brazil and of the State of Paraná have declined recently. In addition, the price of electricity paid by our distribution customers has been increasing. An increase in electricity prices, as well as poor economic performance in the State of Paraná generally, would in each case affect the ability of some of our distributions customers to pay amounts owed to us. As of December 31, 2014, our past due receivables with final customers were approximately R$393.3 million in the aggregate, or 9.0% of our revenues from electricity sales to final customers for the year ended December 31, 2014, and our allowance for doubtful accounts related to these receivables was R$158.2 million. See Note 7 to our audited consolidated financial statements.
In addition, increased prices and a deteriorating economy could result in a greater number of our distribution customers connecting illegally to our distribution grid, which would decrease our revenue from electricity sales to final customers. Furthermore, energy we lose to these illegal connections is considered a commercial loss, and we may incur regulatory penalties if our commercial losses exceed certain established regulatory thresholds.
We are involved in several lawsuits that could have a material adverse effect on our business if their outcome is unfavorable to us.
We are the defendant in several legal proceedings, mainly relating to civil, administrative, labor and tax claims. The outcome of these proceedings is uncertain and, if determined against us, may result in obligations that could materially affect our results of operations. At December 31, 2014 our provisions for probable and reasonably estimated losses were R$1,546.6 million. For additional information, see “Item 8. Financial Information—Legal Proceedings”.
The construction and expansion of our transmission and power generation projects involve significant risks that may have an adverse effect on us.
In connection with the development of transmission and generation projects, we generally must obtain feasibility studies, governmental concessions or authorizations, permits and approvals, condemnation agreements, equipment supply agreements, engineering, procurement and construction contracts, sufficient equity and debt financing and site agreements, each of which involves the consent of third parties over which we have no control. In addition, project development is subject to environmental, engineering and construction risks that can lead to cost overruns, delays and other impediments to timely complete within a project’s budget. We cannot assure you that all required permits and approvals for our projects will be obtained, that we will be able to secure private sector partners for any of our projects, that we or any of our partners will be able to obtain adequate financing for our projects or that financing will be available on a non-recourse basis to us.
If we are unable to complete a project, whether at the initial development phase or after construction has commenced, or if the completion of a project is delayed, this may decrease our expected financial return from the project, which may lead to impairment. If we experience these or other problems relating to the expansion of our electricity transmission and power generation capacity, we may be exposed to increased costs, or we may fail to achieve the revenues we planned in connection with such expansion projects, which may have an adverse effect on our financial condition and results of operations.
We are subject to limitations regarding the amount and use of public sector financing, which could prevent us from obtaining financing and implanting our investment plan.
Our current budget anticipates capital expenditures for expansion, modernization, research, infrastructure and environmental projects of approximately R$2,476.9 million in 2015. As a state- controlled company, we are subject to certain National Monetary Council (Conselho Monetário Nacional - “CMN”) and Brazilian Central Bank (Banco Central do Brasil) limitations regarding the level of credit financial institutions may offer to public sector entities. As a result, we may have difficulty in obtainingfinancing from Brazilian and international financial institutions, which could create difficulties in the implementation of our investment plan. As a result of these regulations, our capacity to incur debt is limited, which could negatively affect the implementation of our investment plan.
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Security breaches and other disruptions could compromise our data centers and operations and expose us to liability, which would cause our business and reputation to suffer.
In our ordinary course of business, we collect and store personal data of our customers in our data centers. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss of information could affect our operations and could result in legal claims or proceedings under Brazilian laws that protect the privacy of personal information (among others) and damage our reputation.
Risks Relating to the Brazilian Electricity Sector
We are uncertain as to the renewal of certain of our concessions, some of which are due to expire in 2015.
Under the 2013 Concession Renewal Law, we may only renew our concessions that were in effect as of 1995 (and, in the case of generation facilities, generation concession contracts entered into prior to 2003) for an additional 30-year period (or an additional 20-year period in the case thermal plants), if we agree to amend the terms of the concession contract that is up for renewal to reflect certain new terms and conditions imposed by the 2013 Concession Renewal Law, which vary depending on whether the concession is for generation, transmission or distribution. If we do not agree to amend the concession contract to reflect these new conditions, the concession contract cannot be renewed and will be subject to a competitive bidding process upon its expiration, which we might not win. Up to now, we have decided not to renew our generation concession contracts that are set to expire by 2015 and are therefore subject to competitive bidding processes pursuant to the 2013 Concession Renewal Law, and we decided to renew pursuant to the 2013 Concession Renewal Law our one transmission concession contract that is set to expire by 2015.
For distribution concessions, we are unsure of the conditions that the Ministry of Mines and Energy, orMinistério de Minas e Energia (“MME”), and the Brazilian Electricity Regulatory Agency, or theAgência Nacional de Energia Elétrica (“ANEEL”), will require in order to renew these concession contracts, and we cannot assure you that we will be able to renew our main distribution contract, which expires on July 7, 2015, on terms that are favorable to us. The request for extension of our main distribution concession was presented to ANEEL on May 31, 2012 and we confirmed our request for renewal as required under the 2013 Concession Renewal Law. In January 2014, we received a response letter from ANEEL stating that it had analyzed our request, but that it had not made a final determination. If we do not renew our main distribution concession or if it is renewed under less favorable conditions, our financial condition and results of operations could be materially adversely affected.
For more information, see “Item 4. Information on the Company—Concessions”.
Our operating results depend on prevailing hydrological conditions, which have been deteriorating recently. The impact of water shortages and resulting measures taken by the government to conserve energy may have a material adverse effect on our business, financial condition and results of operations.
We are dependent on the prevailing hydrological conditions throughout Brazil and in the geographic region in which we operate. According to data from ANEEL, approximately 66% of Brazil’s installed capacity currently comes from hydroelectric generation facilities. Our region, and Brazil in general, is subject to unpredictable hydrological conditions because of non-cyclical deviations in average rainfall. In the years prior to 2001, we have experienced a period of low rainfall, which led the Brazilian government to institute a mandatory rationing program to reduce electricity consumption, which was in effect from June 1, 2001 to February 28, 2002.
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Brazil has recently been experiencing a period of similarly low rainfall. Like in 2001, the current hydrological conditions could lead the Brazilian government to institute a rationing program, which would require that our distribution business distribute less energy to final customers. Our distribution business would be adversely affected by a mandatory rationing program because its revenues are partially based on the volume of electricity it provides through our distribution grid to final customers. However, a mandatory rationing program involves a predictable decrease in energy, which would allow our distribution business to better estimate the amount of electricity it must purchase in order to sell to final customers. In addition, in the context of a formal rationing program, our distribution business would be fully compensated for the amount of energy that it purchased prior to the rationing period in excess of the amount of energy it is allowed to distribute under the rationing program, through automatic adjustment in its energy supply contracts.
In contrast, until now the Brazilian government has reacted to the current poor hydrological conditions not by implementing a formal rationing program, but rather by seeking to reduce the consumption of electricity by final customers by other means, for example through general conservation campaigns to raise public awareness. The effect of these campaigns is less predictable, making it difficult for our distribution business to accurately estimate the volume of energy it needs to purchase for sale to final customers. Furthermore, in the absence of a formal rationing program, our distribution business is not compensated for the amount of energy it had previously contracted that now exceeds the newly-depressed final customer demand. Even after a conservation or rationing program ends, it may take several years for demand by final customers to fully recover, if at all. Deteriorating hydrological conditions may therefore have a material adverse effect on our distribution business.
In 2014, the Brazilian Federal Government provided and facilitated various forms of assistance to distribution concessionaires experiencing cash flow difficulties arising from poor hydrological conditions, which had increased their energy acquisitions costs thereby resulting in mismatches of cash flow in the short-term. These forms of assistance included funding from the CDE Account, credit facilities contracted by the CCEE through the ACR Account and the new “Bandeira Tarifária” system. There can be no assurance that the Federal Government will continue this assistance, that will continue it on favorable terms or that it will be sufficient to cover our losses. See “Item 4. Information on the Company—Energy Sector Regulatory Charges—CDE” and Item 4. Information on the Company—Energy Sector Regulatory Charges—Regulated Market Account – ACR Account”.
With respect to our generation business, in order to compensate for poor hydrological conditions and to maintain adequate water levels in reservoirs, the ONS may order the reduction of generation from hydroelectric power plants, which would be partially compensated by increased generation by thermoelectric plants. This mechanism for replacing hydroelectric production with thermoelectric production may not provide all of the energy we need to fulfill our obligations under existing energy supply contracts. To compensate for this deficit, our generation business can be required to purchase energy in the spot market, typically at higher prices, and we would not be able to pass on these increased costs. This mechanism impacts all generation companies in Brazil regardless of whether the geographical region in which a specific generator is located is experiencing low rainfall, and could have a material adverse effect on our generation business.
In addition, if a shortage of natural gas were to occur, this would increase the general demand for energy in the market and therefore increase the risk that a rationing program would be instated.
Our operating revenues could be adversely affected if ANEEL makes decisions relating to our tariffs that are unfavorable to us.
The tariffs that we charge for sales of electricity to captive customers are determined pursuant to a concession agreement with the Brazilian government through ANEEL. ANEEL has substantial discretion to establish the tariff rates we charge our customers, which are determined pursuant to a concession agreement with ANEEL and in accordance with ANEEL’s regulatory decision-making authority.
Our distribution concession agreement and Brazilian law establish a price cap mechanism that permits three types of tariff adjustments: (i) annual readjustment (reajuste anual), (ii) periodic revision (revisão periódica), and (iii) extraordinary revision (revisão extraordinária). We are entitled to applyeach year for the annual readjustment, which is designed to offset some effects of inflation on tariffs and pass through to customers certain changes in our cost structure that are beyond our control, such as the cost of electricity we purchase from certain sources and certain other regulatory charges, including charges for the use of transmission facilities. In addition, ANEEL carries out a periodic revision every four years that is aimed at identifying variations in our costs as well as setting a factor based on our operational efficiency that will be applied against the index of our ongoing annual tariff readjustments, the effect of which is to ensure that we share the benefits of improved economies of scale with our customers. At any time, we may also request an extraordinary revision of our tariffs in the case of a significant and unexpected event, including if such an event significantly alters our cost structure.
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We cannot assure you that ANEEL will establish tariffs at rates that are favorable to us. To the extent that any of our requests for adjustments are not granted by ANEEL in a timely manner, our financial condition and results of operations may be adversely affected. In addition, ANEEL’s decisions relating to our tariffs may be contested by public authorities or by our customers. Administrative and judicial decisions resulting from these challenges may modify ANEEL’s decisions in a manner that is unfavorable to us, which may adversely affect our financial condition and results of operations.
We are subject to comprehensive regulation of our business, which fundamentally affects our financial performance.
Our business is subject to extensive regulation by various Brazilian legal and regulatory authorities, particularly the MME and ANEEL, which regulate and oversee various aspects of our business and establish our tariffs. Changes to the laws and regulations governing our operations, which have occurred in the past, could adversely affect our financial condition and results of operations.
For example, the Brazilian government has taken action to reduce tariffs in recent years. In order to substantially reduce the price paid by Final Customers for electricity, the Brazilian government enacted the 2013 Concession Renewal Law, which significantly changed the conditions under which concessionaires are able to renew concession contracts. Under the 2013 Concession Renewal Law, most generation, transmission and distribution concessionaires may be renewed at the request of the concessionaire for an additional period of 30 years, but only if the concessionaire agrees to amend the terms of the concession contract to reflect certain new terms and conditions. See “Item 4. Information on the Company—Concessions”.
If any further regulations or new laws are passed by the Brazilian government to lower electricity prices, these new laws and regulations could have a material adverse effect on our results of operations. If we are required to conduct our business in a manner substantially different from our current operations as a result of regulatory changes, our results of operations and financial condition may be adversely affected.
Certain customers in our distribution concession area may cease to purchase energy from our distribution business.
Our distribution business generates a large portion of its revenues by selling energy that it purchases from generation companies. Large electricity customers within the geographic area of our concession that meet certain regulatory requirements may qualify as Free Customers (“Free Customers”). A Free Customer in our distribution concession area is entitled to purchase energy directly from generation companies rather than through our distribution business, in which case that Free Customer would cease to pay our distribution business for that energy that we previously supplied. Therefore, if the number of Free Customers within the geographic area of our concession increases, the revenues and results of operations of our distribution business would be adversely affected.
We generate a portion of our operating revenues from Free Customers who may seek other energy suppliers upon the expiration of their contracts with us.
As of December 31, 2014, we had 29 Free Customers, representing approximately 3.7% of our consolidated operating revenues and approximately 14.2% of the total volume of electricity we soldto final customers. From January 1, 2015 until March 31, 2015, we had 2 (two) agreements with Free Customers that expired and were not renewed. Our contracts with Free Customers are typically for periods ranging between two years and five years.
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Approximately 6.1% of the megawatts sold under contracts to such customers are set to expire in 2015. In addition, as of December 31, 2014, we had 53 customers that were eligible to purchase energy as Free Customers. These customers represented approximately 4.6% of the total volume of electricity we sold in 2014, and approximately 7.6% of our operating revenues from energy sales for that year. There can be no assurance that Free Customers will enter into contracts or extend their current contracts to purchase energy from us.
Additionally, it is possible that our large industrial clients could be authorized by ANEEL to generate electric energy for their own consumption or sale to other parties, in which case they may obtain an authorization or concession for the generation of electric power in a given area, which could adversely affect our results of operations.
The regulatory framework under which we operate is subject to legal challenge.
The Brazilian government implemented fundamental changes in the regulation of the electric power industry under the 2004 legislation known as the New Industry Model Law (Lei do Novo Modelo do Setor Elétrico) and, recently, under the 2013 Concession Renewal Law. Challenges to the constitutionality of both laws are still pending before the Brazilian Supreme Court. If all or part of these laws were held to be unconstitutional, it would have uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but they could have an adverse impact on the entire energy sector, including our business and results of operations.
We may be forced to purchase energy in the spot market at higher prices if our forecasts for energy demand are not accurate, if there is a shortage of energy supply available in the regulated market, or if energy we contract is not delivered, and we may not be entitled to pass on any increased costs to our Final Customers in a timely manner, or at all.
Under the New Industry Model Law, electric energy distributors, including us, must contract to purchase, through public bids conducted by ANEEL, 100% of the forecasted electric energy demand for their respective distribution concession areas, up to five years prior to the actual delivery of electric energy. We cannot guarantee that our forecasts for energy demand in our distribution concession area will be accurate, particularly given the recent conservation campaigns by the Brazilian government in response to deteriorating hydrological conditions. If our forecasts fall short of actual electricity demand, or if we are unable to purchase energy through the regulated market due to lack of energy supply in the market, or if a generation company fails to deliver energy that was previously contracted, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the spot market where we may pay significantly more for energy without being able to pass on these increased costs to our Final Customers. In addition, if we underestimate our distribution energy needs, we may be subject to penalties imposed by the Electric Energy Trading Chamber (Câmara de Comercialização de Energia Elétrica, or “CCEE”). In addition, if our forecasts surpass actual demand by more than the allowed margin (105% of actual demand), including where demand is depressed due to government campaigns in response to poor hydrological conditions, we will not be able to pass on to our Final Customers the cost of the excess energy that we acquire.
Our equipment, facilities and operations are subject to numerous environmental and health regulations, which may become more stringent in the future and may result in increased liabilities and increased capital expenditures.
Our distribution, transmission and generation activities are subject to comprehensive federal, state and local legislation, as well as supervision by Brazilian governmental agencies that are responsible for the implementation of environmental and health laws and policies. These agencies could take enforcement action against us for our failure to comply with their regulations and with requirements established for the maintenance of our environmental licenses. These actions could result in, among other things, the imposition of fines and revocation of licenses, which could have a material adverse effect on our financial condition and results of operations. It is also possible that enhanced environmental and health regulations will force us to allocate capital towards compliance, and consequently, divert funds away from planned investments. Such a diversion could have a material adverse effect on our financial condition and results of operations.
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ANEEL could penalize us for failing to comply with the terms of our concessions or with applicable laws and regulations, and we may not recover the full value of our investment in the event that any of our concessions are terminated.
Our concessions are for terms of 20 to 35 years and may be extended if certain conditions are met. In the event that we fail to comply with any term of our concessions or applicable law or regulation, ANEEL may impose penalties on us, which may include warnings, the imposition of potentially substantial fines (in some instances, up to 2% of our revenues in the fiscal year immediately preceding the assessment) and restrictions on our operations, among others. ANEEL may also terminate our concessions prior to the expiration of their terms if we fail to comply with their provisions or if ANEEL determines, through an expropriation proceeding, that terminating our concession would be in the public interest. If ANEEL terminates any of our concessions before its expiration, we would not be able to operate the segment(s) of our business that had been authorized by the concession. Furthermore, any compensation that we may receive from the federal government for the unamortized portion of our investment may not be sufficient for us to recover the full value of our investment. The early termination or non-renewal of any of our concessions or the imposition of severe fines or penalties by ANEEL could have a material adverse effect on our financial condition and results of operations. See “Item 4. Information on the Company—The Brazilian Power Industry—Concessions”.
The construction, expansion and operation of our generation, transmission and distribution facilities and equipment involve significant risks that may cause loss of revenues or increase of expenses.
The construction, expansion and operation of our generation, transmission and distribution of electricity facilities and equipment involve many risks, including theinability to obtain required governmental permits and approvals,supply interruptions, strikes, climate and hydrological interference, unexpected environmental and engineering problems, increase in losses of electricity (including technical and commercial losses), the unavailability of adequate financing andthe unavailability of equipment.
In the event we experience these or other problems, we might not be able to generate, transmit and distribute electricity in favorable quantities and on favorable terms, which may adversely affect our financial condition and the results of our operations.
If we are unable to conclude our investment program on schedule, the operation and development of our business could be adversely affected.
In 2015, we plan to invest approximately R$1,300.1 million in our generation and transmission activities (including Baixo Iguaçu HPP, Colíder HPP and SPCs of transmission lines), R$162.6 million in Wind Farms, R$784.7 million in our distribution activities and R$107.7 million in our telecommunications activities. Our ability to complete this investment program depends on multiple factors, including our ability to charge sufficient fees for our services and a variety of regulatory and operational contingencies. There is no assurance that we will have the financial resources to complete our proposed investment program, and our inability to do so may adversely affect the operation and development of our business leading to the imposition of fines levied by ANEEL as well as reduction in tariff levels.
We are strictly liable for any damages resulting from inadequate provision of electricity services and our insurance policies may not fully cover such damages.
We are strictly liable under Brazilian law for damages resulting from the inadequate provision of electricity distribution services. In addition, our distribution, transmission and generation utilities may be held liable for damages caused to others as a result of interruptions or disturbances arising from the Brazilian generation, transmission or distribution systems, whenever these interruptions or disturbances are not attributed to an identifiable member of the National Electric System Operator, theOperador Nacional do Sistema Elétrico (“ONS”). We cannot assure you that our insurance policies will fully cover damages resulting from inadequate rendering of electricity services, which may have an adverse effect on us.
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Risks Relating to the Class B Shares and ADSs
As a holder of ADSs, you will generally not have voting rights at our shareholders’ meetings.
In accordance with Brazilian Corporate Law and our bylaws, holders of the Class B Shares, and thus of the ADSs, are not entitled to vote at our shareholders’ meetings except in limited circumstances. That means, among other things, that you, as a holder of the ADSs, are not entitled to vote on corporate transactions, including any proposed merger.
In addition, in the limited circumstances where the holders of Class B Shares are entitled to vote, holders may exercise voting rights with respect to the Class B Shares represented by ADSs only in accordance with the provisions of the deposit agreement relating to the ADSs. There are no provisions under Brazilian Corporate Law or under our bylaws that limit ADS holders’ ability to exercise their voting rights through the Depositary with respect to the underlying Class B Shares. However, the procedural steps involved create practical limitations on the ability of ADS holders to vote. For example, holders of our Class B Shares will be able to exercise their voting rights by either attending the meeting in person or voting by proxy. In accordance with the Deposit Agreement, we will provide the notice to the Depositary, which will in turn, as soon as practicable thereafter, mail to holders of ADSs the notice of such meeting and a statement as to the manner in which instructions may be given by holders. To exercise their voting rights, ADS holders must then instruct the Depositary how to vote their shares. Because of this extra procedural step involving the Depositary, the process for exercising voting rights will take longer for ADS holders than for direct holders of Class B Shares. ADSs for which the Depositary does not receive timely voting instructions will not be voted.
As a holder of ADSs, you will have fewer and less well-defined shareholders’ rights in Brazil than in the United States and certain other jurisdictions.
Our corporate affairs are governed by our bylaws and Brazilian Corporate Law, which may differ from the legal principles that would apply if we were incorporated in a jurisdiction in the United States or in certain other jurisdictions outside Brazil. Under Brazilian Corporate Law, you and the holders of the Class B Shares may have fewer and less well-defined rights to protect your interests in connection with actions taken by our Board of Directors or the holders of Common Shares than under the laws of the UnitedtheUnited States and certain other jurisdictions outside Brazil.
21
Although Brazilian law imposes restrictions on insider trading and price manipulation, the Brazilian securities markets are not as highly supervised as the United States securities markets or markets in certain other jurisdictions outside Brazil. For instance, rules and policies against self-dealing and regarding the preservation of minority shareholder interests may be less developed and not as robustly enforced in Brazil as in the United States and certain other jurisdictions outside Brazil, which could potentially disadvantage you as a holder of the preferred shares and ADSs. In addition, shareholders in Brazilian companies must hold 5% of the outstanding share capital of a corporation in order to have standing to bring shareholders’ derivative suits, and shareholders in Brazilian companies ordinarily do not have standing to bring a class action suit.
You may be unable to exercise preemptive rights relating to the preferred shares.
You will not be able to exercise the preemptive rights relating to the Class B Shares underlying your ADSs unless a registration statement under the United States Securities Act of 1933, as amended (“Securities Act”), is effective with respect to those rights or an exemption from the registration requirements of the Securities Act is available. Therefore, the Depositary will not offer rights to you as a holder of the ADSs unless the rights are either registered under provisions of the Securities Act or are subject to an exemption from the registration requirements. We are not obligated to file a registration statement with respect to the shares or other securities relating to these rights, and we cannot assure you that we will file any such registration statement. Accordingly, you may receive only the net proceeds from the sale of your preemptive rights by the Depositary or, if the preemptive rights cannot be sold, they will be allowed to lapse. If you are unable to participate in rights offerings, your holdings may also be diluted.
Sales of a substantial number of shares, or the perception that such sales might take place, could adversely affect the prevailing market price of our shares or ADSs.
As a consequence of the issuance of new shares, sales of shares by existing share investors, or the perception that such a sale might occur, the market price of our shares and, by extension, of the ADSs may decrease significantly.
Future equity issuances may dilute the holdings of current holders of our shares or ADSs and could materially affect the market price for those securities.
We may in the future decide to offer additional equity to raise capital or for other purposes. Any such future equity offering could reduce the proportionate ownership and interests of holders of our shares and ADSs, as well as our earnings and net equity value per share or ADS. Any offering of shares and ADSs by us or our main shareholders, or a perception that any such offering is imminent, could have an adverse effect on the market price of these securities.
You may not receive dividend payments if we incur net losses or our net profit does not reach certain levels.
Under Brazilian Corporate Law and our by-laws, we must pay our shareholders a mandatory distribution equal to at least 25% of our adjusted net profit for the preceding fiscal year, with holders of preferred shares having priority of payment. According to our bylaws, Class A Shares and Class B Shares are entitled to receive annual, non-cumulative minimum dividends, which dividend per share shall be at least 10% higher than the dividends per share paid to the holders of the Common Shares. Class A Shares have a dividend priority over the Class B Shares, and Class B Shares have a dividend priority over the Common Shares.
If we realize a net profit in an amount sufficient to make dividend payments, at least the mandatory dividend is payable to holders of our preferred and common shares. After payment of the mandatory dividend, we can retain profits as statutory profit reserves for investments or capital reserves. If we incur net losses or realize net profits in an amount insufficient to make dividend payments, including the mandatory dividend, our management may recommend that dividend payments be madeusing the statutory profit reserve after accounting for the net losses for the year and any losses carried forward from previous years. In the event that we areunable to declare dividends, our management may nevertheless decide to defer payment of dividends or, in limited circumstances, not to declare dividends at all. We cannot make dividend payments from our legal reserve and capital reserve accounts.
Additionally, in accordance with Brazilian Corporate Law, in fiscal years in which the amount of mandatory dividends exceeds the amount of realized net profits, according to the parameters set forth in this law, management may suggest the formation of a reserve for realizable profits. This reserve can be offset with any losses and then used for paying mandatory dividends.
1522
Holders of our ADSs may be unable to enforce judgments against our directors or officersofficers.
All of our directors and officers named in this annual report reside in Brazil. Substantially all of our assets, as well as the assets of these persons, are located in Brazil. As a result, it may not be possible for holders of our ADSs to effect service of process upon us or our directors and officers within the United States or other jurisdictions outside Brazil, attach their assets or to enforce against us or our directors and officers judgments obtained in the United States or other jurisdictions outside of Brazil. Because judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain requirements are met, holders of ADSs may face greater difficulties in protecting their interest in actions against us or our directors and officers than would shareholders of a corporation incorporated in a state or other jurisdiction of the United States.
Judgments of Brazilian courts with respect to our shares will be payable only in reais.
If proceedings are brought in the courts of Brazil seeking to enforce our obligations in respect of our shares, we will not be required to discharge any such obligations in a currency other than reais (R$). Under Brazilian exchange control limitations, an obligation in Brazil to pay amounts denominated in a currency other than reais (R$) may only be satisfied in Brazilian currency at the exchange rate, as determined by the Central Bank, in effect on the date the judgment is obtained, and any such amounts are then adjusted to reflect exchange rate variations through the effective payment date. The then prevailing exchange rate may not afford non Brazilian investors with full compensation for any claim arising out of, or related to, our obligations under our shares.
If you exchange your ADSs for Class B Shares, you risk increased taxes and the inability to remit foreign currency abroad.
Brazilian law requires that parties obtain a registration before the Central Bank in order to be allowed to remit foreign currencies, including U.S. dollars, abroad. For the ADSs, the Brazilian custodian for the Class B Shares has obtained the necessary certificate from the Central Bank for the payment of dividends or other cash distributions relating to the preferred shares or upon the disposition of the preferred shares. If you exchange your ADSs for the underlying Class B Shares, however, you must obtain your own certificate of registration or register in accordance with Central Bank and CVM rules in order to obtain and remit U.S. dollars abroad upon the disposition of the Class B Shares or distributions relating to the preferred shares. If you do not obtain a certificate of registration, you may not be able to remit U.S. dollars or other currencies abroad and may be subject to less favorable tax treatment on gains with respect to the preferred shares. Pursuant to Central Bank rules, obtaining this registration requires exchange transactions, which are subject to taxes in Brazil. For more information, see “Item 10. Additional Information—Taxation—Brazilian Tax Considerations—Other Brazilian Taxes”.
If you attempt to obtain your own registration, you may incur expenses or suffer delays in the application process, which could delay your ability to receive dividends or distributions relating to the preferred shares or the return of your capital in a timely manner. The custodian’s registration before the Central Bank and any certificate of foreign capital registration you obtain may be affected by future legislative changes. Additional restrictions may be imposed in the future on the disposition of the underlying Class B Shares or the repatriation of the proceeds from disposition.
23
The Brazilian government may impose exchange controls and restrictions on remittances abroad which may adversely affect your ability to convert funds inreais into other currencies and to remit other currencies abroad.
In the past, the Brazilian government has imposed restrictions on the remittance to foreign investors of the proceeds of their investments in Brazil and the conversion of Brazilian currency into foreign currencies. The Brazilian government could again choose to impose this type of restriction if, among other things, there is deterioration in Brazilian foreign currency reserves or a shift in Brazil’s exchange rate policy. ReimpositionReintroduction of these restrictions would hinder or prevent your ability to convert dividends, distributions or the proceeds from any sale of Class B Shares, as the case may be, fromreaisinto U.S. dollars or other currencies and to remit those funds abroad. We cannot assure you that the Brazilian government will not take similar measures in the future.
The relative volatility and illiquidity of the Brazilian securities markets may impair your ability to sell the Class B Shares underlying the ADSs.
The Brazilian securities markets are substantially smaller, less liquid, more concentrated and more volatile than major securities markets in the United States and certain other jurisdictions outside Brazil, and are not as highly regulated or supervised as some of these other markets. The illiquidity and relatively small market capitalization of the Brazilian equity markets may cause the market price of securities of Brazilian companies, including our ADSs and Class B Shares, to fluctuate in both the domestic and international markets, and may substantially limit your ability to sell the Class B Shares underlying your ADSs at a price and time at which you wish to do so.
Instability of the exchange rate could adversely affect the value of remittances of dividends outsideofBrazil and also the market price of the ADSs.
Many Brazilian and global macroeconomic factors have an influence on the exchange rate. In this context, the Brazilian federal government, through the Central Bank, has in the past occasionally intervened for the purpose of controlling unstable variations in exchange rates. We cannot predict whether the Central Bank or the federal government will continue to allow the real to float freely or whether it will intervene through a system involving an exchange rate band, or the use of other measures.
As a result, the real might fluctuate substantially in relation to the United States dollar, and other currencies, in the future. That instability could adversely affect the equivalent in US dollars of the market price of our shares, and as a result the prices of our ADSs and also outward dividends remittances from Brazil.For more information, see “Item 3. Key Information – Exchange Rates”.
Changes in economic and market conditions in other countries, especially Latin American and emerging market countries, may adversely affect our business, results of operations and financial condition, as well as the market price of our shares, preferred ADS and common ADSs.
The market value of the securities of Brazilian companies is affected to varying degrees by economic and market conditions in other countries, including other Latin American countries and emerging market countries. Although the economic conditions of such countries may differ significantly from the economic conditions of Brazil, the reactions of investors to events in those countries may have an adverse effect on the market value of the securities of Brazilian issuers. Crises in other emerging market countries might reduce investors’ interest in the securities of Brazilian issuers, including our Company. In the future, this could make it more difficult for us to access the capital markets and finance our operations on acceptable terms or at all. Due to the characteristics of the Brazilian power industry (which requires significant investments in operating assets) and due to our financing needs, if access to the capital and credit markets is limited, we could face difficulties in completing our investment plans and refinancing our obligations, and this could adversely affect our business, results of operations and financial condition.
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16
Law No. 10,833 of December 29, 2003, provides that the disposition of assets located in Brazil by a non resident to either a Brazilian resident or a non-resident is subject to taxation in Brazil, regardless of whether the disposition occurs outside or within Brazil. This provision results in the imposition of income tax on the gains arising from a disposition of our common or preferred shares by a nonresident of Brazil to another non-resident of Brazil. There is no judicial guidance as to the application of Law No. 10,833 and, accordingly, we are unable to predict whether Brazilian courts may decide that it applies to dispositions of our ADS between nonresidents of Brazil. However, in the event that the disposition of assets is interpreted to include a disposition of our ADS, this tax law would accordingly result in the imposition of withholding taxes on the disposition of our ADS by a non-resident of Brazil to another non-resident of Brazil.
25
Item 4. Information on the Company
We are engagedengage in the generation, transmission, distribution and sale of electricity mainly in the Brazilian State of Paraná, pursuant to concessions granted by ANEEL, the Brazilian regulatory agency for the electricity sector, ANEEL.sector. We also provide telecommunications and other services.
AtAs of December 31, 2014,2017, we generated electricity from 18 (eighteen)seventeen (17) hydroelectric plants, 1 (one)twelve (12) wind plantplants and 1 (one)one (1) thermoelectric plant, for a total installed capacity of 4,754.45,024.0 MW, of which, approximately 99.6% of which is derived from renewable sources. Including the installed capacity of generation companies in which we have an equity interest, our total installed capacity is 5,360.45,675.9 MW. Our electric power business is subject to comprehensive regulation by ANEEL.
We hold concessions to distribute electricity in 394 of the 399 municipalities in the State of Paraná and in the municipality of Porto União in the State of Santa Catarina. AtAs of December 31, 2014,2017, we owned and operated 2,1742,698.3 km of transmission lines and 189,925.4196,951.2 km of distribution lines, constituting one of the largest distribution networks in Brazil. Of the electricity volume we supplied in 2017 to our Final Customers during 2014:Customers:
· 38.4%31.6% was to industrial customers;
· 25.8%29.2% was to residential customers;
· 19.4%19.9% was to commercial customers; and
· 16.4%19.3% was to rural and other customers.
Key elements of our business strategy include the following:
· expanding our power generation, transmission, distribution, and telecommunication systems;
· expanding our generation business’ sales to Free Customers both inside and outside of the State of Paraná;
· seeking productivity improvements in the short term and sustained growth in the long term;
· striving to keep customers satisfied and our workforce motivated and prepared;
· seeking cost efficiency and innovation;
· achieving excellence in data, image, and voice transmission; and
· researching new technologies in the energy sector in order to expand power output with renewable and non-polluting sources.
Our revenues for each of the last three (3) financial years by activity are described in “Item 5. Operating and Financial Review and Prospects - Results of operations for the years ended December 31, 2017, 2016 and 2015”.
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Historical Background
We were formed in 1954 by the State of Paraná to engage in the generation, transmission and distribution of electricity, as part of a plan to bring the electric energy sector under state control. We acquired the principal private power companies located in the State of Paraná in the early 1970s. During the period fromFrom 1970 to 1977, we significantly expanded our transmission and distribution grid and worked to increase the connectivity of our network to networks in other Brazilian states. In 1979, a change in state law permitted us to extend our generating activities to include production from sources other than hydroelectric and thermal power plants.
17
Currently, we are the largest energy company in the State of Paraná. We are a corporation incorporated and existing under the laws of Brazil, with the legal name Companhia Paranaense de Energia – Copel. Our head offices are located at Rua Coronel Dulcídio, 800, CEP 80420-170 Curitiba, Paraná, Brazil. Our telephone number at the head office is (55-41) 3322-3535+55 (41) 3222-2027 and our website is www.copel.com.www.copel.com. The commercial name of each of our businesses is provided as follows.
Relationship with the State of Paraná
The State of Paraná owns 58.6% of our Common Shares and, consequently, has the ability to control the election of the majority of the members of our Board of Directors, members of our Fiscal Council, the appointment of senior management and our direction, future operations and business strategy.
Corporate Structure
Prior to 2001, we operated as a single corporation engaged in the generation, transmission and distribution of electricity and in certain related activities. In compliance with the changednew regulatory regime, we transferred our operations to four wholly-owned subsidiaries one(one each for generation, transmission, distribution and telecommunicationstelecommunications) and our investments in other companies to a fifth wholly-owned subsidiary. This corporate restructuring was completed in July 2001.
In 2007, to comply with energy sector legislation, we divided the assets of our transmission business (“Copel Transmissão S.A.”) between our distribution business (“Copel Distribuição S.A.”) and our generation business, (“Copel Geração S.A.”). As a result, we changed the name of the latter entity to Copel Gera��Geração e Transmissão S.A. We also liquidated Copel Participações S.A. and distributed the equity interests it held in our controlled companies between Copel Geração e Transmissão and our holding company.
In 2013, the Company was restructured in order to enhance the efficiency of our corporate structure and reduce our operating costs.
On January 28, 2016, our board of directors approved the amendment of the bylaws of Copel Participações S.A., in order to change its corporate purpose and denomination to Copel Comercialização S.A. The corporate purpose of this company is the sale of energy and rendering of related services. The restructuring that created Copel Comercialização S.A. is aimed at strengthening Copel’s positioning in the energy trading market and to improve its efficiency, allowing for greater agility and flexibility in the sale of energy.
In September 2017, in order to optimize the management of operating activities, the Company carried out an organizational restructuring of its wholly-owned subsidiary Copel Renováveis S.A., whose activities were absorbed by Copel Geração e Transmissão S.A.
Copel currently has fourteenfive wholly-owned subsidiaries, the most significant of which are Copel Geração e Transmissão S.A., Copel Distribuição S.A., Copel Telecomunicações, Copel ParticipaçõesComercialização S.A. and Copel Renováveis.veis S.A.
The current organization of the group as of December 31, 2014 is as described below:as follows. All of our subsidiaries are incorporated in the Federative Republic of Brazil and subject to the Brazilian law.
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In the past, our generation and distribution businesses were integrated, and we sold most of the electricity we generated to the customers of our distribution business. This changed as a result of the implementation of the New Industry Model Law, enacted in 2004. Today, open auctions on the regulated market are the primary channel by which our generation business sells energy, and they arestill one of the primary channels by which our distribution business purchases energy to resell to captive customers.Captive Customers and one of the channels by which our generation business generates revenues. Our generation business only sells energy to our distribution business through auctions in the regulated market. OurMoreover, our distribution business, like other certain other Brazilian distribution companies, is also required to purchase energy from Itaipu, Binacional (“Itaipu”), a hydroelectric facility equally owned by Brazil and Paraguay, in an amount determined by the Brazilian government based on our proportionate share in the Brazilian electricity market. Itaipu has an installed capacity of 14,000 MW. Pursuant to a 1973 treaty between Brazil and Paraguay, Brazilian companies purchase the substantial majority of the electricity generated by Itaipu. For more information, see “Item 4. Information on the Company—The Brazilian Electric Power Industry”.
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19
The following table sets forthshows the total electricity we (i) generated through entities in which we hold a 100.0% shareholding stake and the 51.0% of energy generated by Mauá Hydroelectric Plant (corresponding to the interest we hold in this asset) and (ii) purchased in each of the last five years, broken down by showing the total amount of electricity generated and purchased by Copel Geração e Transmissão andWind Farms, and the total amount of electricity purchased by Copel Distribuição and Copel Comercialização.
| Year ended December 31, | ||||
| 2014 | 2013 | 2012 | 2011 | 2010 |
| (GWh) | ||||
Copel Geração e Transmissão |
|
|
|
|
|
Electricity generated | 24,605 | 24,420 | 18,181 | 25,789 | 24,321 |
Electricity purchased from others(1) | 612 | 2,505 | 3,981 | 952 | 696 |
Total electricity generated and purchased by Copel Geração e Transmissão | 25,217 | 26,925 | 22,162 | 26,741 | 25,017 |
Copel Distribuição |
|
|
|
|
|
Electricity purchased from Itaipu(2) | 5,870 | 5,193 | 5,256 | 5,278 | 5,306 |
Electricity purchased from Auction – CCEAR – affiliates | 411 | 832 | 1,316 | 1,327 | 1,230 |
Electricity purchased from Auction – CCEAR – other | 16,281 | 14,715 | 17,457 | 16,771 | 15,405 |
Electricity purchased from other(3) | 6,171 | 6,149 | 3,267 | 3,106 | 3,090 |
Total electricity purchased by Copel Distribuição | 28,733 | 26,889 | 27,296 | 26,482 | 25,031 |
Total electricity generated and purchased by Copel Geração e Transmissão and Copel Distribuição | 53,950 | 53,814 | 49,458 | 53,223 | 50,048 |
| Year ended December 31, | ||||
| 2017 | 2016 | 2015 | 2014 | 2013 |
| (GWh) | ||||
Copel Geração e Transmissão |
|
|
|
|
|
Electricity generated(1) | 19,867 | 25,850 | 24,960 | 24,605 | 24,420 |
Electricity purchased from others | 1,055 | 141 | 401 | 612 | 2,505 |
Electricity received from the Interconnected System(1) | 1,272 | - | - | - | - |
Total electricity generated and purchased by Copel Geração e Transmissão | 22,194 | 25,991 | 25,361 | 25,217 | 26,925 |
Wind Farms(2) |
|
|
|
|
|
Electricity generated | 1,024 | 1,218 | 662 | - | - |
Electricity purchased from others | - | - | 317 | - | - |
Total electricity generated and purchased by Wind Farms | 1,024 | 1,218 | 979 | - | - |
Copel Distribuição |
|
|
|
|
|
Electricity purchased from Itaipu(3) | 5,934 | 5,958 | 5,941 | 5,870 | 5,193 |
Electricity purchased from Auction – CCEAR – affiliates | 87 | 157 | 215 | 411 | 832 |
Electricity purchased from Auction – CCEAR – other | 9,860 | 13,387 | 14,419 | 16,281 | 14,715 |
Electricity purchased from others | 10,102 | 10,361 | 8,419 | 6,171 | 6,149 |
Total electricity purchased by Copel Distribuição | 25,983 | 29,863 | 28,994 | 28,733 | 26,889 |
Copel Comercialização |
|
|
|
|
|
Electricity purchased from others | 2,674 | 59 | - | - | - |
Total electricity purchased by Copel Comercialização | 2,674 | 59 | - | - | - |
Total electricity generated and purchased by Copel Geração e Transmissão, Copel Distribuição, Wind Farms and Copel Comercialização | 51,875 | 57,131 | 55,334 | 53,950 | 53,814 |
(1)Includes the total capacity made available butgenerated during the periods indicated. The total capacity generated might not be fully delivered (including energy from MREdue to technical and CCEE).non-technical losses.
(2)Electricity generated and purchased by our wind farm generation facilities which were under the supervision of Copel Renováveis until 2015. In December 2015, Copel Geração e Transmissão became responsible for the operation of these facilities.
(3)Distribution companies operating under concessions in the Midwest, South and Southeast regions of Brazil purchase electricity generated by Itaipu.
(3) Includes capacity made available but not fully delivered (including energy from Elejor and CCEE).
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The following table sets forthshows the total electricity we sold to Free Customers, captive customers,Captive Customers, distributors, energy traders and other utilities service providers in the south of Brazil through the Interconnected Transmission System that links the states in the south and southeast of Brazil, by showing the total amount of electricity sold by Copel Geração e Transmissão and Copel Distribuição in the last five years.
| Year ended December 31, | Year ended December 31, | ||||||||
| 2014 | 2013 | 2012 | 2011 | 2010 | 2017 | 2016 | 2015 | 2014 | 2013 |
| (GWh) |
|
| (GWh) |
|
| ||||
Copel Geração e Transmissão |
|
|
|
|
| |||||
Electricity delivered to Free Customers | 4,016 | 4,082 | 1,404 | 919 | 1,054 | 3, 860 | 3,823 | 3,906 | 4,016 | 4,082 |
Electricity delivered to bilateral agreements | 7,392 | 5,233 | 1,367 | 1,051 | 1,455 | 8, 504 | 7,682 | 6,675 | 7,392 | 5,233 |
Electricity delivered to Auction – CCEAR – affiliates | 411 | 832 | 1,316 | 1,327 | 1,230 | 86 | 157 | 215 | 411 | 832 |
Electricity delivered to Auction – CCEAR – other | 4,695 | 6,389 | 13,780 | 14,139 | 13,405 | 838 | 3,348 | 4,457 | 4,694 | 6,389 |
Electricity delivered to Spot Market – CCEE | 4,657 | 1,762 | 2,137 | 1,773 | 1,942 | |||||
Electricity delivered to the Interconnected System(1) | 7,970 | 9,796 | 3,856 | 8,625 | 7,233 | 3,755 | 8,575 | 7,360 | 6,197 | 7,855 |
Total electricity delivered by Copel Geração e Transmissão | 24,484 | 26,332 | 21,723 | 26,061 | 24,377 | 21,700 | 25,347 | 24,750 | 24,483 | 26,332 |
Wind Farms(2) |
|
|
|
| ||||||
Electricity delivered to Auction – CCEAR – other | 840 | 841 | 764 | - | - | |||||
Electricity delivered to Auction – CER – other | 357 | 358 | 269 | - | - | |||||
Total electricity delivered by Wind Farms | 1,197 | 1,199 | 1,033 | - | - | |||||
Copel Distribuição |
|
|
|
|
|
| ||||
Electricity delivered to captive customers | 24,208 | 22,926 | 23,248 | 22,454 | 21,304 | |||||
Electricity delivered to Captive Customers | 19,743 | 22,328 | 24,043 | 24,208 | 22,926 | |||||
Electricity delivered to distributors in the State of Paraná | 699 | 620 | 635 | 600 | 568 | 543 | 614 | 699 | 699 | 620 |
Spot Market – CCEE | 362 | 43 | 36 | 341 | 61 | |||||
Spot Market – CCEE(3) | 2,403 | 3,611 | 910 | 368 | 43 | |||||
Total electricity delivered by Copel Distribuição | 25,269 | 23,589 | 23,919 | 23,395 | 21,933 | 22,689 | 26,553 | 25,652 | 25,275 | 23,589 |
Copel Comercialização |
|
|
| |||||||
Electricity delivered to Free Customers | 774 | 58 | - | - | - | |||||
Electricity delivered to Spot Market – CCEE | 1,882 | 1 | - | - | - | |||||
Total electricity delivered by Copel Comercialização | 18 | 59 | - | - | - | |||||
Subtotal | 49,753 | 49,921 | 45,645 | 49,456 | 46,310 | 48,260 | 53,154 | 51,435 | 49,758 | 49,921 |
Losses by Copel Geração e Transmissão and Copel Distribuição | 4,197 | 3,893 | 3,816 | 3,767 | 3,738 | |||||
Total electricity delivered by Copel Geração e Transmissão and Copel Distribuição, including losses | 53,950 | 53,814 | 49,458 | 53,223 | 50,048 | |||||
Losses by Copel Geração e Transmissão, Copel Distribuição and Wind Farms(4) | 3,615 | 3,977 | 3,899 | 4,192 | 3,893 | |||||
Total electricity delivered by Copel Geração e Transmissão, Copel Renováveis, Copel Distribuição and Copel Comercialização, including losses | 51,875 | 57,131 | 55,334 | 53,950 | 53,814 |
(1) Includes capacity made available but not fully delivered.
(2) Electricity generated and purchased by our wind farm generation facilities which were under the supervision of Copel Renováveis until 2015. In December 2015, Copel Geração e Transmissão became responsible for the operation of these facilities.
(3) Includes the Mechanism for Compensation of Surpluses and Deficits (Mecanismo de Compensação de Sobras e Déficits - MCSD).
(4) Includes Technical, Non-technical and Basic network losses of Copel Distribuição and losses related to the allocation of agreements of Copel GeT.
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20
Generation
As of December 31, 2014,2017, considering only the entities in which we hold a 100.0% shareholding stake and 51.0% of the energy generated by Mauá Hydroelectric Plant (corresponding to the interest we hold in this asset), we operated and sold energy through 18 (eighteen)17 (seventeen) hydroelectric plants, 1 (one)12 (twelve) wind plantplants and 1 (one) thermoelectric plant, with a total installed capacity of 4,754.45,024 MW. On February 14, 2014, upon the expiration of the concession agreement of one of our hydroelectric plants (Rio dos Patos), we ceased to sell the energy produced by this plant but we continue to operate and maintain it until the winner of a new competitive bidding process to be conducted by ANEEL assumes the plant. If we include the installed capacity of the generation companies in which we have an equity interest, our total installed capacity as of December 31, 2014 was 5,360.4 MW. We produce electricity almost exclusively through our hydroelectric plants. Our assured energy totaled 2,067.6an average of 2,131.6 MW in 2014.2017. Our generation varies year by yearyearly as a result of hydrological conditions and other factors. We generated 24,604.820,891 in 2017, 27,068 GWh in 2016, 25,960 GWh in 2015, 24,605 GWh in 2014 24,420.4and 24,420 GWh in 2013, 18,180.9 GWh2013.
Considering the installed capacity of all of the generation companies in 2012, 25,789 GWh in 2011, and 24,321 GWh in 2010.which we have an interest (equity or otherwise), our total installed capacity as of December 31, 2017, was 5,675.9 MW.
The generation of electrical energy at our power plants is supervised, coordinated and operated by our Generation and Transmission Operation Center in the city of Curitiba. This operation center is responsible for coordinating the operations related to approximately 99.9% of our total installed capacity, including some of the plants in which we hold only partial ownership interests.
Hydroelectric Generation Facilities
The following table sets forth certain information relatingrelated to our main hydroelectric plants in operation at December 31, 2014:during 2017:
Plant | Installed capacity | Assured energy(1) | Placed in service | Concession expires | Installed capacity | Assured energy(1)
| Placed in service | Concession expires |
| (MW) | (GWh/yr) |
|
| (MW) | (GWh/yr) |
|
|
Foz do Areia | 1,676 | 5,045.8 | 1980 | 2023 | 1,676.0 | 5,045.76 | 1980 | September, 2023 |
Segredo | 1,260 | 5,282.3 | 1992 | 2029 | 1,260.0 | 5,282.28 | 1992 | November, 2029 |
Salto Caxias | 1,240 | 5,299.8 | 1999 | 2030 | 1,240.0 | 5,299.80 | 1999 | May, 2030 |
Capivari Cachoeira | 260 | 954.8 | 1970 | 2015 | 260.0 | 954.84 | 1971 | January, 2046 |
Mauá | 185(2) | 876.0 | 2012 | 2042 | 185.2(3) | 883.24 | 2012 | July, 2042 |
Others | 101.0 | 512.29 | N/A | N/A |
(1) Values used to determine volumes committed for sale.
(2)On January 5, 2016, Copel Geração e Tramissão executed a concession agreement with ANEEL so that it will continue to operate this plant under an operation and maintenance regime until 2046.
(3) Corresponds to 51%51.0% of the installed capacity of the plant (363(363.0 MW) as we operate this plant through a consortium.
Governador Bento Munhoz da Rocha Netto (“Foz do Areia” Plant).The Foz do Areia Hydroelectric Plant is located on the Iguaçu River, approximately 350 kilometers southwest of the city of Curitiba.
Governador Ney Aminthas de Barros Braga (“Segredo” Plant).The Segredo Hydroelectric Plant is located on the Iguaçu River, approximately 370 kilometers southwest of the city of Curitiba.
Governador José Richa (“Salto Caxias” Plant).The Salto Caxias Hydroelectric Power Plant is located on the Iguaçu River, approximately 600 kilometers southwest of the city of Curitiba.
Governador Pedro Viriato Parigot de Souza (“Capivari Cachoeira” Plant).The.The Capivari Cachoeira Hydroelectric Plant is the largest underground hydroelectric plant in Southern Brazil. Thereservoir is located on the Capivari River, approximately 50 kilometers north of the city of Curitiba, and the power station is located on the Cachoeira River, approximately 15 kilometers from the reservoir.
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Our concession agreement for the Capivari Cachoeira Plant expired on July 7, 2015. Although Copel Geração e Transmissão did not elect to renew the original concession pursuant the 2013 Concession Renewal Law, it participated in the new competitive bidding process and won. On January 5, 2016, Copel GeT executed a concession agreement with ANEEL, allowing it to continue to operate this plant under an operation and maintenance regime until January 5, 2046. We paid a total of R$574.8 million as the signing bonus for this concession and we received an annual generation revenue (AGR) of R$144.1 million from January 5, 2016 to December 31, 2016. This AGR was subject to an annual tariff adjustment in July 2017, pursuant to the Aneel Resolution No. 2,265/2017, and was set as R$114.1 million for the period from July 2017 to June 2018.
The Capivari Cachoeira Plant has 260.0 MW of installed capacity and assured energy of 954.8 GWh/year. 100.0% of the energy generated by this plant in 2016 was allocated in quotas to the regulated market (this number was reduced to 70.0% starting on January 1, 2017). Copel GeT will no longer bear the hydrological risk for the energy allocated in quotas under the MRE associated with the Capivari Cachoeira Plant.
Mauá.The.The Mauá Hydroelectric Plant is located on the Tibagi River, in the State of Paraná. It was constructed between 2008 and 2012 by Consórcio Energético Cruzeiro do Sul, in which Copel haswe hold a 51.0%51.0% interest and Eletrosul Centrais Elétricas S.A. (“Eletrosul”) holds the remaining 49.0%49.0%. ItThe facility is located approximately 250 kilometers from Curitiba, in the Municipality of Telêmaco Borba.
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In addition to our generation facilities, we have ownership interests in several other hydroelectric generation companies.
Between 2004 and 2010, we were required by law to retain a majority of the voting shares of any company in which we obtained an ownership interest. Starting in 2010, it became possible for us to hold non-controlling interests in companies.
The following table sets forth information regarding the hydroelectric generation plants in which we had a partial equity interest as of December 31, 2014:2017:
Plant | Installed capacity | Assured energy | Placed in service | Our ownership | Concession expires |
| (MW) | (GWh/yr) |
| (%) |
|
Elejor Facility(Santa Clara and Fundão) | 246.5 | 1,229.0 | July, 2005 | 70.0 | May, 2037(1) December, 2032 |
Dona Francisca | 125.0 | 664.9 | February, 2001 | 23.0 | August, 2033 |
PCH Arturo Andreoli (Foz do Chopim) | 29.1 | 178.6 | October, 2001 | 35.8 | April, 2030 |
Plant | Installed capacity | Assured energy | Placed in service | Our ownership | Concession expires |
| (MW) | (GWh/yr) |
| (%) |
|
Elejor Facility (Santa Clara and Fundão) | 246.4 | 1,229.0 | July 2005 | 70.0 | 2036 |
Dona Francisca | 125.0 | 683.3 | February 2001 | 23.0 | 2033 |
Foz do Chopim | 29.1 | 178.7 | October 2001 | 35.8 | 2030 |
Lajeado (Investco S.A) | 902.5 | 4,613.0 | December 2001 | 0.8 | 2032 |
(1)Elejor Facility adhered on January 14, 2015, with the renegotiation of the hydrological risks, which caused the expiration date to be extended from 2036 to 2037.
Elejor Facility. The Elejor Facility consists of the Santa Clara and Fundão Hydroelectric Plants, both of which are located on the Jordão River in the State of Paraná. The aggregate total installed capacity of the units is 246.4246.5 MW, which includes two smaller hydroelectric generation units installed in the same location. Centrais Elétricas do Rio Jordão S.A. (“Elejor”)Elejor signed a concession agreement with a term of 35 years for the Santa Clara and Fundão plants in October 2001. As of December 31, 2014,2017, we own 70.0% of the common shares of Elejor, andPaineira Participações owns the remaining 30.0%.
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Elejor is required to make monthly payments to the federal government for the use of hydroelectric resources, with total annual payments ofwhich in 2001 totaled R$19.0 million. This amount is adjusted on an annual basis by the Brazilian General Market Price Index,Índice Geral de Preços do Mercado (“IGP-M Index”).Index.
We have a power purchase agreement with Elejor, thatwhich provides that we will purchase all of the energy produced by the Santa Clara and Fundão facilities at a set rate until April 2019, to be adjusted annually in accordance with the IGP-M Index. In 2014,2017, Elejor’s net revenues and net profits were R$241.2291.6 million and R$19.296.2 million, respectively, while in 20132016 its net revenues and net profits were R$217.4263.7 million and R$41.949.1 million, respectively.
Dona Francisca. We own 23.03% of the common shares of Dona Francisca Energética S.A. (“DFESA”). The other shareholders are Gerdau S.A. with a 51.82% interest, Celesc S.A. with a 23.03% interest and Desenvix S.A. with a 2.12% interest. DFESA Hydroelectric Power Plant is located on the Jacuí River in the State of Rio Grande do Sul. The plant began full operations in 2001. As of December 31, 2014, DFESA had loans and financing in the total amount of R$5.1 million. The debt is secured by a pledge of shares of DFESA. Until March 2015, we had a power purchase agreement with DFESA, valued at R$81.3 million annually, under which Copel Geração e Transmissão purchased 100% of DFESA’s assured energy. In April 2015, we signed a new ten year power purchase agreement with DFESA, valued at R$18.917.0 million annually, under which Copel Geração e Transmissão purchases 23.03% of DFESA’s assured energy (proportional to Copel’s stake).
In 2014,2017, DFESA’s net revenues and net profits were R$109.970.7 million and R$43.838.5 million, respectively, while in 20132016 its net revenues and net profits were R$104.470.2 million and R$39.034.3 million, respectively.
PCH Arturo Andreoli (“Foz do ChopimChopim” Hydroelectric Plant).The Foz do Chopim Hydroelectric Plant is located on the Chopim River in the State of Paraná. We own 35.77%35.8% of the common shares of Foz do Chopim Energética Ltda., the entity that owns the Foz do Chopim Hydroelectric Plant. Silea Participações Ltda. owns the remaining 64.23%64.2%. The operation and maintenance of Foz do Chopim Hydroelectric Plant is performed by Copel Geração e Transmissão S.A. Energy supply agreements were executed at an average tariff of R$202.56/220.07/MWh. Foz do Chopim Energética Ltda. also has the authorization to operate Bela Vista SHP, a hydroelectric power plant whichthat is located inon the same river and has similar capacity. The process for obtaining the necessaryenvironmentalnecessary installation environmental license is ongoing. In 2014,2017, Foz do Chopim’s net revenues and net profits were R$40.240.8 million and R$23.729.8 million, respectively, while in 20132016 its net revenues and net profits were R$38.840.8 million and R$28.829.9 million, respectively.
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Wind Farm Generation Facilities
Since 2013 we have been expanding our energy generation capacity and diversifying our energy matrix through the development of renewable energy sources, like the construction and acquisition of wind farms in the State of Rio Grande do Norte.
The following table sets forth certain information relating to our wind farm plants in operation:
Plant | Installed capacity | Assured Power | Placed in Service | Concession Expires |
| (MW) | (Average MW) |
|
|
São Bento Energia(1) | 94.0 | 46.3 | February 2015 | 2046 |
Boa Vista | 14.0 | 6.3 | - | - |
Olho d'Água | 30.0 | 15.3 | - | - |
São Bento do Norte | 30.0 | 14.6 | - | - |
Farol | 20.0 | 10.1 | - | - |
Palmas | 2.5 | 0.5 | February 1999 | 2029 |
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Plant | Installed capacity | Assured Power | Placed in Service | Concession Expires |
| (MW) | (Average MW) |
|
|
São Bento Energia | 94.0 | 46.3 |
|
|
Boa Vista | 14.0 | 6.3 | February, 2015 | April, 2046 |
Olho d'Água | 30.0 | 15.3 | February, 2015 | May, 2046 |
São Bento do Norte | 30.0 | 14.6 | February, 2015 | May, 2046 |
Farol | 20.0 | 10.1 | February, 2015 | April, 2046 |
Palmas | 2.5 | 0.5 | November, 1999 | September, 2029 |
Copel Brisa Potiguar Wind Complex | 183.6 | 98.4 |
|
|
Asa Branca I | 27.0 | 14.2 | August, 2015 | April, 2046 |
Asa Branca II | 27.0 | 14.3 | September, 2015 | May, 2046 |
Asa Branca III | 27.0 | 14.5 | September, 2015 | May, 2046 |
Eurus IV | 27.0 | 14.7 | August, 2015 | April, 2046 |
Santa Maria | 29.7 | 15.7 | April, 2015 | May, 2047 |
Santa Helena | 29.7 | 16.0 | May, 2015 | April, 2047 |
Ventos de Santo Uriel | 16.2 | 9.0 | May, 2015 | April, 2047 |
São Miguel do Gostoso I(1) | 108.0 | 57.1 |
|
|
Carnaúbas | 27.0 | 13.1 | June, 2015 | April, 2047 |
Reduto | 27.0 | 14.4 | June, 2015 | April, 2047 |
Santo Cristo | 27.0 | 15.3 | June, 2015 | April, 2047 |
São João | 27.0 | 14.3 | June, 2015 | March, 2047 |
(1) Copel has a 49.0% interest in São Bento started its operations on February 26, 2015.Miguel do Gostoso I.
São Bento Energia. On February 26,25, 2015, the four wind farms (Boa vista,Vista, Olho d’Água, São Bento do Norte and Farol) included in the São Bento Wind Farm Complex, located in the State of Rio Grande do Norte, began operations. With an installed capacity of 94 MW and assured energy of 46.3 average-MW, the project is the first of a series of five complexes to be built by us in the State of Rio Grande do Norte until 2019.average-MW. In August 2010, an average43.7 average-MW of 43.7 MWs ofthe energy generated at a weighted average price of R$134.4/134.40/MWh (annually adjusted by IPCA index) was sold to fifteen distribution concessionaires in ANEEL public auctions. The energy to be generated by these wind farms wasis sold through 20-year term contracts.
Copel Brisa Potiguar Wind Complex. On September 15, 2015, Copel concluded the installation of the Brisa Potiguar Wind Complex with an installed capacity 183.6 MW and assured energy of 92.6 average-MW. An assured energy of 52.2 average-MW (from Asa Branca I, Asa Branca II, Asa Branca III and Eurus IV) was committed under contract to electric power distributors in the alternative energy auction in August 2010 at a weighted average price of R$135.40/MWh (adjusted annually by IPCA inflation index) and an average of 40.7 MW (from WPPs Santa Helena, Santa Maria and Ventos de Santo Uriel) was committed under contract in the 6th Reserve Energy Auction held in August 2011 at a weighted average price of R$101.98/MWh (annually adjusted by the IPCA inflation index). The energy to be generated was sold through 20-year term contracts with payments beginning in April 2015.
São Miguel do Gostoso I. In June 2014, we negotiated with Voltalia Energia do Brasil Ltda.(Voltalia) the acquisition of a 49.0% interest in the São Miguel do Gostoso I Wind Farm Complex, in the State of Rio Grande do Norte. The São Miguel do Gostoso wind farm complex has 108.0 MW of installed capacity and assured energy of 57.1 average-MW, and its energy was sold in the 4th Reserve Energy Auction at an average price of R$98.92/MWh through 20-year term contracts. In April 2015, weconcluded the construction of this wind farm complex and ANEEL, in July and August 2015, classified it as ready for commercial operation. This wind farm complex began production in June 2017 after completion of the necessary transmission lines.
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Thermoelectric Generation Facilities
The following table sets forth certain information relating toabout our thermoelectric plants in operation atas of December 31, 2014:2017:
Plant | Installed capacity | Assured energy | Placed in service | Our ownership | Concession expires | Installed capacity | Assured energy | Placed in service | Our ownership | Concession expires |
| (MW) | (GWh/yr) |
| (%) |
| (MW) | (GWh/yr) |
| (%) |
|
Araucária | 484.1 | 3,199.2(1) | September 2006 | 80.0 | 2029 | 484.1 | 3,199.2(1) | September, 2002 | 80.0 | December, 2029 |
Figueira | 20.0 | 90.2 | March 1969 | 100.0 | 2019 | 20.0 | 90.2 | April, 1963 | 100.0 | March, 2019 |
(1) The annual assured energy of thermal plants such as Araucária varies depending on the price of natural gas, according to criteria established by the MME.
Araucária. We have an 80.0% interest in UEG Araucária Ltda., which owns the Araucária Thermoelectric Plant. In December 2006, UEG Araucária Ltda. entered intoplant, a lease agreement under which it leasednatural gas thermoelectric power plant, located in the plant toPetróleo Brasileiro S.A. - Petrobras, and Petrobras entered into an operation and maintenance agreement with our subsidiary Copel Geração e Transmissão under which Copel Geração e Transmissão agreed to operate and maintain the plant. Both agreements expired on January 31, 2014. Therefore, asstate of February 1, 2014, UEG Araucária Ltda. is responsible for selling the energyproduced by theParaná. The Araucária Thermoelectric Plant. Thisplant has 484.1 MW of installed capacity, does not have Availability Agreements currently in force and operates under a business model in which revenue depends on the plant’s operation. When produced, energy iscurrentlynotwill be sold in long-term contracts, but rather is distributed in the spot market as directed by the ONS.
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TableAs identified by our management during the preparation of Contentsour unaudited consolidated interim financial information as of September 30, 2017, in 2014, UEG Araucária Ltda. invested in a Multimarket Investment Fund, which holds shares of other investment funds that in turn invest in a private company, whose main asset is a real estate development. As of September 30, 2017, such investment corresponded to R$157.1 million and was recognized under “Bonds and Securities”, in current assets, because, according to information delivered by the management of UEG Araucária to the Company’s Management, that investment was made in a wholly-owned fund, whose benchmark was 103.5% of the CDI (Interbank Deposit Certificate, a money market security) rate and that was composed of shares issued by other investment funds and government bonds, with immediate liquidity and that were available for sale.
As a result of a new valuation and investigations carried out by our management together with independent experts, we have restated our financial statements for the fiscal year ended December 31, 2015 and December 31, 2016, to correct our accounting for this investment and we have identified related material weaknesses in our internal control over financial reporting. For additional information, see Note 4.1 to our audited consolidated financial statements and “Item 15. Controls and Procedures”.
The investments made by UEG Araucária Ltda. are not highly liquid and this may impact the ability of UEG Araucária Ltda. to raise the necessary funds to operate the Araucária Thermoelectric plant.
Figueira. The Figueira plant is located in the city of Figueira, in the northeast of the state of Paraná (where the main coal basin of Paraná is located). The operation and maintenance of this facility are carried out by Companhia Carbonífera do Cambuí Ltda., a company also responsible for the supply of coal consumed in the plant.
The Figueira plant is currently in the modernization process, which consists of replacing the equipment. This process aims to make this plant more efficient, reduce emissions of gases and particles resulting from the burning of coal and comply with applicable environmental legislation.
The Figueira plant currently has an installed capacity of 20.0 MW, with two generating units of 10.0 MW and a physical guarantee of 10.3 average MW, as determined by Portaria nº 303/2004 issued by the Ministry of Mines and Energy of Brazil. The Figueira plant produces an average net energy of 8.6 MW (internal consumption of discount, recorded in Copel's Energy Balance Sheet). Due to the long period in which the Figueira plant was in operation and the use of outdated equipment, the maximum energy efficiency of this plant is approximately 15%.
After the modernization, the plant will maintain the installed capacity of 20.0 MW with only one generating unit and the physical guarantee of 17.7 MW, so that it is in compliance with Normative Resolution No. 500/2012, which defines a minimum efficiency of 25% for installations with installed capacity up to 50.0 MW.
Expansion and Maintenance of Generating Capacity
We expect to spend R$929.21,412.2 million in 20152018 to expand and maintain our generation capacity, including participation in new businesses, of which R$345.1888.5 million will be invested in Complexo Eólico Cutia, R$156.3 million will be invested in the Complexo Eólico Brisa Potiguar, R$98.7 million will be invested in the Colíder Hydroelectric Power Plant and R$158.571.7 million will be invested in the BaixoIguaçu Hydroelectric Power Plant and R$221.4 million will be invested in wind power plants.Plant. The remaining amount will be spent on equipment maintenance, the modernization of the HPP Foz dedo Areia, Hydroelectric power plant, amongthe modernization of the Figueira Thermal Power Plant and other projects.
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Hydroelectric Power Plant Projects
We have interests in several hydroelectric generation projects. The following table sets forth information regarding our planned major hydroelectric generation projects and recent acquisitions of hydroelectric generation facilities.under construction.
Facility | Installed capacity | Estimated assured energy(1) | Budgeted completion cost | Beginning of operation (expected) | Our ownership | Status | Installed capacity | Estimated assured energy(1) | Budgeted completion cost | Beginning of operation (expected) | Our ownership | Status |
| (MW) | (GWh/year) | (R$ million) |
| (%) |
| (MW) | (GWh/year) | (R$ million) |
| (%) |
|
Colíder HPP | 300.0 | 1,573 | 1,800 | April 2016 | 100.0 | Concession granted | 300.0 | 1,560 | 2,364 | June, 2018(2) | 100.0 | Concession granted |
Baixo Iguaçu HPP | 350.2 | 1,514 | 1,600 | December 2017(2) | 30.0 | Concession granted | 350.2 | 1,501 | 2,346 | November, 2018 | 30.0 | Concession granted |
(1) Values used to determine volumes committed for sale.
(2) The expected commercial operation in 2016 has changed becausescheduled commencement of operations for the environmental installation license has been suspended (Generating unit 1 is now scheduledColíder plant was delayed due to go into commercial operation on December 31, 2017 and generating units 2 and 3 in January and February 2018, respectively).fortuitous events.
Colíder.der. In July 2010, we won an ANEEL auctionbid for athe 35-year concession to constructbuild and operate the Colíder Hydroelectric Power Plant on the Teles Pires River in the State of Mato Grosso. The Colíder facilityplant will have an installed capacity of 300.0300.0 MW and will beis located inbetween the municipalities of Nova Canaã do Norte and Itaúba. The municipalities of Colíder Itaúba and Cláudia. Construction began in 2011. The project is in its final stage of construction.udia are also affected by the reservoir. The construction of the dam is onplant began in 2011 and about 94% of the work was concluded in 2017. The reservoir and the spillway were already completed. Equipment manufacturing and electromechanical assemblies are underway, with the generating unit 01 entering its final stage, with coating being applied and drainage system has been installed. The electromechanical equipment is being installedphase of assembly in 2018. In February 2016, we started the powerhouse. The first generating unit is in an advanced stage. Dueconstruction of a 64-km-long transmission line that will connect the plant to the “Cláudia” substation.
As a result of fortuitous events, in early 2013, the original construction schedule has been hampered. Copel GeT is requestingfiled an application with ANEEL to recognize an exclusionexcuse it from certain fines, penalties and charges incurred as a result of liability for the delay in the power plant’s start-up andbeginning of operations of the plant, initially scheduled for December 31, 2014. The request filed by Copel GeT was not approved by ANEEL, so Copel GeT filed an administrative appeal, which was denied on March 14, 2017. Not agreeing with the decision, Copel GeT again requested the reconsideration of such decision by ANEEL, which was definitively denied on July 04, 2017. On December 18, 2017, we filed an ordinary lawsuit regarding the matter.
Copel GeT has been deliveringhonoring the energy supply commitments of the Colíder HPP (CCEAR), totaling 125.0 average MW, as follows:
(i) From January 2015 to May 2016: Copel GeT used leftover energy de-contracted in other generation facilities.
(ii) June 2016: partial reduction pursuant to a Bilateral Agreement.
(iii) From June 2016 to December 2018: reduction of all of the Energy Commercialization Contracts in the Regulated Environment - CCEARs, pursuant to a Bilateral Agreement and participationin the Mechanism of Compensation of Remains and Deficits - MCSD de Energia Nova.
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As a result of the above, the Colíder HPP obtained a release of its obligations to deliver energy in accordance with2017 and 2018 under the terms of Colíder’s CCEAR since January 1, 2015, with energy from its own generation complexes. The commercial generation is scheduledcontracted CCEARs (125.0 average-MW).
Ordinance MME No. 258, on December 21, 2016, required Copel GeT to begin in April 2016. From the facility’s assured energy of 179.6ensure a 177.9 average MW 125.0for the plant, which was increased to 178.1 average MW by MME Ordinance No. 213 of July 14, 2017. Of this total, 125 average MW are committed under a 30-year contract, to distributors at a price of R$103.40/MWh, as of July 1, 2010 (adjusted annually in accordance withfor the variation of the IPCA inflation index)rate). The remaining 54.653.1 average MW power not sold under this contract hasagreement have not yet to bebeen contracted for and is stillare available for sale to large customersconsumers in the free market.
Baixo Iguaçu. In June 2013, we acquired a 30%30.0% equity interest in the Baixo Iguaçu HPP through a consortium, with no premium payment. Baixo Iguaçu is the last large energy project planned for the main river in the state of Paraná (IguaçIguaçu River)River and will be located around 30 km downstream from Governador José Richa HPP - the Salto Caxias Hydroelectric Power Plant, which is 100%100.0% owned by Copel. The Baixo Iguaçu facility will have an installed capacity of 350.2 MW and will be located in the municipalities of Capanema, Capitão Leonidas Marques, Planalto, Realeza and Nova Prata do Iguaçu. FromOf the facility’s assured energy of 172.8171.3 average MW 120.96(established by Ordinance MME No. 11, on January 18, 2017), 121 average MW are committed under a 30-year contract to distributors at a price of R$98.98/MWh, as of July 1, 2008 (adjusted annually in accordance with the IPCA inflation index), with supply starting in December 2017.November 2018. The remaining 51.8450.3 average MW power not sold under this contract has yet to be contracted for and is still available for sale to large customers in the free market.
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Constructionthis facility began in 2013. The2013 and the expected commercial operation in 2016 has changed because the environmental installation license has been suspended since June 2014 due to judicial disputes. The 4th Regional Federal Court determined the suspension of itsthe construction, works, as it understood thatbecause the construction did not have the approval of the ICMBio, the environmental agency responsible for the Iguaçu National Park (Parque Nacional do Iguaçu) (the natural reserve is located 500 meters from the plant). Generating
On August 23, 2016, we entered into the 2nd Amendment to the Concession Agreement with respect to the Baixo Iguaçu HPP, with the purpose of formalizing the new work schedule and recognizing that we should not be held liable for the delay in the implementation of the project for a period corresponding to 756 days, which was considered as an extension of the concession period. Consequently, the concession period was extended from August 19, 2047 to September 14, 2049.
In November 2017, ANEEL acknowledged, through Order No. 3,770, a new 46-day period during which we should not be held liable for delays in implementing the project as a result of systematic invasions of the construction site, carried out by unofficial entities, in mid-May and October 2016.
The civil works and electromechanical assembly in the powerhouse allowed the installation and positioning of important parts of the turbine-generator set, from the first generating unit, in the months of October and November of 2017. The diversion of the river to enable the construction of the last phase of the constructive sequence of the project, is expected to be executed in May 2018.
Baixo Iguaçu’s generating unit 1 is now scheduled to go into commercial operation on December 31, 2017in November 2018 and generating units 2 and 3 in December 2018 and January and February 2018,2019, respectively.
Wind Farm Projects
Currently, we hold 100%100.0% of the equity interest of 20 (twenty)13 (thirteen) wind power plants under construction, totaling 528.1 MW of installed capacity and we also hold 49.0% of the equity interest of the Wind Complex São Miguel do Gostoso, composed of 4 (four) wind power plant with 108.0312.9 MW of installed capacity. All of the energy to be produced from these wind farms was sold to distribution concessionaires through 20-year agreements. The following table sets forth information regarding our wind farm projects:
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Wind Farm | Installed capacity(1) | Estimated Assured Power | Budgeted completion cost | Beginning of operation (expected) | Our ownership | Status |
| (MW) | (Average MW) | (R$ million) |
| (%) |
|
Copel Brisa Potiguar | 196.1 | 92.9 | 972.5 | 2015 | 100.0 | Concession granted |
Nova Eurus IV | 30.0 | 13.7 | - | - | - | - |
Nova Asa Branca I | 30.0 | 13.2 | - | - | - | - |
Nova Asa Branca II | 30.0 | 12.8 | - | - | - | - |
Nova Asa Branca III | 30.0 | 12.5 | - | - | - | - |
Santa Maria | 30.0 | 15.7 | - | - | - | - |
Santa Helena | 30.0 | 16.0 | - | - | - | - |
Ventos de Santo Uriel | 16.1 | 9.0 | - | - | - | - |
Cutia | 332.0 | 126.2 | 1,310.7 | - | 100.0 | Concession granted |
Dreen Cutia | 25.2 | 9.6 | - | 2017 | - | - |
Dreen Guajiru | 21.6 | 8.3 | - | 2017 | - | - |
Esperança do Nordeste | 30.0 | 9.1 | - | 2017 | - | - |
GE Jangada | 30.0 | 10.3 | - | 2017 | - | - |
GE Maria Helena | 30.0 | 12.0 | - | 2017 | - | - |
Paraíso dos Ventos do Nordeste | 30.0 | 10.6 | - | 2017 | - | - |
Potiguar | 28.8 | 11.5 | - | 2017 | - | - |
São Bento do Norte I | 24.2 | 9.7 | - | 2019 | - | - |
São Bento do Norte II | 24.2 | 10.0 | - | 2019 | - | - |
São Bento do Norte III | 22.0 | 9.6 | - | 2019 | - | - |
São Miguel I | 22.0 | 8.7 | - | 2019 | - | - |
São Miguel II | 22.0 | 8.4 | - | 2019 | - | - |
São Miguel III | 22.0 | 8.4 | - | 2019 | - | - |
São Miguel do Gostoso | 108.0 | 57.1 | 513.9 | 2015 | 49.0 | Concession granted |
Carnaúbas | 27.0 | 13.1 | - | - | - | - |
Reduto | 27.0 | 14.4 | - | - | - | - |
Santo Cristo | 27.0 | 15.3 | - | - | - | - |
São João | 27.0 | 14.3 | - | - | - | - |
Wind Farm | Installed capacity(1) | Estimated Assured Power(2) | Budgeted completion cost | Beginning of operation (expected) | Our ownership | Concession expires |
| (MW) | (Average MW) | (R$ million) |
| (%) |
|
Cutia | 312.9 | 129.5 | 2,008.4 | - | 100.0 |
|
Dreen Cutia | 23.1 | 9.6 | - | July, 2018 | - | January, 2042 |
Dreen Guajiru | 21.0 | 8.3 | - | July, 2018 | - | January, 2042 |
Esperança do Nordeste | 27.3 | 9.1 | - | July, 2018 | - | May, 2050 |
GE Jangada | 27.3 | 10.3 | - | August, 2018 | - | January, 2042 |
GE Maria Helena | 27.3 | 12.0 | - | August, 2018 | - | January, 2042 |
Paraíso dos Ventos do Nordeste | 27.3 | 10.6 | - | August, 2018 | - | May, 2050 |
Potiguar | 27.3 | 11.5 | - | July, 2018 | - | May, 2050 |
São Bento do Norte I | 23.1 | 10.1 | - | September, 2018 | - | August, 2050 |
São Bento do Norte II | 23.1 | 10.8 | - | October, 2018 | - | August, 2050 |
São Bento do Norte III | 23.1 | 9.6 | - | January, 2019 | - | August, 2050 |
São Miguel I | 21.0 | 9.3 | - | November, 2018 | - | August, 2050 |
São Miguel II | 21.0 | 9.1 | - | November, 2018 | - | August, 2050 |
São Miguel III | 21.0 | 9.2 | - | December, 2018 | - | August, 2050 |
��
(1)The installed capacity for our wind farm projects can be reduced during the implementation of the projects.
Copel Brisa Potiguar(2). In August 2013, we acquired 100% The assured power of the generation assets of Salus Fundos de Investimento em Participações, a company that owned seven wind farm special purposes entities located in the State of Rio GrandeSão Bento Norte I, São Bento do Norte with total installed capacityII, São Miguel I, São Miguel II and São Miguel III was adjusted pursuant to Ministry of 196.1MW. An averageMines and Energy Ordinance no. 335/2017 dated as of 92.9 MW (from WPPs Asa Branca I, Asa Branca II, Asa Branca III and Eurus IV), was committed under contract to electric power distributors in the alternative energy auction in August 2010, at a weighted average price of R$135.40/ MWh (adjusted annually by IPCA inflation index). An average of 40.7 MW (from WPPs Santa Helena, Santa Maria and Santo Uriel), was committed under contract inthe reserve energy auction in August 2011, at a weighted average price of R$101.98/MWh (annually adjusted by the IPCA inflation index). The energy to be generated was sold through 20-year term contracts, with payments beginning in April 2015.
25
Table of ContentsNovember 14, 2017.
Cutia. On October 31, 2014, in the 6th Reserve Energy Auction, (LER), we sold 71.2 average MW from the Cutia Wind Farm Complex (Dreen Cutia, Dreen Guajiru, Esperança do Nordeste, GE Jangada, GE Maria Helena, Paraíso dos Ventos do Nordeste and Potiguar) for R$144.00/MWh (maximum(the maximum price in the auction). These seven wind farms have a combined installed capacity of 195.6180.6 MW, assured energy of 71.4 average-MWaverage MW and will beare being built in the cities of Pedra Grande and São Bento do Norte, in the State of Rio Grande do Norte.
Additionally, in the 20th New Energy Auction (A-5), held on November 28, 2014, we sold an additional 54.8 average-MWaverage MW of wind power energy (for R$136.97/MWh), through Availability Agreements with a 20-year supply term. With a total capacity of 136.4132.3 MW and assured energy of 54.858.1 average MW, the newest six wind farms (São Bento do Norte I, São Bento do Norte II, São Bento do Norte III, São Miguel I, São Miguel II and São Miguel III) belonging to the Cutia Wind Farm Complex, will beare being built in São Bento do Norte, in the State of Rio Grande do Norte, in the same region ofas the other Wind Farm Complexes belonging to Copel.
São Miguel do Gostoso. On June 05, 2014, we negotiated with Voltalia Energia do Brasil Ltda.(Voltalia), the acquisition of a 49% interest in the São Miguel do Gostoso Wind Farm Complex, in the state of Rio Grande do Norte (Brazil). The São Miguel do Gostoso wind farm complex, which is already under implementation, comprises four wind farms, 108 MW installed capacity, whose energy was sold in the Fourth Reserve Energy Auction by average price R$98.92 MWh, through 20-year term contracts, with supply beginning in April 2015.
38
ProposedDevelopment Projects
We are involved in various initiatives to study the technical, economic and environmental feasibility of certain hydroelectric, wind, power plantsolar photovoltaic and thermoelectric generation projects. These proposed generation projects would have a total of 876.2 MW of installed capacity. The following table sets forth information regarding our proposed generation projects.projects that are considered feasible under a technical, economic, social, environmental and land-related perspective pursuant to the above-mentioned studies.
Proposed Projects(1) | Estimated Installed Capacity | Estimated Assured Energy | Our Ownership |
| (MW) | (GWh/yr) | (%) |
HPP São Jerônimo | 331.0 | 1,560.2 | 41.2 |
WPP Complexo Jandaíra | 99.0 | 428.2 | 100.0 |
WPP Complexo Alto Oriente | 60.0 | 247.5 | 100.0 |
HPP Salto Grande | 47.0 | 235.8 | 36.0 |
SHP Dois Saltos | 30.0 | 135.7 | 30.0 |
SHP Bela Vista | 29.0 | 145.8 | 36.0 |
SHP Salto Alemã | 29.0 | 173.8 | 19.0 |
TOTAL | 625.0 | 2,927.0 | - |
(1)Do not include other proposed projects of Copel whose technical, economic, social, environmental and land-related feasibility is still under analysis.
Proposed Projects | Estimated Installed Capacity | Estimated Assured Energy | Our ownership |
| (MW) | (GWh/yr) | (%) |
HPP São Jerônimo | 331.0 | 1,560 | 41.2 |
SHP BelaVista | 29.0 | 157.4 | 36 |
SHP Dois Saltos | 25.0 | 119.1 | 30 |
SHP Pinhalzinho | 10.9 | 52.1 | 30 |
SHP Burro Branco | 10.0 | 45.1 | 30 |
SHP Foz do Turvo | 8.8 | 41.2 | 30 |
SHP Foz do Curucaca | 29.5 | 142.2 | 15 |
SHP Salto Alemã | 29.0 | 139.7 | 15 |
SHP São Luiz | 26.0 | 125.3 | 15 |
SHP Alto Chopim | 20.3 | 98.0 | 15 |
SHP Rancho Grande | 17.7 | 85.3 | 15 |
WPP Complexo Alto Oriente | 60.0 | 247.5 | 100 |
WPP Complexo Jandaia | 99.0 | 428.2 | 100 |
TPP Norte Pioneiro | 180.0 | 1,190.2 | 100 |
TOTAL | 876.2 | 4,458.3 | - |
In 2016, SEF - Saneamento e Engenharia Ferroviária Ltda decided to leave the Consortium Geração Luz Paranaense and its stake was distributed among the remaining consortium members. Therefore, the participation held by Copel in the projects (i) SHP Foz do Curucaca, (ii) SHP Salto Alemã, (iii) SHP Alto Chopim and (iv) SHP Rancho Grande; went from 15% to 19%. This increase did not require additional investments by COPEL. In 2017, the Authorization Grants previously granted by ANEEL to the SHP Foz do Curucaca, SHP Alto Chopim and SHP Rancho Grande were revoked upon request of the Consortium Geração Luz Paranaense and, as a consequence, such projects were removed from COPEL’s portfolio. Immediately after such revocation, Copel Geração e Transmissão S.A. requested and was granted, on behalf of the consortium, a registration of a grant intent (Registro de Intenção de Outorga) for the same projects. Currently, the feasibility and optimal use of such projects are under analyisis.
In 2015,2018, we plan to bid for concessions to construct and operate new hydroelectric power plants in power auctions in the regulated market for new generation projects. We are studying the feasibility ofourof our participation in the hydroelectric, and wind farms and solar photovoltaic projects planned to be listed in the A-5 Auctionsauctions of 2015.2018. We will also conduct studies of new hydroelectric power plants.
26
For instance, we have partnered withTableBE - Empresa de Estudos Energéticos S.A.,Minas PCH S.A.andSilea Participações S.A.to develop studies in the lower region of Contentsthe Chopim River, which may lead to the development of another 4 (four) hydroelectric projects.
In addition, weWe are also conducting studies related to future government auctions for wind farms, solar photovoltaic and hydropower plants, small hydroelectric plants and thermoelectric power plants in which we may eventually participate.
Other renewable energy projects under study or development include the use of municipal solid waste in power generation, cultivationand thermosolar energy. For instance, during a twelve-month period ending in 2017, Copel conducted solarimetric measurements in two solarimetric stations located in areas leased by Copel Brisa Potiguar. The development of micro algae forsolar energy production, windprojects in such areas is still under analysis and the corresponding studies are expected to be concluded as to be able to submit such projects to energy solar photovoltaic energy, energy from the crude vegetable oilauctions in 2018 and biogas production from micro algae.2019.
39
Transmission and Distribution
General
Electricity is transferred from power plants to customers through transmission and distribution systems. Transmission is the bulk transfer of electricity from generating facilities to the distribution system by means of the Interconnected Transmission System, in tension greater than or equal to 230 kV. Distribution is the transfer of electricity to Final Customers, in tension lesser or equal to 138 kV.
The following table sets forth certain information concerning our transmission and distribution grids aton the dates presented.
| At December 31, | As of December 31, | ||||||||
| 2014 | 2013 | 2012 | 2011 | 2010 | 2017 | 2016 | 2015 | 2014 | 2013 |
Transmission lines (km): |
|
|
|
|
|
| ||||
230 kV and 500 kV | 2,197.3 | 2,160.9 | 2,010.7 | 2,016.3 | 1,900.4 | 2,691.8 | 2,514 | 2,398.8 | 2,197.3 | 2,160.9 |
138 kV | 7.2 | 7.2 | 7.2 | 7.2 | 7.2 | |||||
69 kV(1) | - | 5.4 | ||||||||
69 kV(1) | - | - | - | - | 5.4 | |||||
Distribution lines (km): |
|
|
|
|
|
| ||||
230 kV | 123.5 | 63.3 | 68.3 | 66.1 | ||||||
230 kV(2) | - | 165.5 | 129.6 | 123.5 | 63.3 | |||||
138 kV | 5,153.5 | 5,054.7 | 4,880.1 | 4,705.3 | 4,586.3 | 5,935.0 | 5,970.3 | 5,866.6 | 5,153.5 | 5,054.7 |
69 kV | 727.2 | 932.5 | 968.5 | 1,003.5 | 981.5 | 866.4 | 695.4 | 695.3 | 727.2 | 932.5 |
34.5 kV | 82,232.5 | 81,546.1 | 81,253.3 | 80,662.2 | 79,496.2 | 84,639.2 | 84,071.3 | 83,347.4 | 82,232.5 | 81,546.1 |
13.8 kV | 101,688.7 | 100,279.8 | 99,195.1 | 97,981.0 | 96,863.6 | 105,510.6 | 104,556.0 | 103,488.2 | 101,688.7 | 100,279.8 |
Transformer capacity (MVA): |
|
|
|
|
|
| ||||
Transmission and distribution substations (69 kV – 500 kV)(2) | 21,649.7 | 20,576.5 | 19,454.8 | 19,415.3 | 18,398.6 | |||||
Transmission and distribution substations (69 kV – 500 kV)(3) | 22,849.3 | 22,535.4 | 21,727.2 | 21,649.7 | 20,576.5 | |||||
Generation (step up) substations | 6,312.4 | 5,006.8 | 6,335.0 | 6,335.0 | 6,312.4 | 6,312.4 | 5,006.8 | |||
Distribution substations (34.5 kV) | 1,545.0 | 1,480.2 | 1,504.8 | 1,539.6 | 1,533.7 | |||||
Distribution substations (34.5 kV) | 1,537.9 | 1,488.5 | 1,517.2 | 1,545.0 | 1,480.2 | |||||
Distribution transformers | 11,278.2 | 10,882.2 | 10,325.3 | 9,961.6 | 9,312.4 | 12,956.9 | 12,548.2 | 12,032.7 | 11,278.2 | 10,882.2 |
Total energy losses | 7.0% | 7.2% | 7.7% | 7.1% | 7.5% | |||||
Total energy losses(4) (5) | 7.8% | 8.1% | 7.8% | 8.1% | 8.2% | |||||
(1)As approved by ANEEL in 2008, these 69 kV transmission lines held by Copel Distribuição were transferred to Copel Geração e Transmissão, since they were part of our transmission business segment.
(2)Due to improvements to registration and control systems used by Copel Distribuição to classify and register its transmission lines, lines were classified pursuant to its insulation voltage, and not according to its structure and isolate components. Consequently, all lines previously registered by Copel Distribuição were reclassified and there are no lines classified as 230 kV anymore.
(3)This figure includes transformers with primary tensions of 69 kV and 138 kV which belong to Copel Distribuição but are implemented in 230 kV and 525 kV substations, which belong to Copel Geração e Transmissão.
(4)Percentage of losses on the energy injected in the distributor (technical and non-technical losses on injected energy). Does not consider losses in the basic network.
(5)We note that percentages measured until 2016 and reported in previous reports of the Company reflected the amounts of physical losses (Technical), commercial losses (Non-Technical) and losses on the basic network (allocation of agreements on the gravity center of the submarket) of Copel Distribuição, as well as the losses related to the allocation of agreements of Copel GeT. Those percentages were calculated taking into account the total of power purchased and sale agreements entered into by both Copel Distribuição and Copel GeT. For a better representation and comparison of the percentage of losses, we considered the percentage obtained by dividing the total amount of technical and non-technical losses by the energy injected into the network of Copel Distribuição. This percentage may be compared to other companies and has a more accurate physical meaning as it utilizes the database of measured data and not information taken from agreements of the period being analyzed.
40
Transmission
Our transmission system consists of all our assets of 230 kV and greater and a small portion of our 69 kV and 138 kV assets, which are used to transmit the electricity we generate and the energy we receive from other sources. In addition to using our transmission lines to provide energy to customers in the State of Paraná, we also transmit energy through the Interconnected Transmission System. Two companies owned by the federal government, Eletrosul and Furnas, Centrais Elétricas S.A. (“Furnas”), also maintain significant transmission systems in the State of Paraná. Furnas is responsible for the transmission of electricity from Itaipu, while Eletrosul’s transmission system links the states in the southofsouth of Brazil. Copel, like all other companies that own transmission facilities, is required to allow other partiesthird party access to its transmission facilities in exchange for a compensation at a level set by ANEEL.
27
Currently, we carry out the operation and maintenance of 2,2042,699 km of transmission lines, 32 (thirty-two)thirty-four (34) substations in the State of Paraná and 1two (2) substation in the State of São Paulo. In addition, we have partnerships with other companies to operate 1,442 4,380km of transmission lines and 4nine (9) substations through special purpose companies (SPCs).
41
The table belownext sets forth information regarding our transmission assets in operation:
Subsidiary / SPC | Transmission Lines | TL Extension (km) | Number of Substations | Concession Expiration Date | Transmission Lines | TL Extension(km) | Number of Substations | Concession Expiration Date | Our Ownership | APR ¹ |
COPEL GeT | Main Transmission Concession(1) | 1,919 | 32 | Dec-42 | Main Transmission Concession(1) | 2,024 | 32 | December, 2042 | 100.0% | 473.9 |
COPEL GeT | TL Bateias - Jaguariaiva | 137 | - | Jul-31 | TL Bateias - Jaguariaiva | 137 | - | August, 2031 | 100.0% | 18.3 |
COPEL GeT | TL Bateias - Pilarzinho | 32 | - | Mar-38 | TL Bateias - Pilarzinho | 32 | - | March, 2038 | 100.0% | 1.0 |
COPEL GeT | TL Foz - Cascavel Oeste | 116 | - | Nov-39 | TL Foz - Cascavel Oeste | 116 | - | November, 2039 | 100.0% | 10.9 |
COPEL GeT | Cerquilho III Substation | - | 1 | Oct-40 | Cerquilho III Substation | - | 1 | October, 2040 | 100.0% | 4.5 |
COPEL GeT | TL Londrina – Figueira Foz do Chopim – Salto Osório | 102 | - | August, 2042 | 100.0% | 5.5 | ||||
COPEL GeT | TL Assis – Paraguaçu Paulista Paraguaçu Paulista II Substation | 83 | 1 | February, 2043 | 100.0% | 7.6 | ||||
COPEL GeT | Curitiba Norte Substation TL Bateias – Curitiba Norte | 31 | 1 | January, 2044 | 100.0% | 8.3 | ||||
COPEL GeT | Realeza Sul Substation TL Foz do Chopim- Realeza Sul | 52 | 1 | September, 2044 | 100.0% | 7.2 | ||||
COPEL GeT | TL Assis – Londrina | 122 | - | September, 2044 | 100.0% | 18.9 | ||||
Subtotal Copel GeT | 2,204 | 33 | - | Subtotal Copel GeT | 2,699 | 36 |
| 556.1 | ||
Costa Oeste | LT Cascavel Oeste - Umuarama Sul | 143 | 1 | Jan-42 | ||||||
Transmissora Sul Brasileira | Nova Sta Rita - Camaquã | 798 | 1 | May-42 | ||||||
Caiuá Transmissora | TL Guaíra - Umuarama Sul | 136 | 2 | May-42 | ||||||
Costa Oeste | LT Cascavel Oeste - Umuarama Sul | 152 | 1 | January, 2042 | 51.0%(2) | 5.5 | ||||
Transmissora Sul Brasileira | Nova Sta Rita - Camaquã | 785 | 1 | May, 2042 | 20.0%(2) | 11.5 | ||||
Caiuá Transmissora | TL Guaíra - Umuarama Sul | 136 | 2 | May, 2042 | 49.0%(2) | 9.5 | ||||
Integração Maranhense | LT Açailandia-Miranda II | 365 | - | May, 2042 | 49.0%(2) | 15.2 | ||||
Marumbi | LT Curitiba – Curitiba Leste | 29 | 1 | May, 2042 | 80.0%(2) | 13.5 | ||||
Matrinchã | TL Paranaíta - Ribeirãozinho | 1,005 | 3 | May, 2042 | 49.0%(2) | 92.8 | ||||
Guaraciaba | TL Ribeirãozinho - Marimbondo | 600 | 1 | May, 2042 | 49.0%(2) | 48.7 | ||||
Paranaíba | TL Barreiras II - Pirapora II | 953 | - | May, 2043 | 24.5%(2) | 30.1 | ||||
Cantareira | TL Estreito – Fernão Dias | 342 | - | September, 2044 | 49.0%(2) | 47.6 | ||||
Subtotal SPCs | 1,442 | 4 | 4,367 | 9 |
| 274.4 | ||||
Total | 3,616 | 37 | 7,066 | 45 |
| 830.5 |
(1) Our main transmission concessions encompasses several transmission lines.
(2)Refers to the equity interest held by Copel Geração e Transmissão.
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Expansion and Maintenance of Transmission Facilities
The construction of new transmission facilities of 230 kV and higher must be awarded in a bidding process or otherwise authorized by ANEEL. We are permitted by ANEEL to make minor improvements to some of the existing 230 kV and 500 kV facilities.
In June 2010, Copel won a public auction No. 001/2010 for the construction and operation of two facilities, both located in the State of São Paulo. The first is the transmission line Araraquara II - Taubaté which is a 356 km transmission line of 500 kV. WekV, located in the State of São Paulo. With an APR of R$29.0 million, the corresponding concession agreement was signed in May 2014 and we expect to complete the construction work of these facilities by March 2016.May 2018.
In December 2011, SPC Marumbi Transmissora, a strategic agreement between Copel (80%) and Eletrosul (20%) won an ANEEL auction for the construction and operation of 28 km of transmission lines and one substation in the State of Paraná. The start of operation of these assets is scheduled for April 2015.
In March 2012, Copel (49%), together with State Grid Brazil Holding (51%), through the SPC Matrinchã Transmissora and Guaraciaba Transmissora, won an ANEEL public auction for the construction and operation of 1,605 km of new transmission lines and four new substations that will transmit energy produced by five new hydroelectric plants that are planned to be constructed in TelesPires River, in the North of Mato Grosso State, to the Southeast region of Brazil. These lines and substations are scheduled to enter into operation in July 2015.
28
In June 2012, Copel won a public auction for the construction and operation of 98 km of transmission lines. The concession won by Copel is for the construction of 230 kV transmission lines that will link substations Londrina and Figueira (88km), located in northern Paraná, and Foz do Chopim and Salto Osório power plants (10 km), both located in southwest Paraná. Construction of these lines began in 2013. The transmission line Foz do Chopim - Salto Osório (10 km) started commercial operation on March 29, 2015. The transmission line Londrina - Figueira (88 km) is scheduled to become operational in May 2015.
In December 2012, a strategic agreement between Copel (24.5%), Furnas (24.5%) and State Grid Brazil Holding (51%), SPC Paranaíba Transmissora, won a public auction for the construction and operation of 967 km of transmission lines in the States of Goiás, Minas Gerais and Bahia. The corresponding concession agreement was signed in May 2013 and these transmission lines are scheduled to become operational in May 2016.
In the same public auction, Copel won the right to construct and operate 37 km of transmission lines in the State of São Paulo, between the municipalities of Assis and Paraguaçu Paulista. The corresponding concession agreement was signed in February 2013 and these transmission lines are scheduled to become operational in September 2015.
In November 2013, Copel won a ANEEL public auction for the construction and operation of 33 km of transmission lines and one substation in the State of Paraná. The corresponding concession agreement was signed in January 2014, and these transmission lines are scheduled to become operational in January 2016.
In the same auction, SPC Mata de Santa Genebra Transmissora, a strategic agreement between Copel (50.1%) and Furnas (49.9%), won the right to build and operate 847 km of transmission lines and three substations in the States of Paraná and São Paulo. TheWith an APR of R$113.9 million, the corresponding concession agreement was signed in May 2014, and these transmission lines are scheduled to become operational in October 2017.November 2018.
In May 2014,November 2015, Copel GeT won a ANEELANEEL’s public auction No. 005/2015 for the construction and operation of two lots of transmission lines, the first lot composed of 53 km of transmission lines and one substation in the State of Paraná and the second lot composed of 120230 km of transmission lines in the States of Paraná and São Paulo. The corresponding concession agreements were signed in September 2014Santa Catarina, and these facilities are scheduled to become operational in March and September 2017, respectively.
In the same public auction, a strategic agreement between Copel (49%) and Elecnor (51%) won the right to construct and operate 328 km of transmission linesthree substations in the StatesState of São Paulo and Minas Gerais. TheParaná, with a total capacity of 900 MVA. With an APR of R$108.6 million, the corresponding concession agreement was signed in September 2014,April 2016, and these transmission lines are scheduled to become operational part in September 2019 and part in March 2018.2021.
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The table below summarizes information regarding our transmission assets currently under construction:
Subsidiary / SPC | Transmission Lines | State | Km | Number of Substations | Our Ownership | Beginning of Operation (expected) | Transmission Lines | State | Km | Number of Substations | Our Ownership | Beginning of Operation (expected) |
COPEL GeT | TL Araraquara II — Taubaté | SP | 356 | - | 100% | Mar/2016 | TL Araraquara II — Taubaté | SP | 356 | - | 100.0% | May, 2018 |
COPEL GeT | TL Londrina - Figueira
| PR | 88 | - | 100% | May/2015 | TL Curitiba Leste-Blumenau TL Baixo Iguaçu-Realeza | PR/SC | 189 | 3 | 100.0% | April, 2021 |
COPEL GeT | TL Assis — Paraguaçu Paulista II Substation Paraguaçu Paulista II | SP | 37 | 1 | 100% | Sep/2015 | ||||||
COPEL GeT | TL Bateias - Curitiba Norte | PR | 33 | 1 | 100% | Jan/2016 | ||||||
COPEL GeT | TL Foz do Chopim - Realeza | PR | 53 | 1 | 100% | Mar/2017 | ||||||
COPEL GeT | TL Assis – Londrina | SP / PR | 120 | - | 100% | Sep/2017 | ||||||
Subtotal Copel Get |
| 697 | 3 |
| ||||||||
Marumbi | TL Curitiba - Curitiba Leste | PR | 28 | 1 | 80%
| Apr/2015 | ||||||
Matrinchã | TL Paranaíta - Ribeirãozinho | MT | 1.005 | 3 | 49%
| Jul/2015 | ||||||
Guaraciaba | TL Ribeirãozinho - Marimbondo | MT / GO / MG | 600 | 1 | 49%
| Jul/2015 | ||||||
Paranaíba | TL Barreiras II - Pirapora II | BA / MG / GO | 967 | - | 24,5% | May/2016 | ||||||
Subtotal Copel GeT | Subtotal Copel GeT |
| 545 | 3 |
|
| ||||||
Mata de Santa Genebra | TL Araraquara II - Bateias | SP / PR | 847 | 3 | 50,1% | Oct/2017 | TL Araraquara II - Bateias | SP / PR | 885 | 1 | 50.1% | November, 2018 |
Cantareira | TL Estreito - Fernão Dias | SP / MG | 328 | - | 49% | Mar/2018 | ||||||
Subtotal SPC |
|
| 3,775 | 8 |
|
|
|
| 885 | 1 |
|
|
Total |
|
| 4,472 | 11 |
|
|
|
| 1,430 | 4 |
|
|
Distribution
Our distribution system consists of a widespread network of overhead lines and substations with voltages up to 138 kV and a small portion of our 230 kV assets. Higher voltage electricity is supplied to bigger industrial and commercialcustomers and lower voltage electricity is supplied to residential, small industrial, and commercial customers andin addition to other customers. AtAs of December 31, 2014,2017, we provided electricity in a geographic area encompassing approximately 98% of the State of Paraná and served 4.34.6 million customers.
43
Our distribution grid includes 189,925.4196,951.2 km of distribution lines, 388,883424,923 distribution transformers and 230225 distribution substations of 34.5 kV, 35 substations of 69 kV and 96109 substations of 138 kV. During 2014, 145,4772017, 81,726 new captive customers were connected to our network, including customers connected through the rural and urban electrification programs. We are continuing to implement compact grid design distribution lines in urban areas where there is awith large concentration of trees in the vicinity of the distribution grid.
We have 287 (seven) captive customers that are directly supplied with energy at a high voltage (69 kV and above) through connections to our distribution lines. These customers accounted for approximately 2.9%0.9% of the total volume of electricity sold by Copel Distribuição or 1.5% of our total volume of electricity sold in 2014.2017.
We are also responsible for expanding the 138 kV and 69 kV distribution grid within our concession area.area to meet any future demand growth.
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Performance of the Distribution System Performance
We determineTotal losses are commonly divided into a technical and non-technical component. Technical losses are inherent to the energytransportation of electricity and consist mainly of power dissipation in the line network. Non-technical (or commercial) losses are caused by actions external to the power system (for instance, electricity theft). Since total losses are comprised of both technical and non-technical parcels, the latter is easily calculated as the difference between total losses and the estimated technical losses inherent to the system.
Total losses in our distribution system separately from those ofare segmented between (i) losses in the basic network (tension equal to or greater than 230kV), which are external to our transmission system.distribution grid and have a technical cause, and (ii) losses in the distribution network (internal to our distribution grid), which are usually caused by both technical and non-technical reasons.
Losses in the basic network are calculated monthly by the CCEE as the diference between the total generation and the energy effectively delivered to the distribution networks. The total losses from our distribution grid are calculated by takingas the difference between the energy allocated to the system and the energy supplied to the customers.
Our total energy distribution losses (including transmission system, technical and commercial losses) totaled 12.1%9.2% of ourthe total energy amount available energy in 2014, and include our distribution business’ share of2017, being (i) 1.4% related to losses fromin the basic transmission grid (whichnetwork, (ii) 6.1% of technical losses and (iii) 1.7% of non-technical losses.
The Regulatory Agency grants the transfer of all energy losses to the final consumers when the real losses are allocated betweenless than regulatory losses. The calculation is made within the regulatory period, that is different from a civil year, and thereby we will know the result just in the next tariff adjustment, in June 2018. But our distributionsimulation indicates that in the civil year, from January until December 2017, we will have all losses transferred to the final consumers.
Furthermore, ANEEL requires distributors to observe certain standards for “energy supply continuity”, namely (i) duration of outages per customer per year or DEC –Duração Equivalente de Interrupção por Unidade Consumidora and transmission businesses)(ii) frequency of outages per customer per year or FEC –Frequência Equivalente de Interrupção por Unidade Consumidora.
Information regarding the duration and frequency of outages for our customers is set forth in the following chart for the years indicated.
|
| ||||
Quality of supply indicator | 2014 | 2013 | 2012 | 2011 | 2010 |
DEC – Duration of outages per customer per year (in hours) | 14h06min | 11h37min | 10h15min | 10h38min | 11h28min |
FEC – Frequency of outages per customer per year (number of outages) | 9.08 | 8.06 | 7.84 | 8.26 | 9.46 |
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|
| ||||
Quality of supply indicator | 2017 | 2016 | 2015 | 2014 | 2013 |
DEC – Duration of outages per customer per year (in hours) | 10h28min | 10h49min | 13h40min | 14h01min | 11h37min |
FEC – Frequency of outages per customer per year (number of outages) | 6.83 | 7.23 | 8.33 | 9.08 | 8.06 |
We outperformedcomply with the quality target indicator establishedindicators defined by ANEEL for 2014,2017, which penalize power outages in excess of an average frequency of outages and we underperformed the quality target indicator established by ANEEL for 2014 which penalizepenalizes power outages in excess of an average number of hours per customer, in each case calculated on an annual basis. These limits vary depending on the geographic region, and the average limit established by ANEEL for our distribution company was 12 hours and 1454 minutes of outages per customer per year, and a total of 10.028.74 outages per customer per year. Failure to comply with these predetermined standards with a final customerFinal Customer results in a reduction of the amount we can charge such final customersFinal Customer in future periods.
In addition, quality target indicators are taken into consideration by ANEEL during distribution concession renewal proceedings, and also influence ANEEL’s calculation of our tariff adjustments. For more information, see “Distribution Concessions” and “Distribution Tariffs”.
Purchases
The following table contains information concerning volume, costscost and average tariffstariff for the main sources of the electricity we purchased in the last three years.
Source | 2014 | 2013 | 2012 | 2017 | 2016 | 2015 |
Itaipu |
|
|
|
|
|
|
Volume (GWh) | 5,870 | 5,193 | 5,256 | |||
Volume (GWh) | 5,934 | 5,958 | 5,941 | |||
Cost (R$ millions) | 1,118.0 | 1,089.9 | 1,567.8 | |||
Average tariff (R$/MWh) | 188.41 | 182.91 | 263.89 | |||
Angra |
|
| ||||
Volume (GWh) | 1,023 | 1,026 | 1,051 | |||
Cost (R$ millions) | 231.7 | 227.0 | 178.2 | |||
Average tariff (R$/MWh) | 226.49 | 221.25 | 169.55 | |||
CCGF |
|
| ||||
Volume (GWh) | 7,271 | 7,553 | 3,873 | |||
Cost (R$ millions) | 756.1 | 610.4 | 503.3 | 447,5 | 499,9 | 132,1 |
Average tariff (R$/MWh) | 128.81 | 117.54 | 95.76 | |||
Angra |
|
|
| |||
Volume (GWh) | 1,046 | 1,050 | - | |||
Cost (R$ millions) | 156.2 | 142.5 | - | |||
Average tariff (R$/MWh) | 149.31 | 135.67 | - | |||
CCGF |
|
| ||||
Volume (GWh) | 1,315 | 1,272 | - | |||
Cost (R$ millions) | 42.5 | 40.8 | - | |||
Average tariff (R$/MWh) | 32.34 | 32.07 | - | |||
Auctions in the regulated market |
|
| ||||
Volume (GWh) | 16,281 | 15,645 | 19,003 | |||
Cost (R$ millions)(2) | 3,394.2 | 2,305.8 | 1,927.9 | |||
Average tariff (R$/MWh) | 208.48 | 147.38 | 101.45 | |||
Average tariff (R$/MWh) | 61.55 | 66.19 | 34.11 |
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Auctions in the regulated market |
|
|
|
Volume (GWh)(1) | 9,860 | 13,387 | 15,722 |
Cost (R$ millions)(2) | 2,014.8 | 2,493.6 | 3,502.2 |
Average tariff (R$/MWh) | 204.34 | 186.27 | 222.76 |
(1) PriorThese numbers do not include assignments related to 2013, purchases from Angra were made through auctions in the regulated market.Mechanism for Compensation of Surpluses and Deficits of New Energy (Mecanismo de Compensação de Sobras e Déficits de Energia Nova - MCSD-EN).
(2) These numbers do not include short-term energy purchased through the Electric Energy Trading Chamber ‒ CCEE.
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Itaipu
We purchased 5,8705,934 GWh of electricity from Itaipu in 2014,2017, which constituted 20.4%11.4% of our total available electricity in 20142017 and 10.9%22.8% of Copel Distribuição’s total available electricity in 2014.2017. Our purchases represented approximately 9.1%7.2% of Itaipu’s total production. Distribution companies operating under concessions in the Midwest, Southmidwest, south and Southeastsoutheast regions of Brazil are required by law to purchase Brazil’s portion of the energy generated by Itaipu in a proportion that correlates with the volume of electricity that they provide to customers. The rates at which these companies are required to purchase Itaipu’s energy are fixed to cover Itaipu’s operating expenses and payments of principal and interest on Itaipu’s U.S. dollar-denominated borrowings, as well as the cost of transmitting the power to their concession areas. These rates are denominated in U.S. dollars, and have been set for 20152018 at US$38.0727.87 per kW per month.
In 2014,2017, we paid an average tariff of R$125.49 per 188.41/MWh for energy from Itaipu, compared to R$117.5 per 182.91/MWh during 2013.in 2016. These figures do not include the transmission tariff that distribution companies must pay for the transmission of energy from Itaipu.
ANGRA
Because Eletronuclear renewed the generation concession of Angra under the 2013 Concession Renewal Law, the energy generated by Angra is no longer sold in auctions in the regulated market. Rather, under the 2013 Concession Renewal Law, this energy is sold to distributors in accordance with the quota system established by that law, such thatsaid law. For more information, see “Item 4.Information on the Company-The Brazilian Electric Power Industry”. As a result, Copel Distribuição was obligatedlegally required to purchase 1,0461,023 GWh from Angra in 2014 and 1,0502017, 1,026 GWh in 2013.2016 and 1,051 GWh in 2015.
Assured Power Quota Contract – CCGF
Under the 2013 Concession Renewal Law, certain generation concessionaires renewed their concession contracts, and therefore these concessionaires no longer sell the energy produced by these generation facilities inat auctions in the regulated market. Rather, this energy is sold to distribution companies in accordance with the quota system established by the 2013 Concession Renewal Law. For more information, see “item“Item 4.Information on the Company -The Brazilian Electric Power Industry”. Copel Distribuição is obligated to purchase energy from these generation concessionaires that have renewed generation concessions under this quota system. As a result, Copel Distribução was obligatedlegally required to purchase 1,3157,271 GWh in CCGF contracts in 2014 and 1,2722017, 7,553 GWh in 2013.2016 and 3,873 GWh in 2015.
Auctions in the Regulated Market
In 2014,2017, we purchased 16,6929,860 GWh of thermoelectric and hydroelectric energy through auctions in the regulated market. This energy represents 67.0%38.0% of the total electricity we purchased. For more information on the regulated market and the free market, see “The Brazilian Electric Power Industry—The New Industry Model Law”.
Sales to Final Customers
During 2014,2017, we supplied approximately 97% of the energy distributed directly to captive customersCaptive Customers in the State of Paraná. Our concession area includes 4.34.6 million customers located in the State of Paraná and in one municipality in the State of Santa Catarina, located south of the State of Paraná. We also sold energy to a total of 29 (twenty-nine)one hundred, ninety-one (191) Free Customers, 4 (four)fifty-nine (59) of which were located outside of our concession area. During 2014,2017, the total power consumption of our captive customersCaptive Customers and Free Customers was 28,22424,374 GWh, a 4.5% increase6.8% decrease as compared to 27,00826,151 GWh during 2013.2016. The following table sets forth information regarding our volumes of energy sold to different categories of purchasers for the periods indicated.
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| Year ended December 31, | Year ended December 31, | ||||||||
Categories of purchaser | 2014 | 2013 | 2012 | 2011 | 2010 | 2017 | 2016 | 2015 | 2014 | 2013 |
| (GWh) | (GWh) | ||||||||
Industrial customers | 10,841 | 10,675 | 8,799 | 8,377 | 8,146 | 7,689 | 9,574 | 10,823 | 10,841 | 10,675 |
Residential | 7,267 | 6,888 | 6,559 | 6,224 | 5,925 | 7,126 | 6,932 | 6,957 | 7,267 | 6,888 |
Commercial | 5,482 | 5,086 | 5,058 | 4,778 | 4,466 | 4,847 | 5,061 | 5,542 | 5,482 | 5,086 |
Rural | 2,252 | 2,081 | 2,025 | 1,872 | 1,774 | 2,257 | 2,180 | 2,256 | 2,252 | 2,081 |
Other(1) | 2,382 | 2,279 | 2,211 | 2,122 | 2,048 | 2,455 | 2,404 | 2,371 | 2,382 | 2,279 |
Total(2) | 28,224 | 27,008 | 24,652 | 23,373 | 22,359 | 24,374 | 26,151 | 27,949 | 28,224 | 27,008 |
(1) Includes public services such as street lighting, electricity supply for municipalities and other governmental agencies, as well as our own consumption.
(2) Total GWh does not include our energy losses.
The following table sets forth the number of our Final Customers in each category atas of December 31, 2014.
2017.
Category | Number of Final Customers |
Industrial |
|
Residential |
|
Commercial |
|
Rural |
|
Other |
|
Total |
|
(1) Includes street lighting, as well as electricity for municipalities and other governmental agencies, public services and own consumption.
Industrial and commercial customers accounted for approximately 31%31.8% and 21%19.3%, respectively, of our total net revenues from sales to final customersFinal Customers during 2014.2017. In 2014, 35%2017, 29.5% of our total net revenues from energy sales were from sales to residential customers.
Tariffs
Retail Tariffs.We classify our customers in two groups (“Group A Customers” and “Group B Customers”), based on the voltage level at which electricity is supplied to them and on whether they are considered as industrial, commercial, residential or rural customers. Each customer falls within a certain tariff level defined by law and based on the customer’s classification, although some flexibility is available according to the nature of each customer’s demand. Under Brazilian regulation, low voltage customers such as residential customers (other than Low IncomeLow-income Residential Customers, as defined below)as follows) pay the highest tariff rates, followed by 13.8 kV and 34.5 kV voltage customers usually(usually commercial customerscustomers), and 69 kV and 138 kV voltage customers usually(usually industrial customers.customers).
Group A Customers receive electricity at 2.3 kV or higher and the tariffs applied to them are based on the actual voltage level at which energy is supplied and the time of day the energy is supplied. Tariffs are comprised of two components: a “capacity charge” and an “energy charge”. The capacity charge, expressed inreaisper kW, is based on the higher of (i) contracted firm capacity and (ii) powercapacity actually used. The energy charge, expressed inreaisper MWh, is based on the amount of electricity actually consumed as evidenced by our metering.
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Group B Customers receive electricity at less than 2.3 kV, and the tariffs applied to them are comprised solely of an energy charge and are based on the classification of the customer.
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ANEEL restates our tariffs annually, generallyusually in June. For more information about the distribution tariff adjustments that have been made by ANEEL in recent years, see “Item 5. Operating and Financial Review and Prospects—Overview—Rates and Prices”.
The following table sets forth the average tariffs for each category of Final Customerfinal customer in effect in 2014, 20132017, 2016 and 2012.2015.
Tariffs | 2014 | 2013 | 2012 | 2017 | 2016 | 2015 | |
| (R$/MWh) | (R$/MWh) |
| ||||
Industrial | 236.35 | 202.68 | 220.00 | 389.04 | 398.35 | 369.91 | |
Residential | 292.99 | 257.92 | 293.62 | 425.26 | 459.35 | 434.82 | |
Commercial | 269.00 | 234.05 | 265.67 | 419.27 | 439.47 | 407.17 | |
Rural | 178.48 | 157.28 | 178.04 | 286.96 | 302.47 | 272.10 | |
Other customers | 208.73 | 180.89 | 206.89 | 311.37 | 331.85 | 316.56 | |
All Final Customers | 252.63 | 219.94 | 245.80 | 387.90 | 410.08 | 382.82 | |
Low IncomeLow-income Residential Customers. Under Brazilian law, we are required to provide discountedlow level rates to certain low incomelow-income residential customers (“Low IncomeLow-income Residential Customers”). In 2014,December 2017, we served about 408,251 low incomeapproximately 290,371 low-income residential customers. For servicing these customers, in 20142017 we received aan approximately R$69.577 million grant from the Brazilian Federal Government, which was approved by ANEEL, from the Brazilian Federal Government.ANEEL.
The following table sets forth the current minimum discount rates approved by ANEEL for each category of Low IncomeLow-income Residential Customer.
Consumption | Discount from base tariff |
Up to 30 kWh per month | 65% |
From 31 to 100 kWh per month | 40% |
From 101 to 220 kWh per month | 10% |
Special Customers.A customer of our distribution business that consumes at least 500 kV (a “Special Customer”) may choose its energy supplier if that supplier derives its energy from alternative sources, such as small hydroelectric plants, wind plants or biomass plants. A Special Customer that chooses to purchase energy from a supplier other than Copel Geração e Transmissão continues to use our distribution grid and pay our distribution tariff. However, as an incentive for Special Customers to purchase from alternative sources, we are required to reduce the tariff paid by Special Customers by 50%. This discount is subsidized by the Brazilian federal government, and therefore does not impact the revenues of our distribution business.
Transmission Tariffs. A transmission concessionaire is entitled to annual revenues based on the transmission network it owns and operates. These revenues are annually readjusted according to criteria stipulated in the concession contract. We are directly a party to eleventwelve transmission concession contracts, fiveten of which are in the operational stage and sixtwo of which are inunder construction. Not all of the transmission concession contracts employ the same revenue model. 9.1%2.4% of our transmission revenues arerevenuesare updated on an annual basis by the IGP-M and the other 90.9%97.6% are subject to the tariff review process.
Of all our transmission concessions in operational stage, our main transmission concession (which involves our main transmission facilities) accounted for about 82.6% of our gross transmission revenues in 2014.
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The first periodic revision related to our main transmission concession scheduled for 2005 was only carried out in 2007, at which point ANEEL reduced the tariffs by 15.08%. This adjustment was applied retroactively to July 2005, and was passed on to our Final Customersfinal customers until June 2009. In addition, in July 2010 pursuant to a second periodic revision of our principal concession, ANEEL granted provisional approval of a reduction in our transmission tariff by 22.88%, applied to the revenues of new installations in the Interconnected Transmission System, and applied retroactively from July 1, 2009 onward. In June 2011, ANEEL reviewed the figures of the second periodic revision and reduced the annual revenues by 19.94%. The remainder of our annual revenues was subject to adjustment by IGP-M or IPCA, as applicable.
By late 2012, Copel decided to anticipate the extension of its main transmission concession agreement (corresponding to 87%78% of the Company’s transmission lines then in operation) that would expire in 2015, pursuant to the new rules of the 2013 Concession Renewal Law. OnIn December 2012, Copel executed the Third Addendum to the Concession Agreement 060/2001, extending this transmission concession agreement until December 31, 2042. In order to adjust these assets’ annual permitted revenue to the new rules of 2013 Concession Renewal Law, ANEEL reduced the transmission tariffs we charged by 38.0%61.9%.
Of all our transmission concessions in operational stage, our main transmission concession (which involves our main transmission facilities) accounted for about 85.2% of our gross transmission revenues in 2017.
In addition, we have other 4 (four)9 (nine) concession agreements for transmission lines and substations in operation, which correspond to an aggregate of 17.4%14.8% of our transmission revenues. The amount of revenues we are entitled to receive pursuant to one of these contracts is updated on an annual basis by the IGP-M and is not subject to the tariff review process. However, this amount will be reduced by 50% from the 16th year forward, as of 2016.2018. Other threeeight agreements revenues are subject to the tariff review process and adjustments by the IPCA.
In 2013, our main transmission concession agreement was adjusted by the IPCA, and improvements to the system were approved by ANEEL (increase of 8.9%). Out of the other three transmission concession agreements that were operational in 2013, one was adjusted by the IPCA (increase of 6.5%), another by the IGP-M (increase of 6.2%), and the last one had a first tariff review (decrease of 8.9%). As a result, the annual permitted revenues for the 2013/2014 cycle for our transmission assets reflected an 8.4% net increase over our annual permitted revenues following the renewal of our main transmission concession in 2012.
In 2014, (i) two of our transmission concession agreements (including our main transmission concession agreement), were adjusted by the IPCA and improvements to the system were approved by ANEEL (average increase of 18.2%), (ii) one was adjusted by the IPCA (6.4%), (iii) another one was adjusted by the IGP-M (7.8%) and (iv) one became operational on July 28, 2014, adding R$4.2 million to our annual permitted revenues. As a result, the annual permitted revenues for the 2014/2015 cycle for our transmission assets reflects an increase of 19.9% over our annual permitted revenues for the 2013/2014 cycle.
In 2015, (i) two of our transmission concession agreements (including our main transmission concession agreement), were adjusted by the IPCA and improvements to the system were approved by ANEEL (average increase of 15.6%), (ii) three transmission concession agreements were adjusted by the IPCA (8.5%), (iii) one transmission concession agreement was adjusted by the IGP-M (4.1%), and (iv)two transmission agreements became operational on June 28, 2015 and January 25, 2016, adding R$12.1 million of annual permitted revenues. As a result, the annual permitted revenues for the 2015/2016 cycle for our transmission assets reflects an increase of 21.0% over our annual permitted revenues for the 2014/2015 cycle.
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In 2016, (i) four of our transmission concession agreements (including our main transmission concession agreement), were adjusted by the IPCA and improvements to the system were approved by ANEEL (average increase of 9.5%), (ii) two transmission concession agreements were adjusted by the IPCA (9.3%), (iii) one transmission concession agreement was adjusted by the IGP-M (11.1%), and (iv) two transmission agreement became operational on May 16, 2016, and on January 15, 2017, adding R$15.4 million of annual permitted revenues. As a result, the annual permitted revenues for the 2016/2017 cycle for our transmission assets reflects an increase of 16.7% over our annual permitted revenues for the 2015/2016 cycle.
In relation to our main concession agreement, on April 22, 2016, Ordinance no. 120/2016 of the Ministry of Mines and Energy determined that the amounts ratified by ANEEL related to the non-depreciated transmission assets existing on May 31, 2000 (RBSE) should be incorporated to the Regulatory Remuneration Base, and that their cost of capital should be added to APR. The Ordinance also determined that the cost of capital would be composed of compensation and depreciation installments, plus related taxes, and recognized as of the 2017 tariff revision process, with adjustments and revisions in accordance with contractual conditions.
Also pursuant to the Ordinance, the cost of capital not incorporated between the concessions’ extensions and the 2017 tariff revision process should be restated at the real cost of own capital of the transmission segment defined by ANEEL (10.4%) and, after the tariff revision process, it should be remunerated at the Weighted Average Cost of Capital (WACC) of 6.6%, also defined by that agency.
On May 9, 2017, ANEEL approved the result of the inspection of the appraisal report of the transmission assets existing on May 31, 2000 (Existing Basic Network System - RBSE and Other Transmission Facilities - RPC) related to our main transmission concession agreement. The Agency recognized the amount of R$667.6 million as the net value of the assets for the purposes of indemnification as of December 31, 2012. As of December 31, 2017, the net value of those assets for the purposes of indemnification amounted to R$ 1,418.4 million.
On June 27, 2017, ANEEL approved the Annual Permitted Revenue (APR) of the transmission assets of Copel Geração e Transmissão for the 2017/2018 cycle, including the commencement of receipt of the RBSE indemnification of our main transmission concession agreement.
In 2017, (i) our main transmission concession agreement was adjusted by the IPCA and by the portion related the commencement of receipt of the RBSE indemnification (average increase of 151.3%) (ii) one of our transmission concession agreements was adjusted by the IPCA and improvements to the system were approved by ANEEL (average increase of 3.7%), (iii) six transmission concession agreements were adjusted by the IPCA (3.6%), (iv) one transmission concession agreement was adjusted by the IGP-M (1.6%), and (v) one transmission agreement became operational on August 2017, adding R$18.9 million of annual permitted revenues. As a result, the annual permitted revenues for the 2017/2018 cycle for our transmission assets reflects an increase of 121.2% over our annual permitted revenues for the 2016/2017 cycle.
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The table belowas follows shows our RAPAPR (R$ million) for the last four cycles of transmission lines over which we hold ana 100% ownership:
Contract | Transmission Line / Substation | Jul.2014 Jun.2015 | Jul.2013 Jun.2014 | Jan.2013 Jun.2013 | Jul.2012 Dec.2012 | Transmission Line / Substation | Jul. 2017 Jun. 2018 | Jul.2016 Jun.2017 | Jul.2015 Jun.2016 | Jul.2014 Jun.2015 |
|
| Annual Permitted Revenues (R$ million) |
|
| APR (R$ million) | |||||
060/2001 | Main Transmission Concession(1) | 150.1 | 126.4 | 116.1 | 304.8 | Main Transmission Concession(1) | 482.7 | 192.1 | 174.9 | 150.1 |
075/2001 | Bateias – Jaguariaiva | 16.5 | 15.3 | 14.4 | Bateias – Jaguariaiva | 19.4 | 19.1 | 17.2 | 16.5 | |
006/2008 | Bateias – Pilarzinho | 0.9 | 0.8 | 0.9 | Bateias – Pilarzinho | 1.0 | 1.0 | 0.9 | 0.9 | |
027/2009 | Foz do Iguaçu - Cascavel Oeste | 10.1 | 9.1 | 8.5 | Foz do Iguaçu - Cascavel Oeste | 11.6 | 11.2 | 10.2 | 10.1 | |
015/2010 | Cerquilho III | 4.2 | - | Cerquilho III | 4.7 | 4.5 | 4.6 | 4.2 | ||
022/2012 | Foz do Chopim – Salto Osório | 5.8 | 5.6 | 5.1 | 1.1 | |||||
002/2013 | Assis-Paraguaçu Paulista II SE Paraguaçu Paulista II | 7.7 | 7.7 | 7.0 | - | |||||
005/2014 | Bateias – Curitiba Norte | 8.7 | 8.4 | - | - | |||||
021/2014 | Foz do Chopim - Realeza(2) | 7.3 | 7.1 | - | - | |||||
022/2014 | Assis – Londrina(3) | 18.9 | - | - | ||||||
Total |
| 181.8 | 151.6 | 139.9 | 328.6 |
| 567.8 | 256.7 | 219.9 | 182.9 |
(1) Our main transmission concessions encompassesencompasse several transmission lines.
(2) This transmission line became operational in January, 2017.
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Table of Contents(3) This transmission line became operational in August, 2017.
Other Businesses
Telecommunications
Copel Telecomunicações S.A. Pursuant to an authorization from the Brazilian National Telecommunication Agency,Agência Nacional de Telecomunicações(“ANATEL”), we provide telecommunication services within the States of Paraná and Santa Caratina.Catarina. We have been offering these services since August 1998 through the use of our fiber optics network (totaling 25,425 thousand31,117 km of fiber optic cables by the end of 2014)2017). In 2014, we served the 399 municipalities in the State of Paraná and two additional municipalities in the State of Santa Catarina (attending a total number of 21,761 clients) andaddition we have also been involved in an educational project aimed at providing public elementary and middle schools in the State of Paraná with broadband internet access.
COPEL currently serves 399 municipalities in the State of Paraná and 2 additional municipalities in the State of Santa Catarina. All of these municipalities are connected to COPEL’s optical backbone that uses DWDM (Dense Wavelength Division Multiplexing) technology, allowing transmission rates up to 40 channels of 200Gbit/s per optical fiber.
In addition to the high transmission capacity in its backbone, Copel Telecom serves 64 municipalities in the State of Paraná, with GPON (Gigabit-Capable Passive Optical Networks) access technology, providing several network services with symmetry rates, in different types of FTTx services. GPON technology allows optimization of the installed infrastructure and the use of FTTH (Fiber to the Home), FTTO (Fiber to the Office), FTTB (Fiber to the Building) and FTTA (Fiber to the Apartment), with high transmission rates, quality and reliability.
With approximately 5,000 km in FTTx network, COPEL covers a total of 870 thousand homepassed. In 2017, the number of subscribers increased 34% in relation to 2016.
We provide services to most of the major Brazilian telecommunication companies that operate in the State of Paraná. In total, we have 21,761 clients (4,227 corporate clients whichthat include supermarket,supermarkets, universities, banks,internet service providers and television network and 17,534networks in addition to retail clients).clients. We also provide a number of different telecommunication services to our subsidiaries.
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Sercomtel.We own 45.0%45% of the stock of Sercomtel Telecomunicações S.A. (“Sercomtel”). Sercomtel holdshold concessions to provide fixed and mobile telephone services in the municipalities of Londrina and Tamarana in the State of Paraná and has obtained ANATEL’s authorization to provide telephone services to all other cities in the State of Paraná. Currently, Sercomtel operates under an authorization regime with its own network in 11 (eleven)fifteen (15) cities ofin the State of Paraná., providing voice services and fixed broadband. Through an alliance with us,a commercial agreement between COPEL and Sercomtel in force since March 2012, Sercomtel has been providing telephonevoice services over COPEL’s network to other 63 (sixty-three)another one hundred and eighty one (181) cities within the State of Paraná, including Curitiba. Sercomtel has concessions from ANATEL to provide cable television in São José in the State of Santa Catarina and Osasco in the State of São Paulo and radio-wave television transmission in Maringá in the State of Paraná.
As of December 31, 2014,2017, Sercomtel provided a total of 252,966 accesses in its concessions area for fixed telephone services, had a total of 202,423 telephone lines installed, of which 166,358 were68,217 mobile accesses and 115.467 fixed broadband accesses in operation. As
In addition to the telecommunications business, Sercomtel currently holds 100% of December 31, 2014,the capital stock of three subsidiaries: (i) Sercomtel Participações, a company whose purpose is to provide added value services, design, deploy and maintain internet service providers, operate a service center for users of telecommunications services, offer integrated IT solutions, among others (ii) Sercomtel Contact Center, a company whose purpose is to operate call centers, develop and implement CRM - Customer Relation Management projects, provide customer service and relationship services, among others, and (iii) Sercomtel Illumination, that provides maintenance services in public lighting in the city of Londrina, State of Paraná.
Sercomtel has had an installed capacitylosses in previous years and is facing financial difficulties for carrying out its operations, so it may need additional financial contributions from its shareholders.
In September 2017, pursuant to the Decision (Acórdão) no. 366, National Telecommunications Agency (Agência Nacional de Telecomunicações - ANATEL) determined that a new administrative proceeding should be initiated to assess whether the concession granted to Sercomtel S.A. Telecomunicações for providing the Fixed Switched Telephone Service (STFC) should expire.
In view of 85,000 terminalsthe accumulated losses and uncertainties regarding its operational feasibility, we carried out in 2013 the write-off of this investment in its Global System for Mobil Communications GSM system, of which 32,585 were in operation. In December 2009, Sercomtel started providing 3G services with a capacity of 20,000 lines, of which 19,937 are currently installed. Sercomtel 2014 net revenues were R$145.4 million, with net income of R$7.1 million.financial statements.
Water and Sewage
In January 2008, Copel bought thea 30% stake in Dominó Holdings S.A. (“Dominó Holdings”) held by Sanedo Ltda., a wholly-owned subsidiary of Grupo Veola, for R$110.2 million.
In March 2014, we have completed a corporate restructuring ofrestructured our equity interest in Dominó Holdings and its subsidiary Companhia de Saneamento do Paraná– Sanepar (“Sanepar”), a public utility company that provides 345 urban and rural municipalities and approximately 10.411 million people in the State of Paraná, with water distribution services and 6.7approximately 7.7 million with sewage services.
Upon the completion of this restructuring, Daleth Participações S.A. no longer holds anyIn December 2016, Dominó Holdings’s equity and we now directly hold (i)14.86%Holdings converted 41,000,000 of Sanepar’s voting shares into 41,000,000 preferred shares and tagged along Sanepar’s initial and secondary public offering at the pricing of R$9.50 per share. Dominó Holdings had its Sanepar’s voting shares reduced to 16,237,359 shares, or 7.63% of its total9.7% voting capital and (ii) 49.0%3.2% of Sanepar’s total capital.
On March 13, 2017, at the total outstanding share capitalExtraordinary General Meeting, the shareholders of Dominó Holdings while Andrade Gutierrez Concessões holds(49.0% Copel Comercialização SA) authorized the remaining 51%.reduction of the Company's capital stock without the cancellation of shares, upon delivery of all 16,237,359 Common shares issued by Sanepar, owned by Dominó Holdings, remainsin the proportion of its stake. As a result, Copel Comercialização became the direct owner of 7,956,306 common shares of Sanepar, valued by equity value of R$73.4 million. As a result, Copel had a stake, at the time, a total of 7,956,306 common shares and 36,343,267 preferred shares of Sanepar.
In November 2017, as shareholders of Sanepar, COPEL and Copel Comercialização adhered to the Units Issuance Program approved by Sanepar’s shareholders in the General Meeting held in October 2017 and each combined their shares to create 5,251,954 and 1,149,763 units, respectively.
In December 2017, both Copel and Copel Comercialização sold their Units in a secondary publicoffering, with 24.7%the establishment of the voting stock or 12.2%price of the total capitalR$55.20 per Unit, totalizing R$489.1 million. As a result of Sanepar. Considering the interest held through Dominó Holdings, COPEL’s directsuch transaction, Copel currently holds only two preferred shares issued by Sanepar, and indirect interest in Sanepar represents 13.58% of itsCopel Comercialização currently holds only one common share capital. The State of Paraná owns 75.0% of the outstanding voting or 51.4% of the total capital of Sanepar.
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Gas
Gas Distribution
We are engaged in the distribution of natural gas through Companhia Paranaense de Gás (“Compagas”), the company that holds the exclusive rights to supply piped gas in the State of Paraná. Compagas operates the gas distribution grid in the State of Paraná, which under a concession agreement with a term of 30 years, and may be extended for an equal period upon request of the Concessionaire. The concession agreement setting July 6, 2024 as the expiry date of the concession. Such date has always been announced and considered for assessment of the balances of the prior-year financial statements.
On December 7, 2017, the State of Paraná published Supplementary Law 205, introducing a new interpretation of the expiry of the concession, understanding that expiry will be on January 20, 2019.
The management board of Compagás, we and other shareholders are looking into and challenging the effects of the aforesaid law, understanding that they conflict with the provisions of the concession agreement currently in force. However such discussion has not yet been closed and that law continues in force, and the effects on the financial statements for 2017 had to be taken into consideration.
Management will continue to make its best efforts to protect the Company interests, aiming to appropriately settle the impacts of the new interpretation given by the Concession Grantor and find alternatives necessary to maintain the concession in a sustainable manner. For more information see Note 2.1.1 to our audited consolidated financial statements.
Compagas covered 726812 kilometers in 2014,2017, an increase of 12.8%1.5% compared to 646800 kilometers covered in 2013. In 2014,2016. Compagas’s net revenues were R$1,664.6515.6 million, an increasea decrease of 336%5.0%, compared to 2013,2016, and its net income was R$60.4114.0 million, an increase of 226%R$109 million or 2,201.6% compared to 2013. Compagas’s2016. Compagas’ customers include thermoelectric plants, cogeneration plants,industries, gas stations, other businesses and residences.residences and Araucária Thermoelectric plan. Compagas is focusing its business strategy on increasing the volume of gas it distributes to customers by marketing the benefits of substituting gas for oil and other fuels by gas as a meansmean of achieving greater energy efficiency. Compagas’ customer base increased 24%9.9%, to 26,05239,377 customers in 20142017 from 21,01836,189 in 2013.2016.
Compagas recorded an increaseregistered a decrease of 2%8.1% in the average daily volume of natural gas distributed to final customers,Final Customers, to 1,058,6971,156,657 cubic meters per day in 20142017 (not including the volume of gas supplied to UEG Araucária Thermal Power Plant) from 1,042,124Thermoelectric plant) compared to 1,259,138 cubic meters per day in 2013.2016 (not including the volume of gas supplied to Araucária Thermoelectric plant). In addition, Compagas makes available its distribution grid to transport natural gas to UEG Araucária.ria TPP. In 2014,2017, Petrobras S.A. delivered 636.742 million cubic meters of gas to UEG Araucária TPP, compared to 477.615,4 million cubic meters in 2013.2016.
As of December 31, 2014,2017, we owned 51.0%a controlling stake (51%) of the capital stock of Compagas and accounted forconsolidated this equity interest through consolidation, since we control this company.in our financial statements. The minority shareholders of Compagas are Petrobras and Mitsui Gás, each of which owns 24.5% of the capital stock of Compagas.
Gas Exploration
On November 28,In the 12th bidding round of ANP (Agência Nacional do Petróleo), held at the end of 2013, the National Petroleum, Natural Gas and Biofuels Agency announced that the consortium composed of Copelformed by us (30%), Bayar Participações (30%), Tucumann Engenharia (10%), Bayar Participações (30%) and Petra Energia (30%), the latter acting as operating company, won the right to explore, research, develop and produce oil and natural gas in four blocks located in the central-southcentral southern region of the State of Paraná (Paraná Basin), an area of 11,297in a 11,327 km², equivalent to 7% area. The minimum investment in the first phase of the total auctioned area. The consortium offered a signing bonus ofresearch is approximately R$12.578.1 million for a 4-year term. We and our partners have signed the concession contracts for 2 blocks in May 2014. However, the first phase of exploration for these fourtwo blocks was halted due to public civil action and, on June 7th, 2017, a minimum exploratory program, which envisages investments of R$78.1 million. This concession has a term of four years fromcourt decision held that both the executionbidding round and the agreements related thereto should be deemed null and void. Moreover, the Government of the agreement and may be extendedState of Paraná enacted Law No. 18,947 (December 22, 2016), suspending for 2ten years totaling six years.the exploration of shale gas through the drilling / fracking method. The operatorsuspension is intended to prevent environmental damage.
As a result of the consortium will be Petra Energia. The acquisition of these blocks are in accordance with Copel’s strategies, and allows the access to gas production, which may be used in thermal generation plants to be constructed alongside the gas wells. As of April 28, 2015,above-mentioned events, our consortium has only executed concession agreements for two of these blocksrequested ANP to release it from its contractual obligations, with no liabilities and no exploratory program has been initiated.
Services
We own 40.0%with reimbursement of the share capitalsigning bonuses, reimbursement of Escoelectric Ltda. (“ESCO”)all costs incurred in connection with guarantees and release of such guarantees. Even though this request was submitted to ANP on September 6th, a company that assists customers with their electricity needs through the provision of consulting services, planning and project implementation, automation services, operation, maintenance, training and technical assistance. TheInstituto de Tecnologia para o Desenvolvimento – LACTEC owns the remaining 60.0% of the share capital. ESCO also markets products and services aimed at obtaining greater energy efficiency and energy conservation. All operations of this company were discontinued in 2008, and we plan2017, it is still subject to liquidate ESCO in the coming years.analysis.
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ConcessionsCONCESSIONS
We operate under concessions granted by the Brazilian government for our generation, transmission and distribution businesses. Under Brazilian law, concessions are subject to competitive bidding processes at the end of their respective terms.
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2013 Concession Renewal Law
Until recently,2013, the Brazilian rules governing generation concessions gave concessionaires the right to renew for an additional 20 years concession contracts that were entered into prior to 2003. For transmission and distribution concessions granted after 1995, concessionaires had the right to renew these contracts for an additional 30 years.30-year period.
On September 11, 2012, the Brazilian federal government enacted a law (“the 2013 Concession Renewal Law”Law, which had been preceded by a provisional measure (medida provisória), which significantly changed the conditions under which concessionaires are able to renew concession contracts. Under the 2013 Concession Renewal Law, generation, transmission and distribution concessionaires may renew the concessions that were in effect as of 1995 (and, in the case of generation facilities, generation concession contracts entered into prior to 2003) for an additional period of 30 years (or an additional 20-year period in the case thermal plants), provided that the concessionaire agrees to amend the concession contract to reflect a series of new conditions. The purpose of this new regime was to substantially reduce the cost of electricity paid by Final Customers and to stimulate economic growth. Under the 2013 Concession Renewal Law, concessionaires must decide 60 months before the end of each concession term whether to amend and renew a concession contract or to terminate each concession contract at the end of its respective term. For concession contracts expiring within 60 months of September 12, 2012, concessionaires were required to make this decision by October 15, 2012. So far, for our contracts expiring within this period, we have decided not to renew our generation contracts, and we decided to request the renewal of our transmission and distribution contracts.
For concessionaires of existing generation facilities, the 2013 Concession Renewal Law changes the scope of these concession contracts.contracts that are renewed. Previously, a generation concessionaire had the right to sell the energy generated by the facilities subject to its concession for profit. In contrast, generation concessions renewed pursuant to the 2013 Concession Renewal Law will not grant concessionaires the right to sell the energy generated by these facilities. Instead, these concessions will only cover the operation and maintenance of the generation facilities. The energy generated by these facilities will be allocated by the Brazilian federal government in quotas to the regulated market, for purchase by distribution concessionaires. For new generation facilities, on the other hand, the concessionaire will still have the right to sell the energy produced by the generation facility.
In addition to changing the scope of generation concessions, the 2013 Concession Renewal Law establishes a new tariff regime that significantly affects the treatment of amounts to be invested by concessionaires to improve and maintain generation plants. BecauseTo this effect, several regulations were issued by MME and ANEEL to regulate the 2013 Concession Renewal Law requires that ANEEL pre-approvecompensation due to concessionaires as a result of their investments made byto improve and maintain generation concessionaires in order to receive compensation, the new law substantially increases the risk that a generation concessionaire either will not be able to make certain investments in a timely manner, or will not be able to recover the amounts invested. These changes are expected to materially reduce the margins of generation concessionaires and negatively affect their financial condition. In addition, ANEEL is expected to issue further regulations for generation concessions under the 2013 Concession Renewal Law, and it is not clear what the consequences of these regulations will be.plants.
The 2013 Concession Renewal Law affects transmission and distribution concessions differently. The principal change is that amounts invested related to modernization projects, structural reforms, equipment and contingencies will be subject to prior ANEEL approval. However, the 2013 Concession Renewal Law does not affect the manner in which distribution and transmission concessionaires may recover amounts invested in transmission infrastructure.
The 2013 Concession Renewal Law applies to all generation, transmission and distribution contracts that were in effect as of 1995 (and, in the case of generation concessions, entered into prior to 2003), regardless of whether a contract grants to the concessionaire the right to renew a concession on its original terms. For example, several of our concession contracts contain provisions allowing us to renew these concessions for a period of 20 years. Under the 2013 Concession Renewal Law, in order to renew these contracts, we nonetheless would be required to accept the application of the conditions imposed by thebythe 2013 Concession Renewal Law to the contract, and the concession contract would then be renewed for 30 years, rather than 20.20 years. If we choose to renew a concession contract that contains a renewal provision, we would be indemnified by the Brazilian government using funds from the RGR Fund (seeEnergy(see Energy Sector Regulatory Charges) in an amount equal to the portion of our investments related to the concession that have not yet been amortized or depreciated, as calculated by ANEEL.
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If a concessionaire decides not to accept the new tariff regime with respect to a concession contract and therefore decides not to renew the contract, the concession will terminate at the end of its original term, and the Brazilian government will conduct a new competitive bidding process for the concession. The original concessionaire may participate in the new competitive bidding process.
Generation Concessions
Out of our 18the seventeen (17) generation concessions,plants we have threeoperated in 2017, sixteen (16) were operated pursuant to generation concessionsconcession agreements that were still in effect, and one (Capivari Cachoeira MourãoHPP) was under an operation and Chopim I, with respective installed capacity of 260.0 MW, 8.2 MW and 1.8MW) setmaintenance regime that shall be in effect until 2046.
With respect to expireCapivari Cachoeira, although Copel GeT did not elect to renew the original concession for the Capivari Cachoeira HPP, it participated in 2015, which we have decided not to renew. Also, we decided to not renew a concession agreement of one of our hydroelectric plants (Rio dos Patos, with installed capacity of 1.8 MW) that was set to expire on February 14, 2014. While we ceased to sell the energy produced by this plant, we continue to operate and maintain it until the winner of a new competitive bidding process to be conducted byand won. On January 5, 2016, Copel GeT executed a concession agreement with ANEEL assumes the plant. Our management determinedso that renewal of these generation concessions under the terms of the 2013 Concession Renewal Law would be disadvantageous to our generation business. Therefore, our management decided to allow these concession contracts to expire, and to participate in the subsequent competitive bidding process for these concessions. However, weit will continue to be responsible for theoperate this plant under an operation and maintenance regime until 2046. We paid a total amount of these plants untilR$574.8 million as signing bonus for this concession agreement.
The Capivari Cachoeira Plant has 260 MW of installed capacity, assured average power of 109 MW and the winnerrevenue of a competitive bidding process assumesits operation and maintenance for the plant. Until then,period of July 2016 to June 2017 was R$126.1 million and for the period of July 2017 to June 2018 is R$114,086 million. 100% of the energy generated by this plant in 2017 was allocated in quotas to the regulated market, and reduced to 70% on January 1, 2018. Copel GeT can sell remaining amount of energy generated by this plant on the energy market. Copel GeT will receive a pre-established tariff to operate and maintainno longer bear the plant, as defined by MME 170/2014 resolution.hydrological risk for “assured energy” under the Energy Reallocation Mechanism (MRE) associated with the Capivari Cachoeira Plant.
Under the rules in effect prior to the enactment of the 2013 Concession Renewal Law, 13 of our generation plants have had their concessions extended by Brazilian authorities since 1999, in each case for the 20-year term allowed by previous regulation. Under the previous law, these concessions were not eligible for a second extension. However, as described above, the 2013 Concession Renewal Law now allows extension of these concessions for an addition 30 years period if we choose to accept the application of the new tariff regime.
Concessions for generation projects, granted after 2003, such as the Mauá Hydroelectric Plant, are non-renewable, meaning that upon expiration of their 35-year term, the concession will be granted subject to a competitive bidding process. The 2013 Concession Renewal Law does not impact generation concessions granted after 2003.
The following tables sets forth information relating to the terms as well as the renewals of our main generation hydroelectric, thermoelectric and wind farm plants, whose original concessions (allare not yet subject to the 2013 Concession Renewal Law and all of which we hold a direct ownership interest):interest in:
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Hydroelectric Plants | Initial concession date | First expiration date | Extension Date | Final expiration date |
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Foz do Areia | May, 1973 | May, 2003 | January, 2001 |
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Apucaraninha | October, 1975 | October, 2005 | April, 2003 | October, 2025 |
Guaricana | August, 1976 | August, 2006 | August, 2005 | August, 2026 |
Chaminé | August, 1976 | August, 2006 | August, 2005 | August, 2026 |
Segredo | November, 1979 | November, 2009 | September, 2009 | November, 2029 |
Derivação do Rio Jordão | November, 1979 | November, 2009 | September, 2009 | November, 2029 |
Salto Caxias | May, 1980 | May, 2010 | September, 2009 | May, 2030 |
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Marumbi | March, 1956 | Under review by ANEEL | Under review by ANEEL | Under review by ANEEL |
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Mauá | June, 2007 | July, 2042 | Not extendable | July, 2042 |
Colíder | January, 2011 | January, 2046 | Not extendable | January, 2046 |
Cavernoso II | February, 2011 | February, 2046 | Not extendable | February, 2046 |
Baixo Iguaçu | August, 2012 | August, 2047 | Not extendable |
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(1) The concession for Rio dos Patos expired in February 2014 and was not renewed. Until a new competitive bidding process is concluded with respect to this facility, we will continue to operate it under the terms and conditions of the 2013 Concession Renewal Law.
(2) Mauá was constructed by Consórcio Energético Cruzeiro do Sul, of which Copel owns 51.0% and Eletrosul owns the remaining 49.0%.
(3)(2) Expected to begin operations in April 2016.June, 2018.
(4)(3) Under construction by Consórcio Empreendedor Baixo Iguaçu, of which Copel owns 30% and Geração Céu Azul the remaining 70%.It. It is expected to begin operations in 2017.November, 2018.
Thermoelectric Plants | Initial concession date | First expiration date | Extension date | Final expiration date |
Figueira | March 1969 | March 1999 | June 1999 | March 2019 |
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Wind Plants | Initial concession date | First expiration date |
Asa Branca I | April, | April, |
Asa Branca II |
| May, |
Asa Branca III |
| May, |
Nova Eurus IV | April, | April, |
Santa Maria | May, | May, |
Santa Helena | April, | April, |
Ventos de Santo Uriel | April, | April, |
Boa Vista | April, | April, |
Farol | April, | April, |
Olho D'Água | June, | May, |
São Bento do Norte | May, | May, |
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Guariju |
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Jangada |
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Maria Helena |
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Palmas | September, 1999 | September, 2029 |
Potiguar |
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Esperança do Nordeste |
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Paraíso dos Ventos do Nordeste |
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São Bento do Norte I |
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São Bento do Norte II |
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São Bento do Norte III |
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São Miguel I |
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São Miguel II |
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São Miguel III |
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(1) Wind plants located at Copel’s Brisa Potiguar wind farm complex under construction.
(2) Under construction by Voltália Energia do Brasil S.A. Copel holds a 49% interest. Expected to begin operations in April 2015.
(3) Wind plants located at Copel’s Cutia wind farm complex under construction.
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The following table sets forth information relating to the terms of our generation hydroelectric plant, whose concession agreement has been executed under the terms and conditions of the 2013 Concession Renewal Law:
Hydroelectric Plants | Initial concession date | First expiration date | Extension Date | Final expiration date |
Capivari Cachoeira (Gov Parigot de Souza) | January, 2016 | January, 2046 | Not subject to extension | January, 2046 |
The following table sets forth information relating to the terms of our generation hydroelectric plants which, once respective original concession period expires, will no longer be subject to a concession regime but rather to a registration proceeding with the ANEEL:
Hydroelectric Plants | Initial concession date | Concession expiration date | Final expiration date |
Chopim I(1) | March, 1964 | July, 2015 | Indefinitely |
São Jorge | December, 1974 | December, 2024 | Indefinitely |
Cavernoso | January, 1981 | January, 2031 | Indefinitely |
Melissa | May, 2002 | Indefinitely | - |
Pitangui | May, 2002 | Indefinitely | - |
Salto do Vau | May, 2002 | Indefinitely | - |
(4)(1) Auctioned on ANEEL’s auction No. 08/2014 as of October 31, 2014. The authorization award is expectedLaw 13,097/15, enacted in January 2015, changed the capacity limit for Hydroelectricity Generation Centers – HGCs and SHPs. After this change, the HGCs’ limit increased from 1MW to 3MW. As a result, the Chopim I plant, which used to be issued within 180 days from the auction date.
(5) The authorization granted expires 35 years after the publication of the authorization award.
(6) Auctioned on ANEEL’s auction No. 06/2014classified as of November 28,2014. Thea SHP, is now a HGC, and no longer needs a concession, award is expected to be issued within 180 days from the auction date.just registration with ANEEL.
We also have ownership interests in fiveeight other generation projects. The following table sets forth information relating to the terms of the concessions of the generation facilities in which we had such partial ownership interest as of December 31, 2014.2017.
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Generation Facility | Company | Initial concession date | Expiration date | Extension |
Dona Francisca hydroelectric power plant | Dona Francisca Energética SA ‒ DFESA | July, 1979 | August, 2033 | Possible |
Santa Clara and Fundão hydroelectric power plant | Centrais Elétricas do Rio Jordão S.A. - ELEJOR | October, 2001 |
| Possible |
Araucária thermoelectric power plant | UEG Araucária Ltda. | December, 1999 | December, 2029 | Possible |
| Foz do Chopim Energética | April, 2000 | April, 2030 | Possible |
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Carnaú | São Miguel do Gostoso I | April, 2012 | April, 2047 | Not possible |
| São Miguel do Gostoso I | April, 2012 | April, 2047 | Not possible |
Santo | São Miguel do Gostoso I | April, 2012 | April, 2047 | Not possible |
São Joã | São Miguel do Gostoso I | March, 2012 | March, 2047 | Not possible |
(1) Wind plants.
Transmission Concessions
Pursuant to the 2013 Concession Renewal Law and the terms of our transmission concessions, we have the right to request 30-year extensions of the concessions from ANEEL, provided that such request is delivered within 60 months prior to the expiration of the contract in question.contract. Our principal transmission concession, from which we derived 82.6%85.2% of our transmission revenues in 2014,2017, has been renewed pursuant to the 2013 Concession Renewal Law, and will therefore now expire in December 2042.
In addition, in 2017, we have fourderived an aggregate of 14.8% of our transmission revenues from nine other concession contracts for transmission lines and substations that are currently in operation and whose terms and extensions are set to expireforth in July 2031, March 2038, November 2039 and October 2040, respectively. We derived an aggregate of 17.4% of our transmission revenues from these three contracts in 2014.the next table . In accordance with the 2013 Concession Renewal Law, each of these contracts can be extended for an additional 30-year period.
We intend to continue requesting extensions for all of our transmission concessions.
The following table sets forth certain information relating to the terms and extension terms of our main transmission concessions (all of which we hold a direct ownership interest):, including the concession contracts for transmission lines and substations both in operation or under construction:
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Transmission Facility | Initial concession Date | First expiration Date | Possibility of extension | Expected (or final) expiration date |
Main transmission concession | July, 2001 | July, 2015 | Extended | December, 2042 |
Bateias – Jaguariaíva | August, 2001 | August, 2031 | Possible | August, 2061 |
Bateias – Pilarzinho | March, 2008 | March, 2038 | Possible | March, 2068 |
Foz do Iguaçu – Cascavel Oeste | November, 2009 | November, 2039 | Possible | November, 2069 |
Substation Cerquilho III | October, 2010 | October, 2040 | Possible | October, 2070 |
Araraquara 2 – Taubaté(1) | October, 2010 | October, | Possible | October, 2070 |
Foz do Chopim - Salto Osorio | August, 2012 | August, 2042 | Possible | August, 2072 |
Assis – Paraguaçu Paulista II | February, 2013 | February, 2043 | Possible | February, 2073 |
Bateias – Curitiba Norte | January, 2014 | January, 2044 | Possible | January, 2074 |
| September, 2014 | September, 2044 | Possible | September, 2074 |
Assis - Londrina | September, 2014 | September, 2044 | Possible | September, 2074 |
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| Possible |
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(1)Facility under construction.
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We have ownership interests in ten other transmission projects, through special purpose companies. The following table sets forth information relating to the terms of the concessions of the transmission facilities in which we had such partial ownership interest as of December 31, 2014:2017:
Transmission Facility | Special Purpose Company (SPC) | Initial concession date | First Expiration date | Possibility of Extension | Expected (or final) expiration date |
Cascavel Oeste – Umuarama | Costa Oeste Transmissora de Energia S.A | January, 2012 | January, 2042 | Possible | January, 2072 |
Nova Santa Rita
| Transmissora Sul Brasileira de Energia S.A | May, 2012 | May, 2042 | Possible | May, 2072 |
Umuarama - Guaira | Caiuá Transmissora de Energia S.A | May, 2012 | May, 2042 | Possible | May, 2072 |
Açailândia Miranda II | Integração Maranhense Transmissora de Energia S.A. | May, 2012 | May, 2042 | Possible | May, 2072 |
Curitiba - Curitiba Leste | Marumbi Transmissora de Energia S.A. | May, 2012 | May, 2042 | Possible | May, 2072 |
Paranaíta – Ribeirãozinho | Matrinchã Transmissora de Energia S.A. | May, 2012 | May, 2042 | Possible | May, 2072 |
Ribeirãozinho – Marimbondo II | Guaraciaba Transmissora de Energia S.A | May, 2012 | May, 2042 | Possible | May, 2072 |
Barreiras II – Pirapora II | Paranaíba Transmissora de Energia S.A | May, 2013 | May, 2043 | Possible | May, 2073 |
Itatiba – Bateias | Mata de Santa Genebra Transmissora S.A | May, 2014 | May, 2044 | Possible | May, 2074 |
Estreito – Fernão Dias | Cantareira Transmissora de Energia S.A. | September, 2014 | September, 2044 | Possible | September, 2074 |
(1) Facility under construction.
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Distribution Concessions
We operateoriginally operated our distribution business pursuant to a concession contract that was signed on June 24, 1999 (retroactive to July 7, 1995), and iswas set to expire on July 7, 2015. Under the 2013 Concession Renewal Law, we havehad the right to renew this concession for an additional 30-year period by accepting an amendment to the concession contract. Notwithstanding the changes introduced by the 2013 Concession Renewal Law, we concluded that the renewal of our distribution concession in accordance with the 2013 Concession Renewal Law would not materially affect our results of operations. Accordingly, after a careful evaluation of the conditions imposed by the Brazilian federal government for the extension of our distribution concession, we decided to request the renewal of this contract. Howevercontract and our renewal request was approved by the MME on November 11, 2015. On December 9, 2015, we have not yet receivedexecuted the fifth amendment to be proposed by the granting authority. Therefore, we cannot guaranteepublic Electricity Distribution Service Concession Agreement No. 46/1999 of Copel Distribuição S.A.
This amendment imposes efficiency conditions to Copel Distribuição that we will be ableare measured through two different metrics: quality of the service and economic-financial sustainability of the company. Failure to renewcomply with any of these metrics (a) for two consecutive years within the first four years of this renewed concession or (b) in the fifth year of this concession, may, in each case, result in the termination of our distribution concession contractconcession. From January 1, 2021 on, terms that are favorablefailure to us.comply with the quality indicator for three consecutive years or the economic-financial sustainability indicator for two consecutive years may also result in the termination of the distribution concession.
Additionally, non-compliance with quality indicator targets for two consecutive years or three times in five years may lead to restrictions in the payment of dividends and interest on equity to the controlling shareholder Copel Distribuição, while non-compliance with the economic-financial sustainability indicators may require capital contributions from Copel Distribuição controlling shareholders.
The granting authority must issue its decision ontable below presents the economic and financial and quality indicators established for the first five years after the execution of this matter no later than 18 monthsamendment.
| Economic and Financial Indicators | Quality Indicators(1) | |
Year |
| DECi(2) | FECi(2) |
2016 | N/A | 13.61 | 9.24 |
2017 | EBITDA(3) ≥ 0 | 12.54 | 8.74 |
2018 | [EBITDA (-) QRR (4)] ≥ 0 | 11.23 | 8.24 |
2019 | {Net Debt(5)/[EBITDA(3) (-) QRR(4)]}≤ 1/(0.8*SELIC(6)) | 10.12 | 7.74 |
2020 | {Net Debt(5)/[EBITDA(3) (-) QRR(4)]}≤ 1/(1.11*SELIC(6)) | 9.83 | 7.24 |
(1)According to ANEEL’s Technical Note No. 0335/2015.
(2)DECi – Duration of outages per customer per year (in hours); and FECi – Frequency of outages per customer per year (number of outages).
(3) Earnings before interest, tax depreciation and amortization, as calculated according to ANEEL regulations.
(4)QRR: Regulatory Reintegration Quota or Regulatory Depreciation Expense. This is the concession’s expiration date. Under our main distribution contract,value defined in the most recent Periodic Tariff Review (RTP), plus the General Market Price inflation index (IGP-M) between the month preceding the Periodic Tariff Review and the month preceding the twelve-month period of the economic and financial sustainability measurement.
(5)As calculated according to ANEEL shouldregulations.
(6)Selic base rate: limited to 12.87% per year.
We have respondedcomplied with the quality indicators for 2017 both with respect to our request by January 7, 2014, but the fact that we did not receive a response from ANEEL by this deadline does not itself impact our ability to renew this contract under the 2013 Concession Renewal Law.DECi (totaling 10.41 in 2017) and FECi (totaling 6.79 in 2017).
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We have concessions to distribute electricity in substantially all of the State of Paraná, and we do not face competition from the five utilities that have been granted concessions for the remainder of the state. As a result of legislation passed in 2004, however, other suppliers are able to offer electricity to our existing Free Customers at prices lower than those we currently charge. However, when a captive customerCaptive Customer becomes a Free Customer, it is still required to pay to use our distribution grid. The reduction in net revenue of our distribution business is therefore compensated with a reduction in our costs for energy that we would otherwise acquire to sell to these customers.
Furthermore, under certain circumstances, Free Customers may be entitled to connect directly to the Interconnected Transmission System rather than our distribution grid. Unlike a Free Customer’schoiceCustomer’s choice of another energy supplier, in which case that customer must still use our distribution grid and thus pay us the appropriate tariff, our distribution business ceases to collect tariffs from a customer that connects directly to the Interconnected Transmission System. The migration of customers from the distribution grid to the transmission network therefore results in the loss of revenues for our distribution business.
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Distribution and transmission companies are required to permit the use of their lines and ancillary facilities for the distribution and transmission of electricity by other parties upon payment of a tariff.
Free Customers are limited to:
· existing customers (those connected to the distribution grid before July 1995) with demand of at least 3 MW and supplied at voltage levels equal to or greater than 69 kV;
· new customers (those connected to the distribution grid after July 1995) with demand of at least 3 MW at any voltage; and
· customers with demand of at least 500 kW that opt to be supplied energy by means of alternative sources, such as wind power projects, small hydroelectric power plants, or biomass projects.projects, solar plants and others.
As of December 31, 2014,2017, we had 29 (twenty-nine)one hundred ninety-one (191) Free Customers, representing approximately 3.7%5.1% of our consolidated net operating revenue and approximately 8.1%10.6% of the total quantity of electricity sold by us. Through
Until March 31, 2015, we had 2 (two)2018, Copel GeT signed five (5) additional agreements with Free Customers, that expired and were not renewed.Customers. Our contracts with Free Customers are typically for periods of greatermore than two and less than five years.
Approximately 6.1%9.4% of the megawattsmegawatts-hours sold under contracts to such customers are set to expireby Copel GeT expired in 2015. In addition, as of December 31, 2014, we had 53 customers that were eligible to purchase energy as Free Customers.2017. These customers represented approximately 4.6%2.7% of the total volume of electricity we sold in 2014,2017, and approximately 7.6%2.2% of our total net operating revenue from energy sales for that year.
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Regarding our energy trading company, as of December 31, 2017, we had one hundred thirty-nine (139) Free Customers, representing approximately 0.9% of our consolidated operating revenues and approximately 3.2% of the total volume of electricity we sold to Final Customers.
In the generation business, any producer may be granted a concession to build or manage thermoelectric and small hydroelectric generating facilities in the State of Paraná. Brazilian law provides for competitive bidding for generation concessions for hydroelectric facilities with capacity higher than 30 MW.
In the transmission business, Brazilian law provides for competitive bidding for transmission concessions for facilities with a voltage of 230 kV or greater that will form part of the Interconnected Transmission System.
Brazilian law requires that all of our generation, transmission and distribution concessions be subject to a competitive bidding process upon their expiration. We may face significant competition from third parties in bidding for renewal of such concessions or for any new concessions. The loss of certain concessions could adversely affect our results of operations.
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Our construction and operation activities for the generation, transmission and distribution of electric energy, distribution of natural gas and our telecommunications operations are subject to federal, state and municipal environmental regulations.
All of our activities follow our Sustainability and Corporate Citizenship Policy, which integrates corporate planning and sustainability management in order to optimize our financial, social and environmental performance. We have implemented a Climate Change Policy, which establishes guidelines for the mitigation of greenhouse gas emission and changes in our business, evaluating risks and opportunities related to climate change.
We request and renew our environmental licenses in accordance with the environmental regulation issued by applicable federal, state and municipal level authorities. We are in compliance withallwith all material environmental regulations and our more recent (post-1986) generation, transmission and distribution projects are in compliance with federal, state and municipal regulations.
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To comply withIn 2017, we implemented the environmental licensing of transmission facilities predating the 1986 environmental licensing requirements, we and the environmental regulator for the State of Paraná (“Instituto Ambiental do Paraná – IAP”) executed in 2010 aconduct adjustment term – TAC,agreement in which we committed to complete an environmental licensing process for these facilities by 2012. This environmental licensing process for all of our transmission facilities is complete since 2012.
In 2014, 4 (four) compulsory environmental audits (Auditorias Ambientais Compulsórias – AACs) were performed, 3 (three) of which were of a substation and 1 (one) of which was of transmission line. Starting in 2012 these compulsory environmental inspections were required by law as a condition for the renewal of environmental licenses, however, since August, 2014 we are no longer required to perform such inspections as a condition for the renewal of our environmental licenses.
In December 2010, we received the site licenses to begin construction of the Colíder Hydroelectric Plant. These licenses were granted after we received approval of Colíder Basic Environmental Plan, which contains thirty-two programs and sub-programs designed to prevent, mitigate and offset any negativenecessary environmental and social impactplans for the development and operation of this project, while enhancing the positive effects of the project. During 2014 we continuedour local assets related to implement the programs contained in the Colíder Basic Environmental Plan.
We are involved in environmentalgeneration, transmission and social programs including the “Social and Environmental Reservoirs Management Program” (Programa de Gestão Socioambiental de Reservatórios).TheSocial and Environmental Reservoirs Management Program aimsto improve the quality and availability of water in Copel’s reservoirs through managing and monitoring of watersheds.distribution.
To reinforce our commitment to environmental, social and economic sustainability, we are signatories to the United Nations Global Compact, and we actively seek to implement the principles of the Global Compact in our daily activities and our corporate culture. Additionally, in 2017, COPEL created a center for the United Nations Global Compact Cities Programme, aiming to create partnerships with governmental authorities, civil society and universities in order to develop innovative projects and address urban challenges.
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Plant, Property and EquipmentPLANT, PROPERTY AND EQUIPMENT
Our principal properties consist of the generation and telecommunications facilities described in “Business—“Business - Generation and Purchasers of Energy”. Of the net book value of our total property, plant and equipment atas of December 31, 20142017 (including construction in progress), generation facilities represented 72.6%63.5%, wind farms represented 11.6%20.2%, telecommunications represented 5.3%8.8%, Elejor represented 5.4%4.0%, and Araucária Thermoelectric Plantplant represented 5.1%3.4%. We believe that our facilities generally are adequate for our present needs and suitable for their intended purposes.
In adition , the infrasctruture used by transmission and distribution business, these are classifiedas a financial and a intangible assets as described in note 4.3.9 of our audited financial statements.
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The Expropriation ProcessTHE EXPROPRIATION PROCESS
Although we receive concessions from the Brazilian government to construct hydroelectric facilities, we do not receive title to the land on which the facilities are to be located. In order for us to construct, the land must be expropriated. The land required for the implementation of a hydroelectric facility may only be expropriated pursuant to specific legislation. We generally negotiate with communities and individual owners occupying the land so as to resettle such communities in other areas and to compensate individual owners. Our policy of resettlement and compensation generally has resulted in the settlement of expropriation disputes. Atdisputes, with friendly settlements for most of them. As of December 31, 2014,2017, we estimated our liability related to the settlement of such disputes to be approximately R$52.881.2 million. This amount is in addition to amounts for land expropriation included in each of our hydroelectric facility budgets.
General
In December 2014,2017, the MME approved a ten-year expansion plan under which Brazil’s installed power generation capacity is projected to increase to 195.94212.5 GW by 2023,2026, of which 59.7%48.7% is projected to be hydroelectric, 14.5%10.9% is projected to be thermoelectric, 1.7%1.6% is projected to be nuclear and 24.1%29.7% is projected to be from alternative energy sources such as wind, biomass and small hydroelectric plants.
Approximately 34%32% of the installed power generating capacity of Brazil is currently owned by Eletrobras (including its wholly-owned subsidiary Eletronuclear and its 50.0%50% participation interest in Itaipu). Through its subsidiaries, Eletrobras is also responsible for 55%47% of the installed transmission capacity equal or above 230 kV within Brazil. In addition, some Brazilian states control entities involved in the generation, transmission and distribution of electricity.They include Companhia Energética de São Paulo – CESP, Companhia Energética de Minas Gerais – CEMIG and us, among others.
Principal Regulatory Authorities
Ministry of Mines and Energy – MME
The MME is the primary regulator of the power industry and acts as the Brazilian governmental authority empowered with policymaking, regulatory and supervisory powers.
National Energy Policy Council – CNPE
The National Energy Policy Council (Conselho Nacional de Política Energética - “CNPE”), created in August 1997, provides advice to the President of the Republic of Brazil regarding the development and creation of a national energy policy. The CNPE is chaired by the MME and is composed of six ministers of the Federal Government and three members chosen by the President of Brazil. The CNPE was created in order to optimize the use of energy resources in Brazil and ensure the national supply of electricity.
National Electric Energy Agency – ANEEL
The Brazilian power industry is regulated by ANEEL, an independent federal regulatory agency. ANEEL’s primary responsibility is to regulate and supervise the power industry in accordance with the policies set forth by the MME and to respond to matters which are delegated to it by the Brazilian government and the MME. ANEEL’s current responsibilities include, among others, (i) administering concessions for electric energy generation, transmission and distribution, including the approval of electricity tariffs, (ii) enacting regulations for the electric energy industry, (iii) implementing and regulating the utilization of energy sources, including the use of hydroelectric power, (iv) promoting, monitoring and managing the public bidding process for new concessions, (v) settling administrative disputes among electricity sector entities and electricity purchasers, and (vi) defining the criteria and methodology for the determination of transmission and distribution tariffs.
National Electric System Operator – ONS
The ONS (Operador Nacional do Sistema Elétrico) is a non-profit private entity comprised of electric utilities engaged in the generation, transmission and distribution of electric energy, in addition to other private participants such as importers, exporters and Free Customers. The primary role of the ONS is to coordinate and regulate the generation and transmission operations in the Interconnected Transmission System, subject to the ANEEL’s regulation and supervision. The objectives and principal responsibilities of the ONS include, among others, operational planning for the generation industry,organizing the use of the domestic Interconnected Transmission System and international interconnections, ensuring that industry participants have access to the transmission network in a non-discriminatory manner, assisting in the expansion of the electric energy system, proposing plans to the MME for extensions of the Interconnected Transmission System, and formulating regulations regarding the operation of the transmission system for ANEEL’s approval.
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Electric Energy Trading Chamber – CCEE
The CCEE (Câmara de Comercialização de Energia Elétrica) is a non-profit private entity subject to authorization, inspection and regulation by ANEEL. The CCEE is responsible for, among other things, (i) registering all energy purchase agreements in the regulated market,Contratos de Comercialização de Energia no Ambiente Regulado (“CCEAR”), and registering the agreements resulting from market adjustments and the volume of electricity contracted in the free market, and (ii) accounting for and clearing short-term transactions.transactions and (iii) managing funds generated by some of the regulatory charges. The CCEE is composed of holders of concessions, permissions and authorizations in the electricity industry and Free Customers, and its board of directors is composed of four members appointed by these agents and one by the MME, who is the chairman of the board of directors.
Energy Sector Monitoring Committee – CMSE
The CMSE (Comitê de Monitoramento do Setor Elétrico) was created by the New Industry Model Law to monitor service conditions and to recommend preventative measures to ensure energy supply adequacy, including demand-side action and contracting of energy reserves.
Energy Research Company – EPE
In August 2004, the Brazilian government created the Energy Research Company (Empresa de Pesquisa Energética - “EPE”), a federal public company responsible for conducting strategic studies and research in the energy sector, including the industries of electric power, petroleum, natural gas, coal and renewable energy sources. The studies and research conducted by the EPE subsidize the formulation of energy policy by the MME.
Eletrobras
Eletrobras serves as a holding company for the following federally-owned energy companies: Companhia Hidro Elétrica do São Francisco – CHESF, Furnas, Eletrosul, Centrais Elétricas do Norte do Brasil S.A. –Eletronorte, Companhia de Geração Térmica de Energia Elétrica – CGTEE and Eletrobras Termonuclear S.A.–Eletronuclear.EletrobrasEletronuclear, Eletrobras Amazonas Energia, Eletrobras Distribuição Roraima, Eletrobras Distribuição Alagoas, Eletrobras Distribuição Piauí, Eletrobras Distribuição Rondônia, Eletrobras Distribuição Acre, Cepel and Itaipu Binacional.Eletrobras manages funds generated by some of the regulatory charges, as well as the commercialization of energy from Itaipu and from alternative energy sources, under the Proinfa Program.
Historical Background of Industry Legislation
The Brazilian constitution provides that the development, use and sale of electric energy may be undertaken directly by the Brazilian federal government or indirectly through the granting of concessions, permissions or authorizations. Historically, the Brazilian electric energy industry has been dominated by generation, transmission and distribution concessionaires controlled by the federal or state governments. Since 1995, the Brazilian government has taken a number of measures to reform the Brazilian electric energy industry.in general, these measures were aimed at increasing the role of private investment and eliminating foreign investment restrictions in order to increase overall competition and productivity in the industry.
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The following is a summary of the principal developments in the regulatory and legal framework of the Brazilian electricity sector:
·In 1995, (i) the Brazilian constitution was amended to authorize foreign investment in power generation; (ii) the Concessions Law was enacted, requiring that all concessions for energy related services be granted through public bidding processes, providing for the creation of independent producers and Free Customers and granting electricity suppliers and Free Customers open access to all distribution and transmission systems; and (iii) a portion of the controlling interests held by Eletrobras and various Brazilian states in generation and distribution companies were sold to private investors.
· In 1995, (i) the Brazilian constitution was amended to authorize foreign investment in power generation; (ii) the Concessions Law was enacted, requiring that all concessions for energy-related services be granted through public bidding processes, providing for the creation of independent producers and Free Customers and granting electricity suppliers and Free Customers open access to all distribution and transmission systems; and (iii) a portion of the controlling interests held by Eletrobras and various Brazilian states in generation and distribution companies were sold to private investors. · In 1998, the Power Industry Law was enacted, providing for, among other things, the creation of the ONS and the appointment of Banco Nacional de Desenvolvimento Econômico e Social (“BNDES”), a development bank wholly owned by the Brazilian government, as the financing agent of the power industry, especially to support new generation projects. · In 2001, Brazil faced a serious energy crisis that lasted through February 2002. During this period, the Brazilian government implemented an energy-rationing program in the most adversely affected regions, namely the southeast, central-west and northeast regions of Brazil. In April 2002, the Brazilian government for the first time implemented the extraordinary tariff adjustment to compensate the electricity suppliers for financial losses incurred as a result of the rationing period. · In 2004, the Brazilian government enacted the New Industry Model Law, in an effort to further restructure the power industry with the ultimate goal of providing customers with a stable supply of electricity at reasonable prices. · In 2012, the Brazilian government enacted two Provisional Measures that brought important changes to the Brazilian electricity regulatory framework: (i) Provisional Measure No. 577, dated as of August 29, 2012 (converted into Law No. 12,767 dated as of December 27, 2012); and (ii) Provisional Measure No. 579, dated September 11, 2012 (converted into the 2013 Concession Renewal Law). Provisional Measure No. 577 established the obligation of the granting authority to render electricity services in the event of termination of an electricity concession, as well as new rules related to the intervention by the granting authority in electricity concessions to ensure adequate performance of utility services. The 2013 Concession Renewal Law established new rules that changed concessionaires’ ability to renew concession contracts. Under this Law, generation and distribution concessionaires may renew their concession contracts that were in effect as of 1995 and transmission concessionaires may renew their concession contracts that were in effect prior to and as of 1995 for an additional period of 30 years, provided that the concessionaires agree to amend the concession contracts to reflect a new tariff regime to be established by ANEEL. See “Concessions”. · In 2015, the Brazilian government enacted Provisional Measure No. 688, dated as of August 18, 2015, converted into Federal Law No. 13,203, dated as of December 8, 2015, to revise the allocation of the hydrological risks borne by hydroelectric power plants that share hydrological risks under Energy Reallocation Mechanism. See“Item 4 – Information on the Company - The Brazilian Electric Power Industry - Energy Reallocation Mechanism”. In 2014 and 2015, given poor hydrological conditions, the MRE participants generated less electricity than their assured energies, which was confirmed by a significant decrease of the Generating Scaling Factor (“GSF”), a measurement of the proportion between theelectricity generated by the MRE participants and their respective assured energy. 69·In 1998, the Power Industry Law was enacted, providing for, among other things, the creation of the ONS and the appointment of Banco Nacional de DesenvolvimentoEconô
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| These generation deficits resulted in losses for the MRE participants given their exposure to hydrological risks. As a consequence, Federal Law No. 13,203 established an optional mechanism that allows each generation plant to transfer these risks to Final Customers upon payment of a risk premium to the Brazilian federal government, as well as certain temporary extensions of generation concessions to compensate for losses in 2015. We decided to opt-in with respect to all of Copel GeT´s and Elejor´s eligible Energy Agreements under this new hydrological risk allocation mechanism, which represented approximately 16% of Copel GeT´s total assured energy. |
· | In 2016, the Brazilian government enacted Provisional Measure No. 735, dated as of June 22, 2016, converted into Federal Law No. 13,360, dated as of November 17, 2016, which changed several federal laws mainly to: (i) revise certain rules related to regulatory charges (CDE, CCC and RGE) and appoint CCEE as the new manager of such charges; (ii) facilitate the privatization of generation, transmission and distribution companies, (iii) change certain requirements of the generation concession and authorization regimes; (iv) change rules related to the MRE; (v) allow distribution companies to sell energy excess in the free market; (vi) extension of terms for commencement of the supply under energy auctions in the regulated market; and (vii) transfer back from MME to ANEEL the authority to decide about generation and transmission companies’ requests for extension of their facilities construction schedules. |
· | In July 2017, the MME released the Public Consultation No. 033/2017, named “Proposal for improvement of the legal framework of the electricity sector”. This public consultation was intended to receive contributions for the structuring of changes to the power legal framework to ensure long-term sustainability for the Brazilian power industry. This public consultation marks an important step to guide the MME in preparation of specific legislative proposals capable of providing measures of economic rationalization and modernization of the electricity sector. |
· | In August 2017, the Investment Partnership Program Council of the Presidency of the Republic issued Resolution No. 13, dated August 23, 2017, recommending the privatization of Centrais Elétricas Brasileiras S.A. – Eletrobras, and, accordingly, its inclusion in the National Privatization Program, without prejudice to the ongoing divestment processes related to the sale of Eletrobras’ equity interests in six distribution companies under its control and seventy generation and transmission special purpose companies. |
Concessions
The companies or consortia that wish to build or operate facilities for generation, transmission or distribution of electricity in Brazil must participate in a competitive bidding process or must apply to the MME or to ANEEL for a concession, permission or authorization, as the case may be. Concessions grant rights to generate, transmit or distribute electricity in a specific concession area for a specified period. This period is 35 years for generation concessions granted after 2003, and 30 years for new transmission or distribution concessions. In accordance with the 2013 Concession Renewal Law, generation and distribution concessionaires may renew their concession contracts that were in effect as of 1995 and transmission concessionaires may renew their concession contracts that were in effect prior to and as of 1995 for an additional period of 30 years, provided that the concessionaires agree to amend the concession contracts to reflect certain new terms and conditions established by the law. The 2013 Concession Renewal Law does not impact generation concessions granted after 2003, as they are non-renewable.
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The Concessions Law establishes, among other things,others, the conditions that the concessionaire must comply with when providing electricity services, customers’ rights and the respective rights and obligations of the concessionaire and the granting authority. In addition to the Concessions Law, the concessionaire must also comply with the general regulations governing the electricity sector. The main provisions of the Concessions Law and related ANEEL regulations are summarized as follows:
Adequate service. The concessionaire must render adequate service to all customers in its concession and must maintain certain standards with respect to regularity, continuity, efficiency, safety and accessibility.
Use of land. The concessionaire may use public land or request that the granting authority expropriate necessary private land for the benefit of the concessionaire. In the latter case, the concessionaire must compensate the affected private landowners.
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Strict liability. The concessionaire is strictly liable for all damages arising from the provision of its services.
Changes in controlling interest. The granting authority must approve any direct or indirect change in the concessionaire’s controlling interest.
Intervention by the granting authority. The granting authority may intervene in the concession, through ANEEL, to ensure the adequate performance of services, as well as the full compliance with applicable contractual and regulatory provisions. Once ANEEL determines the intervention, limited to one year, but extendable for additional two years, it must designate a third party to manage the concession. Within 30 days of the determination of the intervention, the granting authority’s representative must commence an administrative proceeding in which the concessionaire is entitled to contest the intervention. The administrative proceeding must be completed within 1 year. The shareholders of the concessionaire under intervention must submit to ANEEL, within 60 days of the determination of the intervention, a recovery and correction plan. If ANEEL approves such plan, the intervention is terminated. In the event ANEEL does not approve the plan, the granting authority may: (i) declare forfeiture of the concession; (ii) determine the spin-off, incorporation, merger or transformation of the concessionaire, incorporation of a subsidiary or assignment of quotas/shares to a third party; (iii) determine the change of control of the concessionaire; (iv) determine a capital increase of the concessionaire; or (v) determine the incorporation of an special purpose company.
Termination of the concession. The termination of the concession agreement may occur by means of expropriation and/or forfeiture. Expropriation is the early termination of a concession for reasons related to the public interest. An expropriation must be specifically approved by law or decree. Forfeiture must be declared by the granting authority after ANEEL or the MME has made a final administrative ruling that the concessionaire, among other things, (i) has failed to render adequate service or comply with an applicable law or regulation, (ii) no longer has the technical, financial or economic capacity to provide adequate service, or (iii) has not complied with penalties assessed by the granting authority. The concessionaire may contest any expropriation or forfeiture in the courts.
A concession agreement may also be terminated (i) through the mutual agreement of the parties, (ii) upon the bankruptcy or dissolution of the concessionaire, or (iii) following a final, non-appealable judicial decision rendered in a proceeding filed by the concessionaire.
When a concession agreement is terminated, all assets, rights and privileges that are materially related to the rendering of electricity services revert to the Brazilian government. Following termination, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated, after deduction of any amounts due by the concessionaire related to fines and damages.anddamages.
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Expiration. When the concession expires, all assets, rights and privileges that are materially related to the rendering of the electricity services revert to the Brazilian government. Following the expiration, the concessionaire is entitled to indemnification for its investments in assets that have not been fully amortized or depreciated as of the expiration.
Penalties.ANEEL regulations govern the imposition of sanctions against electricity sector participants and determine the appropriate penalties based on the nature and importance of the breach (including warnings, fines, temporary suspension from the right to participate in bidding procedures for new concessions, licenses or authorizations and forfeiture). For each infraction, the fines can be up to 2% of the revenue (net of value-added tax and services tax) of the concessionaire in the 12-month period preceding any penalty notice. Some infractions that may result in fines relate to the failure to request ANEEL’s approval to, among other things: (i) execute certain contracts between related parties; (ii) sell or assign the assets related to services rendered as well as impose any encumbrance (including any security, bond, guaranty, pledge and mortgage) on these or any other assets related to the concession or the revenues from electricity services; (iii) effect a change in the controlling interest of the holder of the authorization or concession; and (iv) make certain changes to the bylaws. In the case of contracts executed between related parties that are submitted for ANEEL’s approval, ANEEL may seek to impose restrictions on the terms and conditions of these contracts and, in extreme circumstances, require that the contract be rescinded.
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The New Industry Model Law
TheIn 2004, the New Industry Model Law introduced material changes to the regulation of the electric energy industry, in order to (i) provide incentives to private and public entities to build and maintain generation capacity, and (ii) ensure the supply of electricity in Brazil at low tariffs through a competitive electricity public bidding process. The key elements of the New Industry Model Law include:
· Ensuring the existence of two markets: (i) the regulated market, a more stable market in terms of supply of electricity, and (ii) a market specifically addressed to certain participants (i.e., Free Customers and energy-trading companies), called the free market, that permits a certain degree of competition vis-à-vis the regulated market.
· Restrictions on certain distribution activities, including requiring distributors to focus on their core business of distribution activities in order to promote more efficient and reliable services to captive customers.Captive Customers.
· Elimination of self-dealing by providing an incentive for distributors to purchase electricity at the lowest available prices rather than buying electricity from related parties.
· Upholding contracts executed prior to the New Industry Model Law, in order to provide regulatory stability for transactions carried out before its enactment.
The New Industry Model Law excludes Eletrobras and certain of its subsidiaries from the National Privatization Program, which was created by the Brazilian government in 1990 to promote the privatization process of state-owned companies. However, Provisional Measure No. 814, dated December 28, 2017, changed the New Industry Model Law to reinclude Eletrobras and certain of its subsidiaries in the National Privatization Program. The Brazilian federal government intends to complete the Eletrobras privatization process in 2018.
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For concessionaires of existing generation facilities, the 2013 Concession Renewal Law changesthe nature of these concession contracts. Previously, a generation concessionaire had the right to sell the energy generated by the facilities subject to its concession for profit. In contrast, generation concessions for existing generation facilities (including those renewed pursuant to the 2013 Concession Renewal Law) will not grant concessionaires the right to sell the energy generated by these facilities. Instead, these concessions will only cover the operation and maintenance of the generation facilities. The energy generated by these facilities will be allocated by the Brazilian federal government in quotas to the regulated market, for purchase by distribution concessionaires. For new generation facilities, the concessionaire will have the right to sell the energy produced by the facility.
Parallel Environment for the Trading of Electric Energy
Under the New Industry Model Law, the purchase and sale of electricity is carried out in two different segments: (i) the regulated market, which contemplates that distribution companies will purchase by public auction all the electricity they need to supply their customers; and (ii) the free market, which provides for the purchase of electricity by non-regulated entities (such as the Free Customers and energy traders).
However, the electricity arising from the following is subject to specific rules different from the rules applicable to the regulated market and to the free market: (i) low capacity generation projects located near consumption points (such as certain co-generation plants and small hydroelectric power plants), (ii) plants qualified under the Proinfa Program, an initiative established by the Brazilian government to create incentives for the development of alternative energy sources, such as wind power projects, small hydroelectric power plants and biomass projects, (iii) Itaipu, (iv) Angra 1 and 2 as from 2013 and (v) those generation concession contracts extended or subject to a new bidding process in accordance with the 2013 Concession Renewal Law.
The electricity generated by Itaipu will continue to be sold by Eletrobras to the distribution concessionaires operating in the South, Southeast and Midwest portions of the Interconnected Transmission System. The rates at which Itaipu-generated electricity is traded are denominated in U.S. dollars and established pursuant to a treaty between Brazil and Paraguay. As a consequence, Itaipu rates rise or fall in accordance with the variation of thereal/U.S. dollarexchange rate. Changes in the price of Itaipu-generated electricity are, however, subject to the Parcel A cost recovery mechanism discussed belowas follows under “Distribution Tariffs”.
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Beginning January 2013, the energy generated by nuclear plants Angra 1 and 2 started to be sold by Eletronuclear to the distribution concessionaires at a rate calculated by ANEEL.
The New Industry Model Law does not affect bilateral agreements entered into before 2004.
The Regulated Market
In the regulated market, distribution companies must purchase their expected electricity requirements for their captive customersCaptive Customers in the regulated market through a public auction process. The auction process is administered by ANEEL, either directly or through the CCEE, under certain guidelines provided by the MME.
Electricity purchases are generally made through twothree types of bilateral agreements: (i) Energy Agreements (Contratos de Quantidade de Energia) and, (ii) Availability Agreements (Contratos de Disponibilidade de Energia). and (iii) allocation of energy quotas, as defined by the ANEEL. Under an Energy Agreement, a generator commits to supply a certain amount of electricity and assumes the risk that its electricity supply could be adversely affected by hydrological conditions and low reservoir levels, among other conditions, which could interrupt the supply of electricity. In such case, the generator wouldbe required to purchase electricity elsewhere in order to comply with its supply commitments. Under aan Availability Agreement, a generator commits to makemaking a certain amount of capacity available to the regulated market. In such case, the generator’s revenue is guaranteed and the distributors must bear the risk of a supply shortage. With respect to the third method (introduced by the 2013 Concession Renewal Law), the plants that have had their concession renewed under the 2013 Concession Renewal Law lost the right to sell their energy, and from now on will only receive compensation under the energy quota system as a result of the operation and maintenance of such facilities. As a result, energy generated by these generation concessionaries are passed on to distributors at a lower cost through quotas that match the size of the markets served.
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For the generation plants with expired concessions, which were then subject to a new competitive bidding process, the winner of the competitive bidding process was required, from January 1 to December 31, 2016, to allocate 100% of the energy generated by this plant in quotas to the regulated market, as provided by the 2013 Concession Renewal Law, falling to 70% after January 1, 2017, with the remaining 30% available for the generation concessionaire to sell in the market.
The estimate of demand from distributors is the principal factor in determining how much electricity the system as a whole will contract. A distributor is obligated to contract all of its projected electricity needs. A deviation in actual demand from projected demand could result in penalties to distributors. In the event of under-contracting, the distributor is penalized directly in an amount that increases as the difference between the amount of energy contracted for and actual demand increases. An under-contracting distributor must also pay to meet its demand by purchasing energy in the spot market.
In the event of over-contracting, where the contracted volume falls between 100% and 105% of actual demand, the distributor is not penalized and the additional costs are compensated through increases in its customers’ tariffs. Where the contracted volume is over 105% of actual demand, the distributor must sell energy in the spot market. If the contract price proves lower than the current spot market price, the distributor sells its excess energy for a profit. On the other hand, if the contract price is higher than the spot market price, the distributor sells its excess energy at a loss. ANEEL Normative Resolution No. 711, dated April 19, 2016, allowed distribution companies to renegotiate their energy purchase agreements in the regulated market to reduce the contracted amounts. Recently, Federal Law No. 13,360, dated November 17, 2016, also permitted the sale of excess energy by distribution companies in the free market, but the effectiveness of such rule is still subject to further regulation by ANEEL.
With respect to the granting of new concessions, the newly enacted regulations provide that bids for new hydroelectric generation facilities may include, among other things, the minimum percentage of electricity to be supplied in auctions in the regulated market. Concessions for new generation projects, such as Mauá and Colíder in our case, are non-renewable, meaning that upon expiration, the concessionaire must again complete a competitive bidding process.
The Free Market
The free market covers transactions between generation concessionaires, Independent Power Producers – IPPs, self-generators, energy traders, exporters and importers of electric energy and Free Customers. The free market also covers bilateral agreements between generators and distributors signed under the old model, until they expire. Upon expiration, such contracts must be executed under the New Industry Model Law guidelines.
A consumer that is eligible to choose its supplier may only do so upon the expiration of its contract with the local distributor and with advance notice or, in the case of a contract with no expiration date, upon 15 days’ notice in advance of the date on which the distributor must provide MME with its estimated electricity demand for the year. In the latter case, the contract will only be terminated in the followingthefollowing year. Once a consumer has chosen the free market, it may only return to the regulated system with five years prior notice to its regional distributor, provided that the distributor may reduce such term at its discretion. This extended period of notice seeks to assure that, if necessary, the distributor can buy additional energy in auctions on the regulated market without imposing extra costs on the captive market.
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Private generators may sell electricity directly to Free Customers. State-owned generators may sell electricity directly to Free Customers but are obligated to do so only through private auctions carried out by the state-owned generators exclusively to Free Customers or by the Free Customers.
As mentioned above, recently, Federal Law No. 13,360, dated November 17, 2016, also permitted the sale of excess energy by distribution companies in the free market, but the effectiveness of the rule is still subject to further regulation by ANEEL.
Focusing on the future of the electricity sector, the Ministry of Mines and Energy launched Public Consultation No. 33/2017 with the purpose of obtaining the view of different participants around improvements in the business model of the sector. Issues such as the expansion of the free market and removal of barriers to the entry of its participants, hourly energy price, adequate allocation of risks, security of supply and socio-environmental sustainability were discussed. Further regulation is expected for the years to come.
Regulation under the New Industry Model Law and further rules enacted
A July 2004 decree governs the purchase and sale of electricity in the regulated market and the free market, as well as the granting of authorizations and concessions for electricity generation projects. This decree includes, among other items, regulations relating to auction procedures, the form of power purchase agreements and the mechanism for passing costs through to Final Customers.final customers.
These regulations establish the guidelines under which electricity-purchasing agents must contract their electricity demand. Electricity-selling agents must show that the energy to be sold comes from existing or planned power generation facilities. Agents that do not comply with such requirements are subject to penalties imposed by ANEEL.
These regulations also require electricity distribution companies to contract for 100% of their energy needs primarily through public auctions. In addition to these auctions, distribution companies can purchase limited amounts (up to 10% of their demand) from: (i) generation companies that are connected directly to the distribution company (except for hydroelectric power plants with capacity higher than 30 MW and certain thermoelectric power plants) (ii) electricity generation projects participating in the initial phase of the Proinfa Program, (iii) the Itaipu Power Plant and (iv) quotas from those generation concession contracts extended or subject to a new competitive bidding process in accordance with the 2013 Concession Renewal Law.
The MME establishes the total amount of energy that will be contracted in the regulated market, the number and the type of generation projects that will be auctioned each year.
All electricity generation, distribution and trading companies, independent producers and Free Customers are required to notify MME, by August 1st of each year of their estimated electricity demand or estimated electricity generation, as the case may be, for each of the subsequent five years. In advance of each electricity auction, each distribution company is also required to inform MME of the amount of electricity that it intends to contract in the auction. In addition, distribution companies are required to specify the portion of the contracted amount they intend to use to supply potentially Free Customers.
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Auctions in the Regulated Market
Electricity auctions for new generation projects are held from the third to the seventh year before the initial delivery date of electricity (“A-3 to A-7 Auctions”). Electricity auctions for existing generation projects are held (i) infrom the first to the fifth year before the initial delivery date of electricity (as “A-5 Auctions”), and (ii) in the third year before the commencement of commercial operation (“A-3 Auctions”). Existing power generators hold auctions (i) in the year before the initial delivery date (“A-1A to A-5 Auctions”), and (ii) up to four months before the initial delivery date (“Adjustment Auctions”).
New and existing power generators may participate in the reserve energy auctionsReserve Energy Auctions as long as these generators increase the power system capacity or if they did not achieve commercial operation by January 2008. Invitations to bid in the auctions are prepared by ANEEL in accordance with guidelines established by the MME, including the requirement that the lowest bid wins the auction. Each generation company that participates in the auction executes a contract for the purchase and sale of electricity with each distribution company, in proportion to the distribution companies’ respective estimated demand for electricity, except for the market adjustment and reserve energy auctions.Reserve Energy Auctions.
The contracts for both A-5 and A-3 Auctionsnew generation projects have a term of between 15 and 3035 years, and the contracts for A-1 Auctionsexisting generation projects have a term between 51 and 15 years. Contracts arising from market Adjustment Auctions are limited to a two-year term. The reserve energy contracts are limited to a 35-year term.
The quantity of energy contracted from existing generation facilities may be reduced for three reasons: (i) to compensate for captive customersCaptive Customers that become Free Customers; (ii) to compensate for market deviations from the estimated market projections (up to 4% per year of the annual contracted amount, beginning two years after the initial electricity demand is estimated); and (iii) to adjust thequantitythe quantity of contracted energy in bilateral agreements entered into prior to the enactment of the New Industry Model Law.
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With regard to (i) above, the reduction in net revenue caused when a captive customerCaptive Customer becomes a Free Customer is compensated by the increased amounts that Free Customers are required to pay to use our distribution system. However, a Free Customer may disconnect from our distribution grid (and therefore cease to pay us a distribution tariff) if it chooses to connect directly to the Interconnected Transmission System or if it generates energy for self-consumption and transports this energy without using our distribution grid. Because a Free Customer that connects directly to the Interconnected Transmission System no longer pays us a distribution tariff, we might not be able to fully recover this loss in revenues.
Since 2004, CCEE has conducted twentytwenty-four auctions for new generation projects, fourteeneighteen auctions for energy from existing power generation facilities, sixten auctions for reserve energy in order to increase energy supply security, three auctions from alternative energy sources and eighteenseventeen auctions for market adjustments. No later than August 1 of each year, the generators and distributors provide their estimated electricity generation or estimated electricity demand for the five subsequent years. Based on this information, MME establishes the total amount of electricity to be traded in the auction and determines which generation companies will participate in the auction. The auction is carried out electronically in two phases.
After the completion of the auction (except in the case of reserve energy auction), generators and distributors execute the CCEAR, in which the parties establish the price and amount of the energy contracted in the auction. The price is adjusted annually based on price variations published by the IPCA. The distributors grant financial guarantees to the generators (mainly receivables from the distribution service) to secure their payment obligations under the CCEAR.
Also after completion of the auction,Reserve Energy Auction, the generation concessionaire and the CCEE execute theContrato de Energia de Reserva, in which the parties establish the price and amount of the energy contracted for in the auction. The distributors, Free Customers and self-producing customersthen execute theContrato de Uso da Energia de Reserva (“CONUER”) with CCEE, in order to provide for the terms of the use of the reserve energy. The reserve energy customers grant financial guarantees to CCEE to secure their payment obligations under CONUER.
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The 2013 Concession Renewal Law established that generation concessions entered into prior to 2003 that were not renewed would be subject to a new competitive bidding process and that the energy generated by these facilities will be allocated by the Brazilian federal government in quotas to the regulated market, for purchase by distribution concessionaires. On November 25, 2015, ANEEL carried out a competitive bidding process for the grant of new 30-year concessions of 29 hydroelectric plants in accordance with the 2013 Concession Renewal Law. Until December 31, 2016, 100% of the electricity generated by such 29 hydroelectric plants must be destined to the regulated market and, as of January 1, 2017, the percentage was reduced to 70%. On September 27, 2017, the ANEEL carried another competitive bidding process for the grant of new 30-year concessions of 4 hydroelectric plants in accordance with the 2013 Concession Renewal Law. In this auction, the percentage destined to the regulate market was 70% since the beginning of the concession.
The Annual Reference Value
Brazilian regulation establishes a mechanism ( “Annual(“Annual Reference Value”) that limits the costs that can be passed through to Final Customers.final customers. The Annual Reference Value corresponds to the weighted average of the electricity prices in the A-5 and A-3 Auctions (excluding alternative energy auctions), calculated for all distribution companies.
The regulation establishes the following permanent limitations on the ability of distribution companies to pass-through costs to customers: (i) no pass-through of costs for electricity purchases that exceed 105% of actual demand; (ii) limited pass-through of costs of the acquisition of electricity in the A-3 Auctions, if the amount of purchased energy exceeds 2% of the amount of electricity contracted in the A-5 Auctions; (iii) if the volume contracted from existing generation projects decreases by over 4%, new contracts from new generation projects are afforded limited pass-through.Auctions.
The MME establishes the maximum acquisition price for electricity generated by existing projects. If distributors do not comply with the obligation to fully contract their demand, the pass-through of costs from energy acquired in the short-term market is the lower of the spot market price and the Annual Reference Value.
Electric Energy Trading Convention
The Electric Energy Trading Convention (Convenção de Comercialização de Energia Elétrica) regulates the organization and functioning of the CCEE and defines, among other things, (i) the rights and obligations of CCEE participants, (ii) the penalties to be imposed on defaulting agents, (iii) the means of dispute resolution, (iv) trading rules in the regulated and free markets, and (v) the accounting and clearing process for short-term transactions.
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Restricted Activities of Distributors
Distributors in the Interconnected Transmission System are not permitted to (i) engage in activities related to the generation or transmission of electric energy, (ii) sell electric energy to Free Customers, except for those in their concession area and under the same conditions and tariffs maintained with respect to captive customers, (iii) hold, directly or indirectly, any interest in any other company, corporation or strategic agreement, or (iv)(iii) engage in activities that are unrelated to their respective concessions, except for those permitted by law or the relevant concession agreement. A generator is not allowed to hold more than a 10% equity interest in any distributor. According to Law No. 13,360/2016, distributors are allowed to sell energy to Free Customers. However this legal authorization is still subject to further regulation by ANEEL.
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Elimination of Self-Dealing
Since the purchase of electricity for captive customersCaptive Customers is now performed through auctions in the regulated market, “self-dealing” (under which distributors were permitted to meet up to 30.0%30% of their energy needs using energy that was either self-produced or acquired from affiliated companies) is no longer permitted.
Challenges to the Constitutionality of the New Industry Model Law
The New Industry Model Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court. The Brazilian government moved to dismiss the actions, arguing that the constitutional challenges were moot because they related to a provisional measure that had already been converted into law. To date, the Supreme Court has not reached a final decision and we do not know when such a decision may be reached. While the Supreme Court is reviewing the law, its provisions have remained in effect. Regardless of the Supreme Court’s final decision, certain portions of the New Industry Model Law relating to restrictions on distributors performing activities unrelated to the distribution of electricity, including sales of energy by distributors to Free Customers and the elimination of self-dealing, are expected to remain in full force and effect.
Challenges to the Constitutionality of the 2013 Concession Renewal Law
The 2013 Concession Renewal Law is currently being challenged on constitutional grounds before the Brazilian Supreme Court by the National Confederation of Industry Workers – CNTI (Confederação Nacional dos Trabalhadores na Indústria). It is not possible to predict whether the 2013 Concession Renewal Law shall remain valid in the future. While the Supreme Court is reviewing the law, its provisions remain in full force and effect.
Tariffs for the Use of the Distribution and Transmission Systems
ANEEL regulates access to the distribution and transmission systems and establishes tariffs for the use of these systems. The tariffs are (i) network usage charges, which are charges for the use of the proprietary local grid of distribution companies (“TUSD”) and (ii) tariffs for the use of the transmission system, which is the Interconnected Transmission System and its ancillary facilities (“TUST”).
TUSD
Users of a distribution grid pay the distribution concessionaire a tariff known as the TUSD (Tarifa de Uso dos Sistemas Elétricos de Distribuição). The TUSD is divided into two parts: one related to the contracted power in R$/kW and otheranother related to the regulatory charges in R$/kWh. The amount paid by the users of a distribution grid is calculated by multiplying the maximum contracted power for each of the customer’s points of connection to the concessionaire’s distribution grid, by the tariff in R$/kW, plus the product of the power consumption by the tariff in R$/kWh, per month.
In relation to the captive customers,Captive Customers, the TUSD is part of the supply tariff that is calculated based on the voltage used by each customer.
TUST
The TUST (Tarifa de Uso do Sistema de Transmissão)is paid by distribution companies, generators and Free Customers to transmission companies for the use of the Interconnected TransmissionSystemTransmission System (electrical transmission system with a voltage equal or higher than 230 kV). This tariff is revised annually according to (i) the location of the user of the Interconnected Transmission System and (ii) theannual revenues that a transmission company is permitted to collect for the use of its assets in the Interconnected Transmission System. The ONS, an entity that represents all transmission companies that own assets in the Interconnected Transmission System, coordinates the payment of transmission tariffs to these transmission companies. Users of the Interconnected Transmission System sign contracts with the ONS, which allows them to use the transmission grid in return for paying TUST.
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Distribution Tariffs
Distribution tariff rates to Final Customersfinal customers (including the TUSD) are subject to review by ANEEL, which has the authority to adjust and review these tariffs in response to changes in energy purchase costs and market conditions. When adjusting distribution tariffs, ANEEL divides the costs of distribution companies into (i) costs that are beyond the control of the distributor, or (“Parcel A costs”), and (ii) costs that are under control of distributors (“Parcel B costs”). ANEEL’s tariff readjustmentadjustment formula treats these two categories differently.
Parcel A costs include, among others, the following:
· costs of electricity purchased by the concessionaire to attend captive customers,Captive Customers, in accordance to the regulatory model in force;
· charges for the connection to and use of the transmission and distribution grids; and
· energy sector regulatory charges.
Parcel B costs include, among others, the following:
· a component designed to compensate the distributor for the investments made by the distributor on the concession assets;
· depreciation costs; and
· a component designed to compensate the distributor for its operating and maintenance costs.
Each distribution company’s concession agreement provides for an annual readjustmentrevision (reajuste anual). In general, Parcel A costs are fully passed through to customers. Parcel B costs, however, are only adjusted for inflation in accordance with the IGP-MIPCA Index, minus the X factor.
Electricity distribution concessionaires are also entitled to periodic tariff revisions (revisão periódica) every four or five years. These revisions are aimed at (i) assuring necessary revenues to cover efficient Parcel B operational costs and adequate compensation for investments deemed essential for services provided within the scope of each such company’s concession and (ii) determining the “X factor”..The fifth amendment to our concession agreement, which establishes the renewal of our concession agreement, determines the Periodic Tariff Review every five years.
The X factor for each distribution company is calculated based on the following components:
· P, based on the concessionaire’s productivity, which is measured in terms of increases in assets (kms of power grid), the total volume of energy sold, and the number of Final Customersfinal customers to which energy is sold;
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· T, based on the trajectory of the concessionaire’s operating costs, measured as the difference between the cost benchmarks established by ANEEL and the concessionaire’s actual operating costs; and
· Q, based on quality target indicators that measure the interruption of energy supply to Final Customers.final customers, and other quality indicators.
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In addition, a distribution concessionaire is entitled to an extraordinary tariff review (revisão extraordinária) on a case-by-case basis, to ensure its financial stability and compensate it for unpredictable costs, including taxes, which significantly change its cost structure. Extraordinary tariff adjustments were granted (i) in June 1999 to compensate for increased costs of electricity purchased from Itaipu as a result of the devaluation of thereal against the dollar,dollar; (ii) in 2000 to compensate for the increase in Social Security Financing Contribution (Contribuição para o Financiamento da Seguridade Social - COFINS) from 2% to 3%,; (iii) in December 2001 to compensate for losses caused by the Rationing Program,Program; (iv) in January 2013, due to the enactment of 2013 Concession Renewal Law, andLaw; (v) in March 2015, to compensate the costs related to the quotas of the Electric Development Account (CDE)and increased costs with the purchase of energy,. and (vi) in March 2017, to compensate the amount unduly included in the tariffs for captive consumers in 2016,referring to the Angra III plant.
Since October 2004, on the date of a subsequent tariff readjustmentadjustment or tariff revision, whichever occurs earlier, distribution companies have been required to execute separate contracts for the connection and use of the distribution grid and for the sale of electricity to their potentially Free Customers.
Tariff Flags (Bandeiras Tarifárias)
Effective as of January 1, 2015, a new system has been introduced by the ANEEL to permit distribution concessionaires to pass on to their Final Customerfinal customer certain variable cost increases attributable to changes in hydrological conditions in Brazil, prior to the formal tariffs periodic revisions made by ANEEL.
In accordance with this model, a green, yellow or red flags,flag, as determined by ANEEL, is included in invoices sent to Final Customers,final customers, reflecting nationwide hydrological conditions (except for the StatesState of Amazonas, Amapá and Roraima). If a green flag is added into Final Customers’to final customers’ invoices due to satisfactory hydrological conditions, no additional charges are added. On the other hand, if these invoices contain yellow or red flags, this will indicateindicates that distribution concessionaires are facing higher variable costs from the acquisition of electricity and have passed certainwill pass these costs on to Final Customers.final customers.
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Incentives
In 2000, a Federal decree created the Thermoelectric Priority Program, (Programa Prioritário de Termoeletricidade, or (““PPT”), for the purposes of diversifying the Brazilian energy matrix and decreasing Brazil’s strong dependence on hydroelectric plants. The incentives granted to the thermoelectric plants included in the PPT are:were: (i) guarantee of gas supply for 20 years, as per a MME regulation, (ii) assurance that the costs related to the acquisition of the electric energy produced by thermoelectric plants will be passed on to customers through tariffs up to the normative value established by ANEEL, and (iii) guarantee of access to a special BNDES financing program for the electric energy industry.
In 2002, the Brazilian government established the Proinfa Program to encourage the generation of alternative energy sources. Under the Proinfa Program, Eletrobras shallwould purchase the energy generated by alternative sources for a period of 20 years. In its initial phase, the Proinfa Program iswas limited to a total contracted capacity of 3,300 MW. In its second phase, which willshould start after the 3,300 MW3,300MW cap has been reached, the Proinfa Program intends to purchase up to 10% of Brazil’s annual electric energy consumption from alternative sources. The first phase of the Proinfa program commenced in 2004.2004 and it so far has supported the construction of 131 alternative energy plants which is expected to reach the production of 11.2 million MWh. According to a decision of ANEEL, the total investment to the Proinfa Program in 2018 will be R$ 3.4 billion.
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Energy Sector Regulatory Charges
State and Municipal ICMS Compensation
From January 1, 2010 to December 31, 2012, distributors were required to pay a levy in the amount of 0.3% of their annual operating revenues, which were transferred to certain states and municipalities in compensation with losses in tax revenues that these states and municipalities suffered when they became connected to the Interconnected Transmission System, due to the fact that they no longer receive energy from locally-generated sources. These funds must be used by the states and municipalities to provide increased access to electricity, to finance social and environmental projects, and to conduct research and development and support energy efficiency initiatives.
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EER
TheEncargo de Energia de Reserva(“EER”) is a regulatory charge designed to raise funds for energy reserves that have been contracted through CCEE and which are deposited in the Reserve Energy Account (Conta de Energia de Reserva – CONER). These energy reserves, which are mandatory, were created in order to attempt to ensure a sufficient supply of energy in the Interconnected Transmission System. The EER shall be collected from Final Customersfinal customers of the Interconnected Transmission System. Beginning in 2010, this charge has been collected on a monthly basis.
RGR Fund
In certain circumstances, electric energy companies are compensated for certain assets used in connection with a concession if the concession is revoked or is not renewed. In 1971, the Brazilian Congress created a reserve fund designed to provide these compensatory payments (“RGR Fund”). In February 1999, ANEEL established a fee requiring public-industry electric companies to make monthly contributions to the RGR Fund at an annual rate equal to 2.5% of the company’s fixed assets in service, not to exceed 3% of total operating revenues in any year. Since the enactment of the 2013 Concession Renewal Law, the RGR Fund has been used to fund the compensations arising from the termination of non-renewed concessions. The 2013 Concession Renewal Law also allowed the funds from the RGR Fund to be transferred to the CDE.
According to 2013 Concession Renewal Law, as from January 1, 2013, the concession contracts from concessionaires of (i) distribution; (ii) transmission which competitive bidding process occurred after September 12, 2012; and (iii) transmission and generation which had their concession contract renewed or had their underlying facilities subject to a new competitive bidding process are no longer obliged to pay the annual RGR fee.
UBP
Some hydroelectric generation enterprises (except small hydroelectric power plants) are required to make contributions for using a public asset,Uso de Bem Público (“UBP”) according to the rules of the corresponding public bidding process for the granting of concessions. Eletrobras receives the UBP payments in a specific account. See Note 2728 to our audited consolidated financial statements.
ESS
The costs related to maintaining system reliability and stability when thermoelectric plants generate energy to meet demand in the National Connection System (SIN) are called System Service Charges, orEncargos de Serviços de Sistema (ESS). These amounts are paid by each entity that purchases energy in the spot market (CCEE), proportional to each such entity’s consumption.
ESS is expressed in R$/MWh and paid only to thermoelectric plants that generate energy in response to requests by the Electricity System National Operator (ONS).
CDE
In 2002, the Brazilian government instituted the Electric Energy Development Account,Conta de Desenvolvimento Energético (“CDE Account”). The CDE Account is funded by (i) annual payments made by concessionaires for the use of public assets, (ii) penalties and fines imposed by ANEEL, (iii) the annual fees paid by agents offering electric energy to Final Customers,final customers, by means of an additional chargeadded to the tariffs for the use of the transmission and distribution grids and (iv) the credits held by the federal government against Itaipu. The CDE Account was originally created, amongst others, to promote the availability of electric energy services to all of Brazil and the competitiveness of the energy produced by alternative sources. The CDE is regulated by the executive branch, andwas managed by Eletrobras.Eletrobras until April 30, 2017 and is managed by CCEE as of May 1, 2017, pursuant to Federal Law No. 13,360/2016. This charge had been substantially reduced by the 2013 Concession Renewal Law (approximately 75% compared to its December 31, 2011 amount) in an attempt to reduce the cost of electricity paid by Final Customers,final customers, among others. The 2013 Concession Renewal Law also allowed the funds from the RGR Fund to be transferred to the CDE Account, provided that the Federal Treasury would also contribute with the CDE Account and permittedpermit the funds deposited in the CDE Account to be used in support of the electricity generation program in non-integrated electric grids (sistemas elétricos isolados). as well as to partially offset the increased costs borne by distribution concessionaires for the purchase of energy in the spot market as a result of the non-renewal of generation concessions due to the 2013 Concession Renewal Law.
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On March 7, 2014, Thethe Brazilian government also permitted the transfer to distribution concessionaires of funds deposited in the CDE Account to cover their respective costs arising from the involuntary exposure to the spot market in January 2014 as a result of poor hydrological conditions in 2013 and 2014, which mandated the acquisition of thermoelectric energy at higher prices in the spot market, costs which distribution concessionaires were not able to pass on to final customersFinal Customers through regular Retail Tariffs prior to formal tariffs periodic revisions made by ANEEL. As of December 31, 2014, Eletrobras released to us R$114.6 million from the CDE Account for this specific purpose.
Distribution concessionaries will be able to pass on to its Final Customerfinal customer a CDE Account charge, to the extent necessary to repay their respective financing obligations contracted by the CCEE through the ACR Account. See “Regulated Market Account – ACR Account.”
On February 27, 2015, ANEEL approved a significant increase of the CDE fee charged to cover all of these additional costs supported by the CDE Account, which were aggravated by the lack of contribution from the Brazilian Federal Treasury. ABRACE, an association of Free Customers filed lawsuits to contest the increase of the CDE fee and this litigation remains ongoing. Since July 2015, the Free Customers associated with ABRACE benefit from an injunction suspending the increase of the CDE fee. Associations of distributors of energy (including ABRADEE, with whom Copel Distribuição is associated) also obtained injunctions suspending its obligation to withhold such CDE fees while ABRACE´sand other consumers’ injunction remains in force.
Federal Law No. 13,360/2016 established that the Federal Government must prepare a plan for a structural reduction of the CDE charge until December 31, 2017, and it also provided that the revenues, expenses and beneficiaries of the CDE Account must be published monthly by CCEE. More specifically, promulgation of Law No. 13,360, dated November 17, 2016, implemented a series of changes in the structure of the CDE rules, causing the fund to abandon its role as a source of funds for (i) the amortization of financial operations linked to the indemnity for concessions reversal or (ii) the affordable tariff policy. Currently, the scope of the CDE is to compensate for the discounts applied in the transmission tariffs, to provide funds for the payment of amounts related to the management and movement of CDE, CCC and RGR by CCEE; and to compensate the tariff impact of the reduced load density of the rural electrification cooperatives market.
Regulated Market Account – ACR Account.
On April 2014, the Brazilian government created the Regulated Market Account,Conta no Ambiente de Contratação Regulada – Conta-ACR (“ACR Account”), to assist distribution concessionaires to cover their respective costs for the acquisition of thermoelectric energy for the period from February 2014 to December 2014, incurred as a result of poor hydrological conditions. Distributorsincurred higher costs as a result of adverse hydrological conditions because they were required to buy thermoelectric energy at higher prices in the spot market, and were unable to pass all these costs on to final customersFinal Customers prior to a formal tariff periodic revision made by ANEEL. To fund the ACR Account, the Brazilian federal government authorized the CCEE to enter into credit agreements with Brazilian certain Brazilian financial institutions. An aggregate of R$21.221.7 billion, composed of three separatenine tranches, has been deposited in the ACR Account. Distribution concessionaires will repayconcessionairesare reimbursing this financing contracted byfinancingfrom the CCEE 2015 tariff process,through the application of monthly additional CDE Account charges to its Final Customers,final customers, for a period of 54 months, following the completion of their respective tariff adjustment procedures in 2015. As of December 31, 2014,ofapproximately 60 months. In 2017, the CCEE released to us R$1,137.5 milliondid not release funds from the ACR Account.Account to us.
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Itaipu Transmission Fee
The Itaipu Hydroelectric Plant has an exclusive transmission grid and is not part of the Interconnected Transmission System. Companies that are entitled to receive electricity from Itaipu pay a transmission fee in an amount equal to their proportional share of the Itaipu generated electricity.
Use of Water Resources Tax
Holders of concessions and authorizations that allow for the exploitation of water resources must pay a total tax of 6.75%7.00% of the value of the energy they generate, which for the purposes of this calculation is based on a rate set by ANEEL. Beginning on January 1, 2015,2018, ANEEL set this rate at R$85.26/74.03/MWh. The proceeds of this tax are shared among the states and municipalities where the plant or the plant’s reservoir is located, as well as with certain federal agencies.
ANEEL Inspection Fee (TFSEE)
The ANEEL Inspection Fee is an annual fee due by the holders of concessions, permissions or authorizations equal to an ANEEL determined percentage of their revenues. The ANEEL Inspection Fee requires these holders to pay up to 0.5%0.4% of their annual revenue to ANEEL in 12 monthly installments.
Default on the Payment of Regulatory Charges
The failure to pay required contributions to the RGR Fund, Proinfa Program or CDE Account or to make certain payments, such as those due from the purchase of electric energy in the regulated market or from Itaipu, will prevent the defaulting party from receiving readjustmentsadjustments or reviews of their tariffs (except for an extraordinary review) and will also prevent the defaulting party from receiving funds from the RGR Fund or CDE Account. We comply with payment obligations related to Regulatory Charges.
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Energy Reallocation Mechanism
The Energy Reallocation Mechanism, orMecanismo de Realocação de Energia attempts to mitigate the risks borne by hydroelectric generators due to variations in river flows (hydrological risk).
Under Brazilian law, each hydroelectric plant is assigned a determined amount of “assured energy”, according to an energy supply risk criteria defined by MME, based on historical river flow records. The assured energy also represents the maximum energy that can be sold by the generator, which is set forth in each concession agreement, irrespective of the volume of electricity actually generated by the facility.
The MRE tries to guarantee that all participating plants receive the revenue corresponding to their assured energy, irrespective of the volume of electricity generated by them. In other words, the MRE effectively reallocates the electricity, transferring the surplus from those who have produced in excess oftheir assured energy to those that have produced less than their assured energy. The relocation, which occurs in the Interconnected Transmission System, is determined by the ONS, considering the nationwide electricity demand and hydrological conditions, regardless of the power purchase agreement of each individual generator. The volume of electricity actually generated by the plant, whether more or less than their assigned assured energy quotient, is priced pursuant to a tariff known as the “Energy Optimization Tariff”, designed to cover only the variable operation and maintenance costs of the plant, so that generators are largely unaffected by the actual dispatch of their plants.
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Each hydroelectric plant which has its concession contract renewed in accordance to 2013 Concession Renewal Law will no longer participate in the MRE, and the hydrological risk from those plants will be borne by the distribution concessionaires under the National Interconnected Power Grid. For the generation plants with expired concessions, which were subject to a new competitive bidding process under the 2013 Concession Renewal Law, 30% of the generated energy available for the generation concessionaire to sell in the market is also subject to the MRE hydrological risk allocation mechanism. This risk does not impact our distribution business, since we are allowed to increase the tariffs of our distribution customers to compensate any costs arising from this hydrological risk.
Research and Development
The companies holding concessions and permissions for distribution of electricity must invest a minimum of 0.50% of their annual net operational revenues in research and development and 0.50% in energy efficiency programs. Beginning on January 1, 2016,2023, these percentages will become 0.75% and 0.25%, respectively.
A company holding concessions and authorizations for generation and transmission of electricity must invest a minimum of 1% of its annual net operational revenues in research and development. A company that generates electricity exclusively from small hydroelectric power plants, cogeneration or alternative energy projects is not subject to this requirement.
The amount to be invested in research and development must be distributed as follows:
· 40% to the company research and development projects, under the supervision of ANEEL;
· 40% to the Ministry of Sciences and Technology, to be invested in national research and development projects; and
· 20% to the MME, to defray EPE.
In 2017, we spent R$54.1 million on research and development, while in 2016 we spent R$52.6 million and in 2015 we spent R$72.9 million.
Environmental Regulations
The Brazilian Federal Constitution includes environmental matters among the matters that are subject to concurrent legislative competence, meaning that the Brazilian federal government enacts general rules, which are supplemented by rules passed by states; municipalities, in turn, enact local rules or supplement federal and/or state legislation.
The Federal Environmental Crimes Act, which took effect in 1998, establishes a general framework of liability for environmental crimes. Federal laws and statutes have established the National System for Management of Water Resources and the National Council of Water Resources to address themajorthe major environmental issues facing the hydroelectric sector and users of water resources. In 2000, theBrazilian government created an independent agency, the National Water Agency, to regulate and supervise the use of water resources.
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The Brazilian Forestry Code and related regulations establish rules regarding the maintenance and acquisition of areas affected by hydroelectric plant reservoirs. These regulations may result in increased maintenance, reforestation and expropriation costs to energy industry concessionaires. We have been developing conservation actions in our power plants, as established in the Forestry Code, since their construction. In addition, Paraná State law requires a mandatory environmental audit of companies whose activities may impact the environment within the state.
A violator of an environmental law may be subject to administrative and criminal sanctions and, in case environmental damage occurs, will have an obligation to repair or provide compensation to the affected party. Administrative sanctions may include substantial fines and the suspension of activities, while criminal sanctions may include fines and, for individuals, including for directors and employees of companies that commit environmental crimes, possible imprisonment.
Our energy generation, distribution and transmission facilities are subject to environmental licensing procedures, which may include the preparation of environmental impact assessments before such facilities are constructed. Once the respective environmental licenses are obtained, their maintenance is still subject to the compliance with certain requirements. We were one of the first energy concessionaires in Brazil to provide an environmental impact assessment and report in connection with the construction of a power plant (Segredo Power Plant, 1987) and to maintain excellence in the implementation of environmental programs.
Item 4A. Unresolved Staff Comments
None.
Item 5. Operating and Financial Review and Prospects
The information presented as follows has been derived from our consolidated statementstatements of income for the years ended December 31, 2014, 20132017, 2016 and 2012 has2015, that have been prepared in accordance with IFRS as issued by the IASB. For more information see “Presentation of Financial and Other Information” and Note 23 to our audited consolidated financial statements for the year ended December 31, 2014.2017.
We have restated our financial statements for the fiscal year ended December 31, 2015 and December 31, 2016, to correct our accounting for an investment made by our subsidiary UEG Araucária Ltda., and we have identified material weaknesses in our internal control over financial reporting. For additional information, see Note 4.1 to our audited consolidated financial statements and “Item 15. Controls and Procedures”.
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Brazilian Economic Conditions
All of our operations are in Brazil, and we are affected by general Brazilian economic conditions. In particular, the general performance of the Brazilian economy affects demand for electricity, and inflation affects our costs and our margins. The Brazilian economic environment has been characterized by significant variationsfaced consecutive decreases in economicBrazilian GDP growth rates, with very low growth from 2001 through 2003, an economic recovery that led to consistent growth from 2004 to 2009. Since then, the Brazilian GDP growth has fluctuated, from 0.9% growth in 2012, toincrease of 2.3% in 2013 and 0.1% in 2014.
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Table2014 and a decrease of Contents3.8% in 2015. The growth rate was equally negative in 2016, with a decrease of 3.6%. The economic environment showed signs of recovery in 2017, with an increase of 1.0% in growth rate, and the lowest inflation rate and exchange rate variation of thereal vs. U.S. dollar of the last few years.
The following table shows selected economic data for the periods indicated:
| Year ended December 31, | Year ended December 31, | ||||
| 2014 | 2013 | 2012 | 2017 | 2016 | 2015 |
Inflation (IGP-DI) | 3.78% | 5.52% | 8.10% | |||
Inflation (IGP-DI) | (0.42)% | 7.18% | 10.70% | |||
Appreciation (depreciation) of therealvs. U.S. dollar | (11.81)% | (12.77)% | (8.21)% | (1.48)% | 19.81% | (31.98)% |
Period-end exchange rate – US$1.00(1) | 2.6562 | 2.3426 | 2.0435 | |||
Period-end exchange rate – US$1.00(1) | 3.3080 | 3.2591 | 3.9048 | |||
Average exchange rate – US$1.00 | 2.3599 | 2.1741 | 1.9588 | 3.2031 | 3.4500 | 3.3876 |
Change in realGDP | 0.1% | 2.3% | 0.9% | 1.0% | (3.6)% | (3.8)% |
Average interbank interest rates(2) | 10.83% | 8.18% | 8.30% | |||
Average interbank interest rates(2) | 9.80% | 14.05% | 13.46% |
(1) Thereal/U.S. dollar exchange rate at April 14, 201530, 2018 was R$3.08803.4811 per US$1.00.
(2)Calculated in accordance with Central Clearing and Custody House, orCentral de Custódia e Liquidação Financeira de Títulos(“CETIP”), methodology (based on nominal rates).
Sources:FGV ‒ Fundação Getúlio Vargas, the Brazilian Central Bank, the Brazilian Geography and Statistics Institute IBGE and CETIP.
Rates and Prices
Our results of operations are significantly affected by changes in the prices at which our generation business sells energy, and by the prices at which our distribution business buys and resells energy.
Our generation business sells energy at unregulated prices in the regulated market, in the Free Market and in the Spot Market. Our generation business allocates the amount of energy that it sells in each of these markets seeking to maximize returns, based on factors such as: (i) the requirements of its concession contracts, many of which set a minimum percentage of energy generated in a particular concession that must be sold in the regulated market; (ii) the volume of energy that we plan to sell to Free Customers for a given year; and (iii) the outlook of the short-term, medium-term and long-term for energy prices generally. Although sales in the Free Market and the Spot Market are not directly regulated, they are influenced by energy regulatory policy. The prices at which our generation business sells energy are not regulated.
Our distribution business purchases enough energy to meet 100% of the demand we forecast for our Final Customersfinal customers in auctions at unregulated prices in the regulated market. Our distribution business resells that energy to Final Customersfinal customers at regulated tariffs that take into consideration the price at which the energy was purchased. If our forecasts fall short of the actual electricity demand of our Final Customers,final customers, we may be forced to make up for the shortfall by entering into short-term agreements to purchase electricity in the spot market. If our forecasts exceed the actual demand of our Final Customers, our distributionfinal customers, ourdistribution business sells the excess energy in the Spot Market. Except for possible future effects brought by the 2013 Concession Renewal Law, the margins in our distribution business tend to be relatively stable due to the regulated nature of the distribution business, while the margins in our generation business are typically larger but less stable, since they are substantially market regulated.
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Sales to Final Customersfinal customers (which include sales by our distribution business to captive customersCaptive Customers, sales by our generation business and sales by our generationtrading business to Free Customers) represented approximately 52.3%55.9% of the volume of electricity we made available in 2014,2017, and accounted for 50.0%59.6% of our energy sales revenues. Almost all of such sales were to captive customers.Captive Customers. For more information, see “Item 4. Information on the Company — The Brazilian Electric Power Industry — Distribution Tariffs”. In general, if our costs for energy increase, the tariff process permits us to recover these costs from our customers through higher rates in future periods. However, if we do not receive tariff increases to cover our costs, if the recovery of these costs is delayed, or if our Board of Directors elects to reduce the tariff increase awarded by ANEEL,our profits and cash flows may be adversely affected.
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ANEEL modifies our Retail Tariffs annually, generally in June. Since January 2010,2013, the adjustments have been as follows.
·
| In January 2013, due to the enactment of 2013 Concession Renewal Law, we were subject to an extraordinary revision that has been approved by ANEEL. The average impact of this extraordinary review in the tariffs we charge our customers was a decrease of 19.28% which caused a reduction of approximately 14.4% in our distribution revenues since the difference was paid for with funds from the federal government. |
· | In June 2013, ANEEL approved the annual revision of our Retail Tariffs, increasing them by an average of 13.08%, of which 11.40% related to the tariff increase and 1.68% referred to an increase in recovery of deferred regulatory accounts (CVA). After giving effect to the recovery of Parcel A costs, the average effect of this tariff readjustment on our Captive Customers was an increase of 14.61%. However, Copel Distribuição requested a partial deferral of this adjustment, which was authorized by ANEEL and approved on July9, 2013. The amount of R$255.9 million was therefore deferred, and to be included as a financial component in the 2014 annual revision. This deferral reduced the average effect of the tariff adjustment to 9.55%. |
· | In June 2014, ANEEL approved the annual adjustment of our Retail Tariffs, increasing them by an averageof 35.38%, of which 25.05% related to the tariff increase and 10.34% related to an increase in recovery of deferred regulatory accounts (CVA). After giving effect to the recovery of Parcel A costs, the average effect of this tariff adjustment on our Captive Customers was an increase of 39.71%. However, Copel Distribuição requested a partial deferral of this adjustment, which was authorized by ANEEL and approved on July22, 2014. The amount of R$898.3 million was therefore deferred, and to be included as a financial component in the 2015 annual readjustment. This deferral reduced the average effect of the tariff revision to 24.86%. |
· | In March 2015, ANEEL approved an extraordinary revision due to a series of events that significantly impacted the distribution concessionaires’ costs, which were not originally foreseen in the 2014 Retail Tariff increase, such as the increase of Itaipu tariffs (46.14%) and higher prices to purchase energy in recent energy auctions. Copel Distribuição’s average tariff revision approved by ANEEL was 36.79% starting from March 02, 2015. Of this total, 22.14% relatedto CDE Account chargesthat have been passed to customersand 14.65% relates to (i) Itaipu’s tariff increase and (ii) thehigher prices paid by us to purchase energy in recent energy auctions that have been passed to customers. |
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· | In June 2015, ANEEL authorized theannual revision of Copel Distribuição’s tariff to final customers, increasing them by an average of 15.32%, of which (a) 20.58% related to the inclusion of the financial components, which will be recovered in the 12 months subsequent to the adjustment (including the amount of R$935.3 million corresponding to the deferrals in 2013 and 2014), (b) 0.34% related to the restatement of Portion B, (c) (3.25)% related to the adjustment of Portion A, and (d) (2.35)% reflected the removal of the financial components from the previous process. The adjustment was fully applied to Copel Distribuição’s tariffs as of June 24, 2015. |
· | In June 2016, ANEEL approved the fourth periodic review of our Retail Tariffs, decreasing them by 12.87%, of which: (1.73)% related to the inclusion of financial components; 4.48% due to the update of Portion B; (2.57)% related to the update of Portion A; and (13.05)% reflecting the removal of the financial components of the previous tariff process. |
· | In March 2017, ANEEL approved an extraordinary tariff revision to correct the amount unduly included in the tariffs for captive consumers in 2016. The return corresponded to the energy that was to be generated by the Angra III power plant; however, the plant was not yet in commercial operation. The refund of the amount charged the most was made in a single installment during the month of April 2017, and, as of May 2017, the tariffs were adjusted to disregard the amount that was being charged. The decision, of extraordinary character, affected 90 distributors of electric power of the country. Copel's retail tariff was reduced by an average of 11.8% during April 2017, and in May 2017, the tariff was close to its previous value, retaining an average discount of 1.27% until June 2017. |
· | In June 2017, ANEEL approved the annual revision of our Retail Tariffs, increasing them by an average of 3.13%, of which 3.86% related to the tariff increase and (0.73)% related to the inclusion of financial components.After the removal of the financial components of the previous tariff process, the average effect of this tariff adjustment on our Customers was an increase of 5.85%. |
Purchase and Resale of Energy
Our distribution business purchases energy from generation companies and resells this energy to Final Customersfinal customers at regulated rates. For more information, see “Item 4. Information on the Company— Business—Generation” and “Item 4. Information on the Company—Business—Purchases”. Our major long-term contracts or purchase obligations are described below.as follows.
· | We purchase energy from Itaipu at prices that are determined based on the Itaipu project’s costs, including servicing its U.S. dollar-denominated debt. In 2017, our electricity purchases from Itaipu amounted to R$1,124.8 million; |
· | Our distribution business is required to purchase a large portion of its energy needs from the regulated market. For more information, see “Item 4. Information on the Company — The Brazilian Electric Power — Industry — Auctions in the Regulated Market”. |
·We purchase energy from Itaipu at prices that are determined based on the Itaipu project’s costs, including servicing its U.S. dollar-denominated debt. In 2014, our electricity purchases from Itaipu amounted to R$756.1 million.
·Our distribution business is required to purchase a large portion of its energy needs from the regulated market. For more information, see “Item 4. Information on the Company — The Company — Distribution — Auctions in the Regulated Market”.
Under current legislation, the amount that our distribution business charges Final Customers is composed of two fees: a fee for the actual energy consumed and a fee for the use of our distribution grid. Since the regulated rates at which our distribution business sells energy to Final Customersfinal customers are substantially the same as the rates at which it purchases energy (after accounting for deductions and the cost of energy purchased for resale), our distribution business does not generate operating profit from the sale of electricity to Final Customers.final customers. Rather, our distribution business generates operating profit principally by collecting tariffs for the use of our distribution grid.
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Impact of the CRC Account
One of our most significant assets consists of the obligations of the State of Paraná under an agreement that was last amended in January 2005.October 2017. These obligations derive from amounts we were entitled to recover under a prior regulatory regime, and as a result they are referred to as the recoverable rate deficit account or “CRC Account” (Conta de Resultados a Compensar). As of December 31, 2014, the outstanding balance of the CRC Account was R$1,344.1 million. The balance is adjusted for IGP-DI, bearsplus interest at 6.65%, per year, and is payable in monthly installments until April 2025. If the State of Paraná fails to make payments on a timely basis, we may apply dividends we owe to the State of Paraná in its capacity as our shareholder against amounts it owes us under the CRC Account agreement.
In June 2016, as per the request of the Paraná State Government, our Board of Directors approved an amendment to the CRC Agreement, contingent upon the approval of the Brazilian Department of Treasury, comprising: (i) a grace period from April 2016 to December 2016, in which no principal and interest amounts were paid under the CRC Agreement; and (ii) a grace period from January 2017 to December 2017, in which amounts corresponding exclusively to the interest were paid monthly, but no principal amounts were paid. All other provisions of the CRC Agreement were maintained as they were, including the maintenance of the current correction and interest rates, thus not affecting the global net present value of such agreement.
The Company and the State of Paraná formalized the above-mentioned amendment on October 31, 2017, after the consent from the Brazilian Department of Treasury.The State of Paraná complied with the agreed terms of such amendment and made monthly interest payments until December 2017.As of December 31, 2017, the outstanding balance of the CRC Account was R$1,516.4 million.
As of January 1, 2018, there were 88 monthly installments left. For additional information, see Note 8 to our audited consolidated financial statements.
Special Obligations
The contributions received from the federal government and our customers exclusively for investment in our generation assets, transmission and distribution grid are named as special obligations. We record the amount of these contributions on our statement of financial position as a reduction of our intangible and financial assets, under the caption “special obligations”, and, upon the conclusion or termination of the operating concession granted to us, the amount of these contributions is offset against intangible and financial assets. The amount we recorded as special obligations as of December 31, 20142017 was R$224.02,871.5 million as a reduction of intangible assets and R$2,269.079.5 million as a reduction of financial assets.
Restatements
We have restated our financial statements for the fiscal year ended December 31, 2015 and December 31, 2016, to correct our accounting for an investment made by our subsidiary UEG Araucária Ltda., and we have identified material weaknesses in our internal control over financial reporting. For additional information, see Note 4.1 to our audited consolidated financial statements and “Item 15. Controls and Procedures”.
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Critical Accounting PoliciesCRITICAL ACCOUNTING POLICIES
In preparing our financial statements, we make estimates concerning a variety of matters as referred to in Note 2.43.4 to our audited consolidated financial statements. Some of these matters are highly uncertain, and our estimates involve judgments we make based on the information available to us. We have discussed in “Overview” above certain accounting policies relating to regulatory matters. In the discussion below, we have identified several other matters for which our financial information would be materially affected if either (i) we reasonably used different estimates or (ii) in the future we change our estimates in response to changes that are reasonably likely to occur.
The discussion below addresses only those estimates that we consider most important based on the degree of uncertainty and the likelihood of a material impact if we used a different estimate. There aremanyare many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation. Please see Note 2.43.4 to our audited consolidated financial statements included herein for a more detailed discussion of the application of these and other accounting policies.
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Property, Plant and Equipment
We have adopted the deemed cost methodology to determine the fair value of Copel Geração e Transmissão’s property, plant and equipment, specifically for the generation business as of the date of transition of our financial statements to IFRS (January 1, 2009). These assets are depreciated according to the linear method based on annual rates set forth and reviewed periodically by ANEEL, which are used and accepted by the market as representative of the economic useful life of the assets related to concession’s infrastructure, limited to the term of said concession, when applicable. The estimated useful life, the residual amounts, and depreciation are reviewed as of theeach reporting date, and the effect of any changes in estimates is recorded prospectively.
Accounting for concession arrangements
We account for our concession agreements for transmission and distribution business in accordance with IFRIC 12 - Service Concession Agreements.
IFRIC 12 establishes that electric energy utilities should record and measure revenues according to IAS 11 - Construction Contracts and IAS 18 - Revenues, even when governed by a single concession agreement. When we make investments in the infrastructure used in the power transmission and distribution services we perform pursuant to our concession agreements, we capitalize these investments as intangible assets and financial assets, and we recognize construction revenue and construction costs in connection with these investments. Intangible assets represent the right to access and to operate infrastructure that is provided to us or that we build or acquire as part of the concession agreement. The value of intangible assets is determined based on construction fair value, reduced by the corresponding estimated financial assets, described in greater detail below, and by any accumulated amortization and impairment losses, when applicable. The amortization pattern for intangible assets reflects our estimate of our future economic benefits from these assets, limited to the term of the concession. These intangible assets are amortized according to the lesser of (i) the remaining useful life of the asset or; (ii) the time remaining until the end of the concession term.
We calculate the value of financial assets related to our distribution business based on our distribution concession arrangements. These financial assets represent our understanding of our unconditional right to receive cash payments upon expiration of the concession from the grantor, as set forth in our concession agreements. These cash payments are designed to compensate us for the investments we make in infrastructure and that are not recovered through the collection of tariffs from users.
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Financial assets related to our distribution business do not have determinable cash flows, since we operate under the assumption that the value of the cash payments we will receive from the grantor upon expiration of a concession will be based on the replacement cost of the concession assets. Since these financial assets do not fit into any other category of financial assets under IFRS, they are classified as “available for sale”. The cash flows related to these assets are determined taking into account the replacement cost of PPE, which is known as the Regulatory Compensation Basis (Base de Remuneração Regulatória or BRR), and is defined by ANEEL. The return on these financial assets is based on the regulatory weighted average cost of capital approved by ANEEL in the periodic rate review process carried out every four years.
We calculate the value of the financial assets related to our transmission business based on: (i) revenues from tariffs based on the construction of transmission infrastructure for use by system users; (ii) revenues from tariffs based on the operation and maintenance of infrastructure assets related to our concessions; and (iii) the financial return on these assets that is guaranteed by ANEEL and that is not otherwise recovered through tariffs by the end of the concession term. Because the aggregate transmissiontariffstransmission tariffs we collect are calculated entirely based on the infrastructure assets that we make available to system users as a whole, they are not subject to demand risk, and are therefore considered guaranteed revenues. These revenues, which are calculated considering the entire term of the transmission concession, are known as Annual Permitted Revenues (Receita Anual Permitida or RAP). Users of this infrastructure are billed on a monthly basis for these amounts, pursuant to reports issued by the National System Operator (ONS). Upon expiration of the concession, the grantor is required to pay any uncollected amounts related to the construction, operation, and maintenance of infrastructure, as compensation for investments made and not recovered through tariffs. Because these financial assets do not have an active market and present fixed and determinable cash flows, they are classified as “loans and receivables”. These financial assets are initially estimated based on their fair values, and are later measured according to the amortized cost calculated under the effective interest rate method.
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As described above, we recognized financial assets in connection with these transmission concessions. However, we renewed the Concession Agreement 060/2001 pursuant to the 2013 Concession Renewal Law, which required that we accept certain amendments to this concession contract. See “Item 4. Information on the Company—Concessions.”Concessions”. One of the effects of these amendments is that we no longer recognize financial assets for concessions renewed pursuant to the 2013 Concession Renewal Law, because the scope of the concession has been narrowed to cover only the maintenance and operation of the transmission facilities. As a result, the financial assets we had previously recognized for concessions that were renewed pursuant to the 2013 Concession Renewal Law were converted into a receivable, since the Granting Authority has an obligation to pay these amounts. OnAs of December 31, 2012, we estimated that we would receive R$160.2 million related to financial assets that were constituted before May 2000, and we included this amount in our accounts receivable, in addition to the agreed R$893.9 million related to financial assets constituted after May 2000. On December 31, 2014,2017, the amount recorded in “Accounts Receivable Related to the Concession Extension” account, totaled R$461.368.9 million, R$256.5 million lower thanrelates to the residual amount of generation assets, the concessions of which expired in December 31, 2013, due to amortizations in the period.2014 and 2015.
Generation concessions are deemed outside the scope of IFRIC 12 and are accounted for under other applicable IFRS.
In addition to our financial assets and intangible assets, under IFRS we also recognize construction revenues and construction costs for construction activities we perform in connection with our distribution and transmission concessions. Our distribution business outsources power distribution infrastructure construction. As a result, under IFRS we recognize construction costs and revenues in roughly the same amounts. In contrast, since our transmission business performs much of our transmission infrastructure construction, we recognize construction revenue in amounts that exceed construction costs. The resulting margin for our transmission business’ construction revenue was 1.65% in 20142016 and 2013,2017, and is calculated based on a methodology that takes into account business risk.
The determination of the amortization term of our intangible assets and the fair value of our financial assets in connection with our concession contracts is subject to assumptions and estimates, and the use of different assumptions could affect the amounts we recognize. The estimated useful lives of the underlyingtheunderlying assets, as well as the rate of return of the financial assets also require significant assumptions and estimates. Different assumptions and estimates and changes in future circumstances could have a significant impact on our results of operations. Additional information on the accounting for intangible and financial assets arising from concession agreements is contained in Notes 3.74.3.9 and 3.124.6 to our audited consolidated financial statements.
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Revenue Recognition
We bill our residential, industrial and commercial customers monthly. Unbilled revenues from the billing date to month-end are estimated based on the prior month’s billing and recognized as revenue at the end of the month in which the service was provided. We read certain of our individual customers’ meters systematically throughout the month in order to estimate how much energy we have sold to individual customers as a group. At the end of each month, the amount of energy delivered to each customer since their last meter reading date is estimated and the corresponding unbilled revenue is determined based upon a customer’s daily estimated usage by class and applicable customer rates reflecting significant historical trends and experience. Differences between estimated and actual unbilled revenues, which have historically been insignificant, are recognized in the following month.
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Net Sectorial Financial Assets and Liabilities
Until 2009, the Brazilian accounting standards allowed distribution concessionaires to book the difference, if any, between the amounts that concessionaires were entitled to collect under their respective concession contracts and the amounts they actually collected, which are referred to as sectorial assets and liabilities. The positive or negative variations in these amounts were included in the tariffs in the following annual tariff adjustment. With the adoption of IFRS in 2010, these assets and liabilities were no longer recorded in the financial statements of distribution concessionaires.
As a result of an amendment to our distribution concession agreement as ofexecuted on December 31,10, 2014, we recognized on December 31, 2017, a financial assetliability in the amount of R$1,041.1283.5 million (financial liability of R$279.0 million in 2016), which represents our net balance of sectorial financial assets and liabilities. This amendment added a guarantee that, if the concession is extinguished for any reason, the residual amounts of items of Parcel A costs and other financial components that have not been recovered or returned via tariff shall be incorporated in the calculation of the indemnification amount by the granting authority. For more information, see Note 9 to the audited consolidated financial statements.
Impairment of Long-Lived Assets
Long-lived assets, primarily property, plants and equipment and intangible assets, comprise a significant amount of our total assets. We evaluate our long-lived assets and make judgments and estimates concerning the carrying value of these assets, including the amounts to be capitalized, the depreciation/ amortization rates and useful lives of these long-lived assets. The carrying values of these assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. This requires us to make long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts require assumptions about the demand for our products and services, future market conditions and regulatory developments. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Our evaluation as of December 31, 2017, resulted in an impairment of our in service and in progress property, plant and equipment in the amounts of R$5.0 million and R$1,210.4 million, respectively (see Notes 19.1 and 19.9 of our consolidated financial statements).
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Electric Energy Trading Chamber – CCEE
For accounting purposes, we recognize costs and revenues related to purchases and sales of energy in the spot market based on our internal estimates, which are reviewed by the CCEE.
We claimed a credit based on energy purchased from Itaipu during the energy rationing period that occurred in 2001, when there was a significant difference between the purchase price of Itaipu energy and energy sold at a loss in the spot market. However, we may be required to contribute to the amounts owed by other energy companies under similar lawsuits, and as of December 31, 2014,2017, we had provisions of R$41.949.4 million to cover probable losses related to these other lawsuits.
Provision for Risks (Labor, Civil, Tax and Environmental Claims)
Our subsidiaries and we are party to certain legal proceedings in Brazil arising in the normal course of business regarding tax, labor, civil and environmental claims.
We account for risks based onProvisions are recognized when, and only when: (i) the determination thatCompany has a present obligation (legal or constructive) resulting from a past event, (ii) it is probable (i.e., more likely than not that a future event will confirmnot) that an asset has been impaired oroutflow of resources embodying economic benefits will be required to settle the obligation, and (iii) a liability has been incurred at the reporting date, andreliable estimate can be made of the amount of loss can be reasonably estimated.to settle the obligation. By their nature, risks will only be resolved when a future event or events occur or fail to occur, typicallyoccur. Typically such events will occur a number of years in the future. The evaluation of these risks is performed by our internal and external legal counsel. Accounting for risks requires significant judgment by management concerning the estimated probabilities, including classification as probable or possible losses and ranges of exposure to potential liability. Management’s assessment of our exposure to risks could change as new developments occur or more information becomes available. The outcome of the risks could vary significantly and could materially impact our consolidated results of operations, cash flows and financial position. The provision for contingencies, classified as probable losses, as of December 31, 20142017 amounted to R$1,546.61,512.1 million, of which R$291.8138.6 million was related to tax proceedings, R$755.1742.6 million was related to civil claims, R$326.2475.6 million was related to labor claims, R$114.589.4 million was related to employee benefits, andR$58.5R$64.3 million was related to regulatory proceedings and R$0.51.6 million was related to environmental claims.
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As of December 31, 2014,2017, we estimate that the total amount of claims against us, excluding disputes involving non-monetary claims or claims that cannot be evaluated in the current stage of proceedings, classified as possible losses, was approximately R$2,738.83,123.5 million, of which R$558.9360.3 million correspond to labor claims; R$107.120.3 million to employee benefits; R$18.5793.7 million to regulatory claims; R$698.11,091.1 million to civil claims; and R$1,356.2858.1 million to tax claims. For more information, see Note 2930 to theour audited consolidated financial statements.
Employee Retirement and Health Benefits
We sponsor a (i) defined-benefit pension plan and a (ii) defined-contributionvariable contribution pension plan covering substantially all of our employees. We have also established a health care plan for current and retired employees. We determine our obligations for these plans based on calculations performed by independent actuaries using assumptions that we provide about interest rates, investment returns, rates of inflation, mortality rates and future employment levels.levels (see the assumptions in Note 25.5.1 and the sensitivity analysis in Note 25.5.8 of our consolidated financial statements). These assumptions directly affect our post- employmentpost-employment benefits liability.
In 2014,2017, we recorded expenses in the amount of R$201.5237.6 million for our pension and health care plans. We estimate that we will incur expenses in the amount of R$143.298 million in 20152018 for our health care plans (according to actuarial calculations), plus the monthly costs of defined-contribution plans..
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Deferred Taxes
We recognize deferred tax assets and liabilities based on the differences between the financial statement carrying amounts and the tax basis of assets and liabilities using prevailing rates. We regularly review our deferred tax assets for recoverability based on historical taxable income, projected future taxable income, and the expected timing of the reversals of existing temporary differences. If we are unable to generate sufficient future taxable income, or if there is a material change in the actual effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to derecognize all or a significant portion of our deferred tax assets resulting in a substantial increase in our effective tax rate and a material adverse impact on our operating results. The taxes balances subject to the federal taxing department inspection are those constituted over the last five years. As of December 31, 2017 we have recognized deferred tax assets totaling R$1,882.6 million and have not considered any reduction for risk of recovery of such assets (see Note 13.2.1 to the consolidated financial statements).
Estimated losses for doubtful accounts
The estimated losses for doubtful accounts are recorded in amounts deemed sufficient by Copel’s senior management to cover potential losses on the realization of customer receivables and others whose recovery is considered unlikely. The estimated losses for doubtful accounts are recorded considering the history of losses and parameters recommended by ANEEL, based on the expectation of receivables from the main debtors, on the analysis of large debts in judicial recovery / bankruptcy, on amounts receivable from residential class customers overdue for more than 90 days, from commercial class customers overdue for more than 180 days and from industrial and rural customers, public authorities, public lighting and public utilities overdue for more than 360 days in addition to previous experience of actual losses. As of December 31, 2017, we recorded a provision for doubtful accounts in the amount of R$309.8 million (see Note 7.3 to our consolidated financial statements for further details including provisions and reversals).
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Analysis of Electricity Sales and Cost of Electricity PurchasedANALYSIS OF ELECTRICITY SALES AND COST OF ELECTRICITY PURCHASED
The following table sets forth the volume and average rate components of electricity sales and purchases for the years ended December 31, 2014, 20132017, 2016 and 2012:2015:
| Year ended December 31, | Year ended December 31, | ||||
| 2014 | 2013 | 2012 | 2017 | 2016 | 2015 |
Electricity Sales |
|
|
|
|
| |
Sales to Final Customers |
|
|
|
|
| |
Average price (R$/MWh):(1) |
|
|
|
|
| |
Industrial customers(2) | 180.95 | 151.77 | 170.81 | |||
Industrial customers(2) | 254.45 | 246.25 | 231.79 | |||
Residential customers | 305.85 | 260.52 | 245.86 | 335.71 | 338.80 | 361.03 |
Commercial customers | 245.25 | 210.80 | 225.01 | 318.65 | 339.26 | 300.19 |
Rural customers | 164.33 | 145.06 | 155.29 | 333.33 | 378.67 | 232.59 |
Other customers(3) | 187.03 | 161.34 | 172.84 | |||
All customers(2) | 224.79 | 190.91 | 200.81 | |||
Other customers(3) | 262.23 | 268.98 | 237.18 | |||
All customers(2) | 299.06 | 301.95 | 278.05 | |||
Volume (GWh): |
|
|
|
|
| |
Industrial customers(2) | 10,841 | 10,675 | 8,799 | |||
Industrial customers(2) | 7,689 | 9,585 | 10,823 | |||
Residential customers | 7,267 | 6,888 | 6,559 | 7,126 | 6,932 | 6,957 |
Commercial customers | 5,482 | 5,086 | 5,058 | 4,847 | 5,108 | 5,542 |
Rural customers | 2,252 | 2,081 | 2,025 | 2,257 | 2,180 | 2,256 |
Other customers(3) | 2,382 | 2,278 | 2,211 | |||
All customers(2) | 28,224 | 27,008 | 24,652 | |||
Total revenues from sales to Final Customers (millions of R$) | 6,344 | 5,156 | 4,950 | |||
Other customers(3) | 2,455 | 2,404 | 2,371 | |||
All customers(2) | 24,374 | 26,209 | 27,949 | |||
Total revenues from sales to final customers (millions of R$) | 7,691 | 7,914 | 7,771 | |||
Sales to distributors(4) |
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|
|
|
| |
Average price (R$/MWh)(1) | 292.96 | 135.65 | 102.07 | |||
Volume (GWh)(5) | 14,920 | 14,242 | 15,910 | |||
Total revenues (millions of R$) | 4,370.8 | 1,932.0 | 1,624.0 | |||
Average price (R$/MWh)(1) | 183.98 | 146.93 | 233.02 | |||
Volume (GWh)(5) | 17,263 | 18,213 | 15,910 | |||
Total revenues (millions of R$) | 3,176 | 2,676 | 3,707.4 | |||
Electricity Purchases |
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|
|
|
| |
Purchases from Itaipu |
|
|
|
|
| |
Average cost (R$/MWh)(6) | 128.81 | 117.54 | 95.76 | |||
Volume (GWh) | 5,870 | 5,193 | 5,256 | |||
Average cost (R$/MWh)(6) | 188.41 | 182.91 | 263.89 | |||
Volume (GWh) | 5,934 | 5,958 | 5,941 | |||
Percentage of total Itaipu production purchased | 7.6 | 5.8 | 5.9 | 7.2 | 6.5 | 7.6 |
Total cost (millions of R$)(7) | 756.1 | 610.4 | 503.3 | |||
Total cost (millions of R$)(7) | 1,118.0 | 1,089.8 | 1,567.8 | |||
Purchases from Angra |
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|
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| |
Average cost (R$/MWh) | 149.31 | 135.67 | - | |||
Volume (GWh) | 1,046 | 1,050 | - | |||
Total cost (millions of R$)(7) | 156.2 | 142.5 | - | |||
Average cost (R$/MWh) | 226.49 | 221.25 | 169.55 | |||
Volume (GWh) | 1,023 | 1,026 | 1,051 | |||
Total cost (millions of R$)(7) | 231.7 | 227.0 | 178.2 | |||
Purchases from CCGF |
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|
|
|
| |
Average cost (R$/MWh) | 32.34 | 32.07 | - | |||
Volume (GWh) | 1,315 | 1,272 | - | |||
Total cost (millions of R$)(7) | 42.5 | 40.8 | - | |||
Average cost (R$/MWh) | 61.55 | 66.19 | 34.11 | |||
Volume (GWh) | 7.271 | 7,553 | 3,873 | |||
Total cost (millions of R$)(7) | 447.5 | 499.9 | 132.1 | |||
Purchases from others(4) |
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| |
Average cost (R$/MWh) | 203.34 | 147.38 | 131.46 | |||
Volume (GWh) | 16,692 | 15,645 | 17,529 | |||
Total cost (millions of R$)(7) | 3,394.2 | 2,305.8 | 2,304.4 | |||
Average cost (R$/MWh) | 342.37 | 202.27 | 267.10 | |||
Volume (GWh) | 12,758 | 14,180 | 15,556 | |||
Total cost (millions of R$)(7) | 4,368 | 2,868 | 4,155 |
(1) Average prices or costs have been computed by dividing (i) the corresponding revenues or expenses by (ii) MWh of electricity soldelectricitysold or purchased.
(2) Includes Free Customers outside Paraná.
(3) Includes public services such as street lighting, as well as the supply of electricity to government agencies, and our own consumption.
(4) Energy traded between Copel’s subsidiaries not included.
(5) Energy Reallocation Mechanism not included.
(6) Our purchases of electricity generated by Itaipu are stated in reais and paid for on the basis of a capacity charge expressed in U.S. dollars per kW plus a “wheeling” (or transportation) charge expressed in reais per kWh.
(7) See “Item 4. Information on the Company-Business—Generation” and “Item 4. Information on the Company—Business Purchases” for an explanation of our expenses relating to electricity purchases.
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Results of Operations for the Years Ended DecemberRESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 and 20122017, 2016 AND 2015
The following table summarizes our results of operations for the years ended December 31, 2014, 20132017, 2016 and 2012.2015.
Our consolidated financial statements present our operating costs of sales and services provided by function. However, in accordance with IFRS, Note 32 to the33 of our audited consolidated financial statements presents this information according to the nature of the operating cost or expense. For ease of understanding, the analysis below reflects the information presented by nature.
| Year ended December 31, | Year ended December 31, | ||||||
| 2014 | 2013 | 2012 | 2017 |
| 2016 Restated |
| 2015 Restated |
| (R$ million) | (R$ million) | ||||||
Operating Revenues: |
|
| ||||||
Operating Revenues(1): |
|
|
| |||||
Electricity sales to Final Customers: | 4,371,2 | 3,344.6 | 2,625.5 | 4,681.5 | 5,231.5 | 5,746.9 | ||
Residential | 1,429.6 | 1,074.1 | 782.3 | 1,381.7 | 1,371.2 | 1,804.7 | ||
Industrial | 1,563.1 | 1,263.1 | 926.6 | 1,488.5 | 1,796.0 | 2,049.5 | ||
Commercial, services and other activities | 838.3 | 626.9 | 573.8 | 904.5 | 1,065.2 | 1,156.0 | ||
Rural | 260.8 | 165.1 | 148.9 | 511.4 | 584.5 | 339.3 | ||
Other classes | 279.4 | 215.4 | 193.9 | 395.5 | 414.6 | 397.4 | ||
Electricity sales to distributors | 4,370.8 | 1,932.3 | 1,623.5 | 3,176.4 | 2,676.1 | 3,707.4 | ||
Use of main distribution and transmission grid | 2,237.5 | 2,029.0 | 2,830.6 | 3,617.9 | 3,976.6 | 2,388.5 | ||
Residential | 793.0 | 720.3 | 830.3 | 1,010.5 | 977.4 | 707.0 | ||
Industrial | 398.6 | 357.1 | 576.4 | 468.0 | 564.3 | 459.2 | ||
Commercial, services and other activities | 506.2 | 445.3 | 564.3 | 640.0 | 667.7 | 507.7 | ||
Rural | 109.3 | 136.8 | 165.6 | 241.0 | 241.0 | 185.4 | ||
Other classes | 166.2 | 152.0 | 187.9 | 248.3 | 231.9 | 164.9 | ||
Interest income | 403.8 | 854.1 | 116.1 | |||||
Other distribution and transmission revenue | 264.2 | 217.5 | 506.1 | 606.3 | 440.2 | 248.2 | ||
Construction revenues | 1,279.0 | 1,076.1 | 749.8 | 868.0 | 1,279.7 | 1,196.3 | ||
Revenues from telecommunications | 165.5 | 141.3 | 125.6 | 309.0 | 261.6 | 209.9 | ||
Distribution of piped gas | 391.3 | 368.6 | 325.0 | 454.8 | 471.9 | 526.4 | ||
Sectorial financial assets and liabilities result | 1,033.9 | - | - | 718.8 | (1,079.7) | 858.2 | ||
Other operating revenues | 69.3 | 288.3 | 213.3 | 141.1 | 151.4 | 94.5 | ||
Fair value of assets from the indemnity for the concession | 57.1 | 132.7 | 217.7 | |||||
| 13,918.5 | 9,180.2 | 8,493.3 | 14,024.6 | 13,101.8 | 14,945.8 | ||
Cost of sales and services provided: |
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|
|
| ||||
Electricity purchased for resale | (5,097.7) | (3,336.4) | (2,807.7) | (6,165.5) | (4,685.6) | (6,032.9) | ||
Charge of main distribution and transmission grid | (384.9) | (407.3) | (772.4) | (712.0) | (866.2) | (919.8) | ||
Personnel and management | (1,052.8) | (1,096.3) | (1,245.7) | (1,343.3) | (1,304.4) | (1,168.9) | ||
Pension and healthcare plans | (201.6) | (176.2) | (182.9) | (237.6) | (259.8) | (254.3) | ||
Material and supplies | (74.4) | (70.4) | (69.7) | (83.1) | (81.5) | (76.7) | ||
Materials and supplies for power electricity | (150.9) | (27.2) | (25.5) | (97.4) | (33.4) | (199.3) | ||
Natural gas and supplies for gas business | (1,469.8) | (295.7) | (247.8) | (309.5) | (325.4) | (1,176.1) | ||
Third-party services | (424.5) | (423.5) | (408.9) | (521.5) | (550.5) | (519.5) | ||
Depreciation and amortization | (629.9) | (603.2) | (549.9) | (731.6) | (708.3) | (676.5) | ||
Accruals and provisions | (1,203.7) | (199.5) | (218.8) | (365.5) | (768.7) | (210.8) | ||
Construction cost | (1,285.9) | (1,088.3) | (733.5) | (1,003.9) | (1,280.7) | (1,251.0) | ||
Other costs and expenses | (392.5) | (343.6) | (238.0) | (414.0) | (414.8) | (426.1) | ||
| (12,368.6) | (8,067.6) | (7,500.8) | (11,984.9) | (11,279.3) | (12,911.9) | ||
Equity in earnings of associates and joint ventures | 160.0 | 113.6 | 6.7 | 101.7 | 166.4 | 87.6 | ||
Financial results | 147.7 | 280.3 | (26.7) | (748.4) | (594.7) | (427.7) | ||
Profit before income tax and social contribution | 1,857.6 | 1,506.5 | 972.5 | 1,392.9 | 1,394.2 | 1,693.8 | ||
Income tax and social contribution on profit | (522.0) | (405.1) | (246.0) | (274.7) | (519.7) | (532.2) | ||
Net income for the year | 1,335.6 | 1,101.4 | 726.5 | 1,118.3 | 874.5 | 1,161.6 | ||
Net income attributable to controlling shareholders | 1,206.0 | 1,072.5 | 700.7 | 1,033.6 | 895.8 | 1,109.6 | ||
Net income attributable to non-controlling interest | 129.6 | 28.9 | 25.8 | 84.7 | (21.3) | 52.0 | ||
Other comprehensive income | 90.0 | (129.1) | (30.5) | 31.3 | (57.2) | 291.3 | ||
Comprehensive income | 1,425.6 | 972.3 | 696.0 | 1,086.9 | 817.3 | 1,452.9 | ||
Comprehensive income attributable to controlling shareholders | 1,297.2 | 943.4 | 550.7 | 1,002.4 | 838.5 | 1,400.4 | ||
Comprehensive income attributable to non-controlling interest | 128.4 | 28.9 | 145.3 | 84.5 | (21.2) | 52.5 | ||
(1)The information contained herein reflects the restatement of the Income Statement of the years 2016 and 2015.
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Results of Operations for 20142017 Compared with 20132016
The information contained herein reflects the restatement of Financial Results and Net Income of the Income Statement of the year 2016. For more information see Note 4.1 of our Consolidated Financial Statements.
Operating Revenues
Our consolidated operating revenues increased by 51.6%,7.0% or R$4,738.3922.8 million, in 20142017 compared to 2013. R$2,438.5 million of this increase was due to2016. This result reflected an increase of R$1,798.5 million in the sectorial financial assets and liabilities; an increase of R$500.3 million in electricity sales to distributors; an increase of R$1,033.947.4 million was due to revenues fromsectorial financial assets and liabilities;in telecommunications revenues. These increases were partially offset by a decrease of R$1,026.6550.0 million was from an increase in electricity sales to Final Customers;final customers; a decrease of R$208.5411.6 million was from an increasein construction revenues; a decrease of R$358.6 million in revenues from the use of our main transmission grid; a decrease of R$202.975.7 million was from an increase in construction revenues; andfair value of the Indemnifiable Concession Assets; a decrease of R$46.917.1 million was from an increase in telecommunications revenues and distribution of piped gas. These increases were partially offset bygas; and a decrease of R$218.910.3 million in other operationoperating revenues.
Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers increaseddecreased by 30.7%10.5%, or R$1,026.6550.0 million, to R$4,681.5 million in 2014,2017 compared with R$5,231.5 million in 2016, primarily due to an increasea decrease of 24.9% in the average tariff paid by6.8% of total power consumption of our Final Customers, and an increase of 5.6%from 26,151 GWh in the volume of energy sold2016 to most classes of Final Customers.
The increase24,374 GWh in the volume of energy sold to Final Customers in 2014 compared with 2013 reflected an increase in the number of Final Customers in each category:2017, as follows:
· The volume of electricity sold to residential customers increased by 5.5%2.8% in 20142017 compared to 2013. Of this2016. While there was an increase 3.5 p.p. was due to an increasedin number of customers and 1.5 p.p. was due to an increasedby 2.4%, the average consumption per residential customer. This increaseremained stable in consumption, in turn, was principally the result of the maintenance of the favorable economic conditions and higher temperatures in 2014.2017 compared to 2016.
· The volume of electricity sold to industrial customers, including both captive customersCaptive Customers and Free Customers, increaseddecreased by 1.6%19.7% in 20142017 compared with 2013, primarilyto 2016. Primarily due to the growthincreasing migration of industrial customers to the free marketandthe country’s economic situation. The number of industrial customers decreased by 6.9% and the average consumption decreased by 39.2% in industrial production in the beverage, wood products and paper & pulp sectors in the State of Paraná.2017 compared to 2016.
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· The volume of electricity sold to commercial customers, increasedincluding both Captive Customers and Free Customers, decreased by 7.8%4.2% in 20142017 compared with 2013. This2016. Despite the increase was mainly due to an increase of 9.1% in the number of commercial customers as well as higher temperaturesof 2.0%, the average of consumption decrease by 9.9% in 2014.2017 compared to 2016.
· The volume of electricity sold to rural customers increased by 8.2%3.5% in 20142017 compared to 2013.2016. This increase is mainly due to the strongpositive performance of agribusiness in the State of Paraná and to an increase of 1.1%5.1% in the numberaverage consumption.
The decrease of rural customers during the period.total power consumption of our Final Customers was partially offset by an increase of 5.9% from June 2017 in the average tariff paid by Final Customers.
Electricity Sales to Distributors. Our revenues from electricity sales to distributors increased by 126.2%18.7%, or R$2,438.5500.3 million, to R$4,370.83,176.4 million in 20142017 compared with R$1,932.32,676.1 million in 2013.2016. This increase was mainly caused by (i) an increase in our revenues forfrom energy sold to distributors under Bilateral Agreements, which increased by 42.5%, or R$581.3 million, to R$1,947.9 million in 2017 from R$1,366.6 million in 2016; and (ii) an increase in our revenues from energy sold to distributors in the spot market (CCEE), which increased by R$2,439.0 million,43.1%, or 445.0%, from R$548.1324.6 million, to R$2,987.11,077.9 million in 2017 from R$753.4 million in 2016. This increase in CCEE revenues is a result of the activation of the Araucária Thermoelectric plant and higher prices in the spot market.
Use of main distribution and transmission grid. Our revenues from the use of main distribution and transmission grid decreased by 9.0%, or R$358.6 million, to R$3,617.9 million in 2017 compared to R$3,976.6 million in 2016. This decrease was mainly due to the recognition of the indemnification of assets related to the Existing System Basic Network (RBSE) which registered a revenue of R$361.2 million in 2017, compared to R$809.6 million in 2016, as disclosed in Note 10.4 of our Consolidated Financial Statements. For more information on the RBSE recognition, also see “Results of Operations for 2016 Compared with 2015 – Operating Revenues - Use of main distribution and transmission grid”. This decrease in our revenues from the use of main distribution and transmission grid was partially offset by the result of the 4th tariff review cycle in June 2016, which increased the Parcel B in 22%. For more information about the calculation of the tariff review, see “Item 4. Information on the Company — The Brazilian Electric Power IndustryRates and Prices”.
Construction revenues. Our revenues from construction decreased by 32.2%, or R$411.6 million, to R$868.0 million in 2017 compared to R$1,279.7 million in 2016. This decrease was mainly due to reduced investments in infrastructure, reflecting the decrease in construction costs.
Fair value of assets from the indemnity for the concession. The fair value of our assets from the indemnity for the concession decreased 57.0%, or R$75.7 million, to R$57.1 million in 2017 compared to R$132.7 million in 2016. This decrease was mainly due to lower variation in the distribution concession agreement’s assets and the reduction of IPCA index, from 6.29% in 2016 to 2.95% in 2017.
Revenues from Telecommunications. Revenues from our telecommunications segment increased by 18.1%, or R$47.4 million, to R$309.0 million in 2017 compared to R$261.6 million in 2016, as a result of an increased number of customers in the retail market, notably in the internet broadband segment.
Distribution of Piped Gas. Revenues from the distribution of piped gas decreased by 3.6%, orR$17.1 million, to R$454.8 million in 2017 compared to R$471.9 million in 2016, reflecting the decrease in natural gas consumption by industrial clients by 13.1%. This decrease was partially offset by the activation of the Araucária TPP.
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Sectorial Financial Assets and Liabilities. Sectorial financial assets and liabilities registered a gain of R$718.8 million in 2017 compared to a loss of R$1,079.7 million in 2016. This positive variation of R$1,798.5 million was mainly due to the recognition of receivables resulting from the positive difference between the average price of the electricity purchased from Angra, CCGF and under the Availability Agreements and the coverage tariff average price, which in turn resulted from a lower average GSF and a higher average PLD. For more information on this positive variation, see Note 9.2 of our Consolidated Financial Statements.
Other Operating Revenues. Other operating revenues decreased by 6.8%, or R$10.3 million, to R$141.1 million in 2017 compared to R$151.4 million in 2016, mainly due to a decrease in our revenues from penalties imposed on customers.
Cost of sales and services provided
Our consolidated costs of sales and services provided increased by 6.3% or R$705.6 million, to R$11,984.9 million in 2017 compared with R$11,279.3 million in 2016. The main factors leading to such increase in our cost of sales and services provided are as follows:
· | Electricity Purchased for Resale.Our expenses for purchasing energy for resale increased by 31.6%, or R$1,479.8 million, to R$6,165.4 million in 2017 compared to R$4,685.6 million in 2016. This increase was mainly due to: (i) an increase by 229.7%, or R$1,230.4 million, in the cost of energy purchased in the spot market in 2017 compared to 2016, and (ii) an increase by R$746.8 million in the cost of energy purchased pursuant to Bilateral Agreements, both mainly as a result of a lower average GSF (81.6% in 2017 versus 88.2% in 2016) and a higher average PLD in the period (R$318.15/MWh in 2017 versus R$92.35/MWh in 2016). |
· | Charge of Main Distribution and Transmission Grid.Expenses we incurred for our use of the main distribution and transmission grid decreased by 17.8%, or R$154.2 million, to R$712.0 million in 2017 compared to R$866.2 million in 2016, mainly as a result of the lower costs with System Service Charges - ESS, in connection with the funds from the reserve electric energy (Coner) and of the charge of the reserve energy - EER, offset against the increase in costs of the basic network costs and transportation of energy, due to the effects of the indemnifications to the energy transmission companies. |
· | Personnel and Management.Personnel and management expenses increased by 3.0%, or R$38.9 million, to R$1,343.3 million in 2017 compared to R$1,304.4 million in 2016, as a result of (a) wage increases of 1.63% as of October 2017 and 9.15% as of October 2016, and (b) the provision of R$53.4 million for the retirement incentive program (PDI). |
· | Pension and Healthcare Plans. Pension and Healthcare expenses decreased by 8.5%, or R$22.2 million, to R$237.6 million in 2017, compared with R$259.8 million in 2016, arising from the effects of the actuarial valuation, calculated by the actuary hired. |
· | Material and Supplies.Materials and supplies expenses increased by 2.0%, or R$1.7 million, to R$83.1 million in 2017 compared with R$81.5 million in 2016. |
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· | Material and Supplies for Power Electricity. These expenses drastically increased 191.9%, or R$64.0 million, to R$97.4 million in 2017, compared to R$33.4 million in 2016, mainly as a result of the activation of TPP Araucaria in 2017, and the corresponding increase in natural gas purchases. |
· | Natural Gas and Supplies for Gas Business.Expenses related to natural gas purchases decreased by 4.9%, or R$15.9 million, to R$309.5 million in 2017 compared to R$325.4 million in 2016, mainly as a result of a reduction in the demand of natural gas, which was partially offset by the activation of TPP Araucária. |
· | Third-Party Services. Third-party services expenses decreased by 5.3%, or R$29.0 million, to R$521.5 million in 2017 compared with R$550.5 million in 2016, mainly due to the decrease in expenses with the maintenance of our electric system and with auditing and advisory services, offset against the increase in the communication, processing and data transmission services. |
· | Depreciation and Amortization. Depreciation and amortization increased by 3.3%, or R$23.3 million, to R$731.6 million in 2017, compared to R$708.3 in 2016, mainly due to an increase in our non-current assets. |
· | Accruals and Provisions.Accruals and provisions expenses decreased by 52.4% or R$403.2 million, to R$365.5 million in 2017 compared to R$768.7 million in 2016, mainly due to (i) the reversal of estimated impairment of assets of R$122.8 million in 2017, against an accrual of estimated impairment of assets of R$581.6 million in 2016; and (ii) a decrease in the provision for estimated losses with doubtful accounts in the amount of R$89.3 million. These decreases were partially offset by an increase in the provision for litigation of R$407.8 million in 2017 compared to 2016. |
· | Construction Cost. Construction costs decreased by 21.6%, or R$276.9 million, to R$1,003.9 million in 2017 from R$1,280.7 million in 2016, mainly due to reduced investments in infrastructure, reflecting the completion of certain projects by Copel Distribuição in 2016 and 2017. |
· | Other Costs and Expenses. Other costs and expenses decreased by 0.2%, or R$0.9 million, to R$414.0 million in 2017, compared to R$414.9 million in 2016. This decrease was mainly due to a non-operational gain of R$28.7 million arising from the sale of our stake in Sanepar. |
Equity earnings of associates and joint ventures
Equity earnings of associates and joint ventures was R$101.8 million in 2017, a decrease of 38.9%, compared to R$166.4 million in 2016, mainly due to a decrease in the profits of our associate entities and joint ventures in 2017, in special due to the sale of our stake in Sanepar.
Namely, our equity method income for 2017 was: (i) loss of R$0.6 million from Dominó Holdings, compared with income of R$37.5 million in 2016; (ii) loss of R$9.5 million from Marumbi, compared with income of R$16.2 million in 2016; (iii) loss of R$8.9 million from Integração Maranhense, compared with income of R$15.9 million in 2016; (iv) R$57.4 million from Matrinchã, compared with R$41.9 million in 2016; (v) R$25.4 million, from Guaraciaba, compared with R$11.2 million in 2016; (vi) R$19.5 million from Mata de Santa Genebra, compared with a loss of R$2.6 in 2016; and (vii) R$17.0 million from Paranaíba, compared with R$12.8 million in 2016.
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Financial Results
We recognized an increase of financial losses by 25.9%, or R$153.8 million, to R$748.4 million of net financial losses in 2017, compared to a net financial loss of R$594.7 million in 2016. This increase in financial losses is primarily due to the decrease of our financial revenues by 22.6%, mainly as a result of deflation of financial indexes that update financial revenue and lower fees on late payments of energy generatedbills. This increase was partially offset by a decrease in our financial expenses by 3.4%.
Income Tax and Social ContributionExpenses
In 2017, our income tax and social contribution expenses decreased to R$274.7 million, reflecting an effective tax rate of 19.7% on our pretax income, compared to R$519.7 million and an effective tax rate of 39.7% on our pretax income in 2016. The decrease in our effective tax rate in 2017 compared to 2016 was primarily due to our enrollment in a special tax benefit program of the AraucáBrazilian Federal Tax Authority (Programa Especial de Regularização Tributária Thermal Power Plant, which we had leased– PERT da Secretaria da Receita Federal). For more information on such special tax benefit program, see Note 13.3.1 of our Consolidated Financial Statements.
Results of Operations for 2016 Compared with 2015
The information contained herein reflects the restatement of Operating Revenues of the Income Statement of the year 2015, and the restatement of Financial Results, and Net Income of the Income Statement of the year 2016 and 2015. For more information see Note 4.1 of our Consolidated Financial Statements.
Operating Revenues
Our consolidated operating revenues decreased by 12.3%, or R$1,844.1 million, in 2016 compared to Petrobras until January 31, 2014 (and we therefore did not recognize revenue for2015. This result reflected a decrease of R$1,937.9 million in the salesectorial financial assets and liabilities; a decrease of this energyR$1,031.4 million in 2013)electricity sales to distributors; a decrease of R$515.4 million in electricity sales to final customers; a decrease of R$85.0 million in fair value of the Indemnifiable Concession Assets; and a decrease of R$54.5 million in distribution of piped gas. These decreases were partially offset by an increase of R$1,588.1 million in revenues from the use of our main transmission grid; an increase of R$83.3 million in construction revenues; an increase of R$57.0 million in other operating revenues; and an increase of R$51.7 million in telecommunication revenues.
Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers decreased by 9.0%, or R$515.4 million, to R$5,231.5 million in 2016 compared with R$5,746.9 million in 2015, primarily due to (i) a decrease of 12.9% from June 2016 in the average tariff paid by Final Customers, and (ii) higher pricesa decrease of 6.2% of total power consumption of our Final Customers, from 27,949 GWh in 2015 to 26,209 GWh in 2016, as follow:
·The volume of electricity sold to residential customers decreased by 0.4% in 2016 compared to 2015. Despite the increase in the number of customers of 2.0%, the average consumption decreased by 2.3% in 2016 compared to 2015.
·The volume of electricity sold to industrial customers, including both Captive Customers and Free Customers, decreased by 11.4% in 2016 compared with 2015. Primarily due to the negative economic conditions in Brazil, the number of industrial customers decreased by 7.1% and the average consumption decreased by 4.7% in 2016 compared to 2015.
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·The volume of electricity sold to commercial customers, including both Captive Customers and Free Customers, decreased by 7.8% in 2016 compared with 2015. This decrease was mainly due to a decrease of 9.1% in the average of consumption.
·The volume of electricity sold to rural customers decreased by 3.4% in 2016 compared to 2015. This decrease is mainly due to the negative performance of agribusiness in the State of Paraná.
Electricity Sales to Distributors. Our revenues from electricity sales to distributors decreased by 27.8%, or R$1,031.4 million, to R$2,676.1 million in 2016 compared with R$3,707.4 million in 2015. This decrease was mainly caused by a decrease in our revenues from energy sold to distributors in the spot market (CCEE), which decreased by R$1,399.6 million, or 64.8%, to R$759.9 million in 2014 compared to 2013.2016 from R$2,159.4 million in 2015. This decrease in CCEE revenues is a result of the non-activation of Araucária Thermoelectric plant and lower prices in the spot market.
Use of main distribution and transmission grid. Our revenues from the use of main distribution and transmission grid increased by 10.3%66.5%, or R$208.51,588.1 million, to R$2,237.53,976.6 million in 20142016 compared withto R$2,029.02,388.5 million in 2013.2015. This increase was principally due to: (i) tariff increases applied by Copel Distribuição, (ii) growth of 5.3% into the volume of energy that passed through our distribution grid, and (iii) adjustmentrecognition of the Permitted Annual Revenueindemnification of assets related to the Existing System Basic Network (RBSE), which registered a revenue of R$809.6 million in 2016, as disclosed in Note 10.4 of our transmission assets to reflect inflationConsolidated Financial Statements. It also reflected the result of the 4th tariff review cycle in June 2016, which increased the Parcel B by 22%. For more information about the calculation of the tariff review, see “Item 4. Information on the Company — The Brazilian Electric Power Industry” and operations of new transmission assets.“Item 5. Overview — Rates and Prices”.
Construction revenues. Our revenues from construction increased by 18.9%7.0%, or R$202.983.4 million, to R$1,279.01,279.7 million in 20142016 compared with R$1,076.11,196.3 million 2013.2015. This increase was mainly due to anincreasean intensification of construction efforts occurred in improvements we made to2016 aimed at improving our distribution and transmission infrastructureinfrastructure.
Fair value of assets from the indemnity for the concession.In 2016, we reviewed our accounting policy and reclassified the gains on “Fair Value of the Indemnifiable Concession Asset”, from financial income to operating revenue, as we believe that this reflects a more appropriate accounting approach for the distribution segment. For more information, see Note 4.1 of our Consolidated Financial Statements. This reclassification resulted in a restatement of the Income Statement of the years end 2014 compared with 2013.and 2015. An amount of R$217.7 million was reclassified from financial income to operating revenue in 2015. In 2016 we recognized a gain of R$132.7 million, resulting in a decrease of 39%, or R$85.0 million. This decrease reflects the renewal of one of our concession agreements in 2015 and, therefore, a reduction in the balance of “Accounts Receivable Related to the Concession” as a result of the transfer of part of its balance to “Intangible Assets”.
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Revenues from Telecommunications. Revenues from our telecommunications segment increased by 17.1%24.6%, or R$24.251.7 million, to R$165.5261.6 million in 20142016 compared to R$141.3209.9 million in 2013, primarily due to2015, as a result of an increased number of customers. In 2014,customers in the customer base increased by 173%, to 21,761retail market, notably in December 2014 from 8,270 in December 2013.the internet broadband segment.
Distribution of Piped Gas. Revenues from the distribution of piped gas increaseddecreased by 6.2%10.4%, or R$22.754.5 million, in 20142016 compared to 2013, primarily due to2015, reflecting the non-activation of the Araucária TPP and a 7.0% tariff adjustmentdecrease in March 2014.gas consumption by industrial clients. This decrease was partially offset by a 10.4% increase in gas prices.
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Sectorial Financial Assets and Liabilities. In 2014, we recognized net revenue of R$1,033.9 million related to our sectorialSectorial financial assets and liabilities registered a loss of R$1,079.7 million in 2016, compared to a gain of R$858.2 million in 2015. This negative variation of R$1,937.8 million was primarily due to an amendmentthe amortization (as a result of tariff rebalance that occurred in 2016) of (a) the balance recorded in 2015 as Sectorial Assets as a result of a deferral to 2013 and 2014 to our distribution concession contract, which clarified that if this concession is extinguishedin the tariff increase for any reason, our Parcel A costsCaptive Customers, (b) the balance recorded as a result of the exchange rate variation of the Itaipu power purchase agreement, and certain other financial components that we have not recovered shall be recoverable through indemnification by(c) the granting authority. A subsequent CVM resolution madebalance of the recognition of revenues related to these financial assets or liabilities mandatory.CDE Account.
Other Operating Revenues. Other operating revenues decreasedincreased by 75.9%60.2%, or R$219.057.0 million, to R$69.3151.4 million in 20142016 compared withto R$288.394.4 million in 2013,2015, mainly due lower rentalto revenue from leases and rentals and income due to the termination on January 31, 2014 of the lease agreement with Petrobras for Araucária Thermal Power Plant.from telecom services rendered in 2016 (other than broadband internet).
Cost of sales and services provided
Our consolidated costs of sales and services provided increaseddecreased by 53.3%12.6% or R$4,301.01,632.6 million, to R$12,368.611,279.3 million in 2014 (including amounts recognized as other operating expenses)2016 compared with R$8,067.612,911.9 million in 2013.2015. The following weremain factors leading to the principal factors in the increasedecrease of our costscost of sales and services provided:provided are as follows:
· | Electricity Purchased for Resale.
|
· | Charge of Main Distribution and Transmission Grid.Expenses we incurred for our use of the main distribution and transmission grid decreased by 5.8%, or R$53.6 million, to R$866.2 million in 2016 compared with R$919.8 million in 2015, mainly as a result of the decrease of ESS charges following a lower level of activity in thermoelectric plants in 2016. |
· | Personnel and Management.Personnel and management expenses increased by 11.6%, or R$135.5 million, to R$1,304.4 million in 2016 compared with R$1,168.9 million in 2015, as a result of (a) wage increases of 9.15% as of October 2016 and 9.9% as of October 2015, and (b) the provision of R$44.3 million for the retirement incentive program (PDI). |
· | Pension and Healthcare Plans.Pension and Healthcare expenses increased by 2.2%, or R$5.5 million, to R$259.8 million in 2016, compared with R$254.3 million in 2015. |
· | Material and Supplies.Materials and supplies expenses increased by 6.3%, or R$4.8 million, to R$81.5 million in 2016 compared with R$76.7 million in 2015. |
· | Material and Supplies for Power Electricity. These expenses decreased 83.3%, or R$165.9 million, to R$33.4 million in 2016, compared to R$199.3 million in 2015, mainly as a result of the non-activation of TPP Araucaria in 2016, and the corresponding reduction in natural gas purchases. |
· | Natural Gas and Supplies for Gas Business.Expenses related to natural gas purchases decreased by 72.3%, or R$850.7 million, to R$325.4 million in 2016 compared withSectorial Financial Assets and Liabilities. Sectorial financial assets and liabilities registered aR$1,176.1 million in 2015, mainly as a result of the non-activation of TPP Araucária, causing a reduction in the demand of natural gas. Due to poor hydrological conditions in 2015, the generation of thermoelectric energy was higher than normal. |
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· | Third-Party Services. Third-party services expenses increased by 6.0%, or R$31.0 million, to R$550.5 million in 2016 compared with R$519.5 million in 2015, mainly due to inflation indexation. |
· | Depreciation and Amortization. Depreciation and amortization increased by 4.7%, to R$708.3 million in 2016, compared with R$676.5 million in 2015, mainly due to an increase in our non-current assets. |
· | Accruals and Provisions.Accruals and provisions expenses increased by 264.6% or R$557.9 million, to R$768.7 million in 2016 compared with R$210.8 million in 2015, mainly due to the R$581.6 million impairment of generation and gas distribution assets. |
· | Construction Cost.Construction costs increased by 2.4%, or R$29.7 million, to R$1,280.7 million in 2016 from R$1,251.0 million in 2015, mainly due the intensification of construction efforts which occurred in 2016 aimed at improving our distribution and transmission infrastructure. |
· | Other Costs and Expenses. Other costs and expenses decreased by 2.7% or R$11.3 million, to R$414.8 million in 2016, compared with R$426.1 million in 2015. This decrease was mainly due to a non-operational gain of R$52.1 million arising from the change in the accounting technique for assessing our stake at Sanepar (from the equity method to fair value). |
·Natural Gas and Supplies for Gas Business. Expenses related to natural gas purchases increased by 397.1%, or R$1,174.1 million, to R$1.469.8 million in 2014 compared with R$295.7 million in 2013. This increase resulted from the purchase of natural gas by Compagas, principally to supply the Araucária Thermal Power Plant.
·Personnel and Management.Personnel and management expenses decreased by 4.0%, or R$43.5 million, to R$1,052.8 million in 2014 compared with R$1,096.3 million in 2013, mainly due to (i) a decrease in provisions for severance pay related to our retirement incentive program and (ii) a reduction in 0.6% in workforce provisions, partially offset by (a) an increase in profit sharing and (b) wage increases of 7.0% as of October 2013 and 7.5% as of 2014.
·Material and Supplies for Power Electricity. These expenses increased 454.8%, or R$123.7 million, to R$150.9 million in 2014, compared to R$27.2 million in 2013, reflecting acquisition costs for coal for the Figueira Thermal Power Plant and natural gas for the Araucária Thermal Power Plant.
·Construction Cost.Construction costs increased 18.2%, or R$197.6 million, to R$1,285.9 million in 2014 from R$1,088.3 million in 2013. This increase reflects costs incurred in connection with improvements we made to our distribution and transmission infrastructure in 2014.
·Pension and Healthcare Plans.Pension and Healthcare expenses increased 14.4%, or R$25.4 million, to R$201.6 million in 2014, compared to R$176.2 million in 2013.
·Material and Supplies.Materials and supplies expenses increased by 5.7%, or R$4.0 million, to R$74.4 million in 2014 compared with R$70.4 million in 2013.
·Third-Party Services. Third-party services expenses increased 0.2%, or R$1.0 million, to R$424.5 million in 2014 compared with R$423.5 million in 2013, mainly due to lower expenses related to electrical system and consulting and audit services, partly offset by the higher costs in facility maintenance.
·Other Costs and Expenses. Other costs and expenses increased by 14.2% or R$48.9 million, to R$392.5 million in 2014, compared with R$343.6 million in 2013. This increase was mainly due to higher expenses on taxes related to the State REFIS (Tax Debt Refinancing Program) and tax indemnifications.
Equity earnings of associates and joint ventures
Equity earnings of associates and joint ventures was R$160.0166.4 million in 2014,2016, an increase of 40.8%90.0%, compared to R$113.687.6 million in 2013,2015, mainly due to higher equity income registered by our joint ventures. Equity investment reflectsan increase in the equity income or lossprofits of our associates and joint ventures. In 2014, this positive net result was mainly due to:associate entities in 2016. Namely, our equity method income for 2016 was: (i) income of R$60.843.1 million from Sanepar, compared with R$34.7 million in 2015; (ii) R$41.9 million from Matrinchã, compared with R$0.3 million in 2015; (iii) R$37.5 million from Dominó Holdings; (ii) income ofHoldings, compared with R$30.624.8 million in 2015; (iv) R$16.2 million from Matrinchã; (iii) income ofMarumbi, compared with R$13.1 million in 2015; (v) R$15.9 million from Sanepar; (iv) incomeIntegração Maranhense, compared with R$14.3 million in 2015; (vi) R$12.8 million from Parnaíba, compared with R$3.0 million in 2015; and (vii) R$11.2 million from Guaraciaba, compared with a loss of R$15.817.1 million in 2015; (viii) R$10.7 million from Guaraciaba; (v) income ofFoz do Chopim Energética, compared with R$10.112.0 million in 2015; (ix) R$8.1 million from Caiuá, compared with R$8.6 million in 2015; (x) R$7.9 million from Dona Francisca Energética; (vi) incometica, compared with a loss of R$8.51.1 million in 2015; (xi) R$7.4 million from Foz do Chopim; (vii) income ofCosta Oeste, compared with R$3.57.5 million in 2015; (xii) R$5.2 million from IntegraçãCantarera, compared with R$1.6 million in 2015; (xiii) R$4.3 million from Voltalia São Maranhense and (iii) incomeMiguel do Gostoso I, compared with a loss of R$3.299 thousand in 2015; (xiv) R$1.8 million from Paranaíba. This income wasTransmissora Sul Brasileira, compared with a loss of R$6.4 million in 2015.
Additionally, equity earnings of associates and joint ventures were partially offset by a loss of R$3.855.3 million from Sercomtel Telecomunicações.due to the recognition of a provision for the impairment of an investiment made by UEG Araucária Ltda. in a Multimarket Investment Fund, which hold shares of other investment funds that in turn invest in a private company, whose main asset is a real estate development. For more information see Note 4.1 of our audited consolidated financial statements.
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Financial Results
We recognized an increase of financial losses by 39.0%, or R$147.7167.0 million, to R$594.7 million of net financial incomelosses in 2014,2016, compared to a net financial incomeloss of R$280.3427.7 million in 2013. Financial income increased by 6.5%, or R$42.1 million,2015. This increase in 2014 compared to 2013,financial losses is primarily due to (i) increased inflation adjustments on accounts receivable related to our distribution concession, and (ii) increased income from financial investments, reflecting higher interest rates in the period.
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Financial expenses increased by 46.9%, or R$174.7 million, in 2014 compared to 2013, to R$546.8 million in 2014 from R$372.1 million in 2013, mainly due to the increase in debt charges, primarily related tomainly arising from the higher balance of financing and debentures. This result was partially offset by a new debenture issuance in 2014, as well as inflationdecrease of IGP-DI rate (IGP-DI) and interest rate adjustments.
the appreciation of the Real versus U.S. dollar.
Income Tax and Social ContributionExpenses
In 2014,2016, we recognized income tax and social contribution expenses of R$522.0519.7 million, reflecting an effective tax rate of 28.1%37.3% on our pretax income. The increase in our effective tax rate in 2016 compared to 2015 was primarily due to the increase in (a) the difference between actual profit and presumed profit booked in our controlled companies, which was the result of the commercial start-up of wind farms that use an alternative method to calculate income tax payments based on a presumed taxable income base (i.e., gross revenue multiplied by statutorily provided margin percentages), and (b) the Interest on Capital paid in 2016. In 2013,2015, we recognized income tax and social contribution expenses of R$405.1532.2 million, reflecting an effective tax rate of 26.9%31.1% on our pretax income.
Results of Operations for 2013 Compared with 2012
Operating Revenues
Our operating revenues increased by 8.1%, or R$686.9 million, in 2013 compared to 2012. R$719.1 million of this increase was from an increase in electricity sales to Final Customers, R$308.8 million was from an increase in electricity sales to distributors, R$326.3 million was from an increase in construction revenues and R$134.3 million was from an increase in telecommunications revenues, distribution of piped gas and other operation revenues. All these increases were partially offset by a decrease of R$801.6 million in the use of our main transmission grid.
Electricity Sales to Final Customers. Our revenues from electricity sales to Final Customers increased by 27.4%, or R$719.1 million, in 2013, due to an increase of 9.6% in the average tariff paid by Final Customers and an increase in the volume of energy sold to most classes of Final Customers. In addition, the annual tariff revision issued by ANEEL in June 2012 increased the percentage of revenues we book as electricity sales, compared to the percentage we book as charges for use of the distribution grid. In addition, Copel Geração and Transmissão sold 190.8% more energy to Free Customers.
The increase in the volume of energy sold to Final Customers in 2013 compared with 2012 reflected an increase in the number of Final Customers in each category.
·The volume of electricity sold to residential customers increased by 5.0% in 2013 compared to 2012. Of this increase, 3.9% was due to an increased number of customers and 1.1% was due to an increased average consumption per residential customer. This increase was principally the result of (i) above average temperatures, especially in the last quarter of 2013, which led to increased energy consumption, and (ii) sales of energy consuming products as a consequence of a greater availability of consumer credit.
·The volume of electricity sold to industrial customers, including both captive customers and Free Customers, increased by 21.3% in 2013 compared with 2012. This increase is the consequence of industrial growth in Paraná in 2013 (growth of 5.6%, compared to growth of 1.2% in Brazil) and Copel Geração e Transmissão’s strategy to allocate more energy for sales to Free Customers, including industrial customers in other states.
·The volume of electricity sold to commercial customers increased by 0.6% in 2013 compared with 2012. This increase is mainly due to an increased number of commercial customers and a general increase in retail sales in the concession area.
·The volume of electricity sold to rural customers increased by 2.8% in 2013 compared to 2012. This increase is mainly due to an increment of 2.7% of average consumption per rural customer and an increase of 0.1% in the number of rural customers during the period.
Electricity Sales to Distributors. Our revenues from electricity sales to distributors increased by 19.0%, or R$308.8 million, to R$1,932.3 million in 2013 compared with R$1,623.5 million in 2012. This increase was mainly caused by: (i) an increase in our revenues for energy sales to distributors in the spot market (CCEE), which increased by R$299.4 million, or 136.0%, from R$220.2 million to R$519.6 million, mainly due to higher prices paid by distributors for energy sold in the spot market (CCEE), and (ii) the increased volume of bilateral agreements which increased by 282.2% in 2013 compared to 2012,from 1,367 GWh to 5,233 GWh. This increase was partially offset by lower revenue from auctions in the regulated market, due to the maturity of long-term agreements in the regulated environment.
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Use of main distribution and transmission grid. Our revenues from the use of main distribution and transmission grid decreased by 28.3% or R$801.6 million, to R$2,029.0 million in 2013 compared with R$2,830.6 million in 2012. This decrease was principally due to: (i) the annual tariff revision issued by ANEEL in June 2012, which reduced the percentage of revenues we book as charges for use of the distribution grid, compared to the percentage of revenues we book as electricity sales to final customers; (ii) the renewal of our main transmission concession under the 2013 Concession Renewal Law, the result of which was a decrease of approximately R$188.7 million in our annual permitted revenue; and (iii) a periodic downward tariff revision of 0.7% on June 24, 2012 for the use of our distribution grid. These decreases were partially offset by an increase of 4.2% in our revenues from use of the distribution grid, due to an increase in the volume of energy that we distributed to final customers.
Construction revenues. Our revenues from constructions increased by 43.5% or R$326.3 million in 2013 compared with 2012. This increase was mainly due to an increase in improvements we made to our distribution and transmission infrastructure in 2013, compared with 2012.
Revenues from Telecommunications. Revenues from our telecommunications segment increased by 12.5% or R$15.7 million in 2013 compared to 2012, primarily due to an increased number of customers. The majority of these new clients were residential clients, which generate less revenue on average than corporate clients. In 2013, the customer base increased by 163.3%, to 8,270 in December 2013 from 3,141 in December 2012.
Distribution of Piped Gas. Revenues from distribution of piped gas increased by 13.4%, or R$43.6 million, in 2013 compared to 2012, mainly due to two upward tariff adjustments: 8.0% in August 2012 and 6.5% in March 2013.
Other Operating Revenues. Other operating revenues increased by 35.2% or R$75.0 million, to R$288.3 million in 2013 compared with R$213.3 million in 2012, mainly attributable to: (i) higher rental income from UEG Araucária, since part of the lease payment is variable, depending on how much energy UEG Araucária produces, and production increased in 2013 compared to 2012;(ii) revenue from financial compensation for unavailability of energy by certain generation companies of the increased cost of energy acquired by Copel Distribuição in the spot market after these generation companies failed to supply energy pursuant to sales agreements.
Cost of sales and services provided
Our costs of sales and services provided increased by 7.6% or R$566.8 million, to R$8,067.6 million in 2013 (including amounts recognized as other operating expenses) compared with R$7,500.8 million in 2012. The following were the principal factors in the increase of our costs of sales and services provided:
·Electricity Purchased for Resale. Our costs for the energy we purchased for resale increased by 18.8%, or R$528.7 million, to R$3,336.4 million in 2013 compared with R$2,807.7 million in 2012. This increase was mainly due to higher acquisition costs from auctions in the regulated market, from Itaipu (partially as a result of the appreciation in U.S. dollar), and in bilateral agreements, motivated by (i) higher costs from thermal power agreements, and (ii) inflation adjustments in long-term energy supply agreements. Costs from energy purchases in the spot market were partially offset by CDE funds, which totaled R$294.1 million in 2013.
·Charge of Main Distribution and Transmission Grid. Expenses we incurred for our use of the main distribution and transmission grid decreased by 47.3%, or R$365.1 million, to R$407.3 million in 2013 compared with R$772.4 million in 2012, mainly due to lower costs from charges for the use of the transmission system as a whole as a result of the 2013 Concession Renewal Law. In addition, we received R$319.6 million in CDE funds in 2013 to offset these costs.
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·Personnel and Management. Personnel and management expenses decreased by 12.0%, or R$149.4 million, to R$1,096.3 million in 2013 compared with R$1,245.7 million in 2012, mainly due to (i) lower provisions for severance pay related to the Voluntary Redundancy Program, and (ii) lower expenses with compensation and related charges. This amount already includes the wage increases of 5.6% as of October 2012, 1.0% as of May 2013, and 7.0% in October 2013.
·Pension and Healthcare Plans. Pension and Healthcare expenses decreased 3.7%, or R$6.7 million, to R$176.2 million in 2013, compared to R$182.9 million in 2012. This decrease reflects the accrual of amounts related to the private pension and healthcare plans, reflecting the reduction in healthcare plan costs, in accordance with the actuarial calculation made by an independent actuary.
·Material and Supplies. Materials and supplies expenses increased by 1.0%, or R$0.7 million, to R$70.4 million in 2013 compared with R$69.7 million in 2012;
·Material and Supplies for Power Electricity. These expenses increased 6.7%, or R$1.7 million, to R$27.2 million in 2013, compared to R$25.5 million in 2012. This increase was mainly due to an increase in the unit cost of mineral coal purchased for the Figueira Thermoelectric Plant.
·Natural Gas and Supplies for Gas Business. Expenses related to natural gas purchases increased by 19.3%, or R$47.9 million, to R$295.7 million in 2013 compared with R$247.8 million in 2012. This increase was caused by an increase in the purchase price of natural gas acquired by Compagas from third-party suppliers. The increase of the purchase price of natural gas was mainly attributable to the effects of the recent devaluation of the Brazilian Real and an increase in the market price of oil, which influences the price of gas.
·Third-Party Services. Third-party services expenses increased 3.6%, or R$14.6 million, to R$423.5 million in 2013 compared with R$408.9 million in 2012, mainly due to higher expenses related to facilities maintenance, communications and data processing. This increase was partially offset by a decrease in the cost of consulting services.
·Accruals and Provisions. Accruals and provisions expenses decreased by 8.8% or R$19.3 million in 2013, to R$199.5 million in 2013 compared with R$218.8 million in 2012. This decrease was mainly due to (i) the reversal of tax provisions, and (ii) lower provisions for litigation related to civil and administrative claims.
·Construction Cost. Construction costs increased 48.8%, or R$354.8 million, to R$1,088.3 million in 2013 from R$733.5 million in 2012. This increase reflects costs incurred in connection with improvements we made to our distribution and transmission infrastructure in 2013.
·Other Costs and Expenses. Other costs and expenses increased by 44.4% or R$105.6 million, to R$343.6 million in 2013, compared with R$238.0 million in 2012. This increase was mainly due to (i) costs in connection with deactivation and disposal of assets in 2013, reflecting changes to ANEEL rules with respect to the accounting of assets and (ii) increased costs for use of hydrological resources, reflecting an increase in the volume of hydroelectric energy we produced in 2013 compared to 2012.
Equity earnings of associates and joint ventures
Equity earnings of associates and joint ventures was R$113.6 million in 2013, compared to R$6.7 million in 2012. Equity investment reflects the equity income or loss of our associates and joint ventures. In 2013, this positive net result was mainly due to: (i) income of R$96.6 million from Sanepar; (ii) income of R$10.3 million from Foz do Chopim; and (iii) income of R$9.0 million from Dona Francisca Energética, which was partially offset by a loss of R$13.6 million from Sercomtel Telecomunicações.
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Financial Results
We recognized R$280.3 million of net financial income in 2013, compared to a net financial expense of R$26.7 million in 2012. Financial income increased by 0.6%, or R$4.0 million, in 2013 compared to 2012, primarily due to inflation adjustments on indemnification payments related to the extension of our transmission concessions, which increased to R$84.6 million in 2013 compared with zero in 2012. This increase was partially offset by a reduction in inflation adjustments on account receivables related to our concessions, which decreased to R$108.2 million in 2013 compared with R$165.6 million in 2012, due to lower level of inflation in the period.
Financial expenses decreased by 44.9%, or R$302.9 million, in 2013 compared to 2012, to R$372.1 million in 2013 from R$675.0 million in 2012, mainly due to the non-recurring nature of the recognition of the remeasurement at fair value of Copel Distribuição’s financial assets in 2012, which generated a financial expense in 2012 of R$401.1 million.
Income Tax and Social Contribution
In 2013, we recognized income tax and social contribution expenses of R$405.1 million, reflecting an effective tax rate of 26.9% on our pretax income. In 2012, we recognized income tax and social contribution expenses of R$246.0 million, reflecting an effective tax rate of 25.3% on our pretax income.
Liquidity and Capital Resources
Our principal liquidity and capital requirements are to finance the expansion and improvement of our distribution and transmission infrastructure and to finance the expansion of our generation facilities.
We believe our working capital is sufficient for our present requirements and the next 12 months. Our other principal uses of cash are to dividends payments and debt servicing. Capital expenditures were R$2,464.52,206.9 million in 20142017 and R$1,955.43,651.2 million in 2013.2016. The following table sets forth a breakdown of our capital expenditures for the periods indicated. Our capital expenditures are focused on projects located in Brazil.
As of December 31, 2017, our Net Working Capital ended negative by R$408.1 million. As in previous years, our capital requirement will be financed by cash from our operations and by external financing, which will serve to offset commitments arising from the maturity of previous external financing.
| Year ended December 31, | Year ended December 31, | ||||
| 2014 | 2013 | 2012 | 2017 | 2016 | 2015 |
| (R$ million) | (R$ million) | ||||
Generation and transmission | 758.4 | 478.7 | 988.2 | |||
Generation and transmission¹ | 1,389.1
| 2,129.5
| 948.5 | |||
Distribution | 857.7 | 816.5 | 809.0 | 630.4
| 777.1
| 656.4 |
Telecom | 107.5 | 74.1 | 79.9 | 241.1
| 193.8
| 105.7 |
Investment of associates and joint ventures | 628.6 | 519.3 | 57.3 | 248.2
| 503.1 | 654.4 |
Araucária Thermoelectric Plant | 32.7 | 19.4 | 1.7 | 0.7
| 20.4 | 3.7 |
Compagas | 79.1 | 42.1 | 31.1 | 13.7
| 25.8 | 69.6 |
Elejor | 0.5 | 5.3 | 2.3 | 1.5 | 1.3 | |
Total | 2,464.5 | 1,955.4 | 1,969.5 | 2,524.7 | 3,651.2 | 2,439.3 |
¹ Considers investment in projects 100% Copel GeT.
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Our total budgeted capital expenditures for our wholly-owned subsidiaries for 20152018 is R$2,476.92,928.6 million, of which:
· R$1,042.2743.6 million is for generation and transmission, including R$345.198.7 million is for the construction of the Colíder Hydroelectric Plant, and R$158,571.7 million is for the construction of the Baixo Iguaçu Hydroelectric Plant;
· R$784.7790.0 million is for distribution;our distribution business;
· R$107.7340.2 million is for our telecommunication business;
· R$536.81,051.4 million is for new businesses.our wind farms, including R$888.5 million for the construction of the Cutia Wind Farm Complex; and
·R$3.4 million is for other investments.
Our following subsidiaries also budgeted their own capital expenditures for 2015,2018, as described below:as follows:
· Compagas: R$80.921.6 million;
· Araucária: R$26.02.5 million; and
· Elejor: R$12.311.4 million.
Historically, we have financed our liquidity and capital requirements primarily with cash provided by our operations and through external financing. Our principal source of funds in 20142017 was ouroperating activities. Net cash provided by financing activities was R$650.0 million in 2017, compared with R$535.6 million in 2016. Net cash provided by operating activities was R$1,091.4989.2million in 2017, compared with R$1,476.8 million in 2014, compared with R$1,337.6 million in 2013.2016. In 2015,2018, we expect to finance our liquidity and capital requirements primarily with cash provided by our operations and through debt financing from BNDES and in the Brazilian capital markets.
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As in prior years, we plan to make significant investments in future periods to expand and upgrade our generation, transmission and distribution businesses. In addition, we may seek to invest in other existing electric utilities, in communications services or in other areas, each of which may require additional domestic and international financing. Our ability to generate cash sufficient to meet our planned expenditures is dependent upon a variety of factors, including our ability to maintain adequate tariff levels, to obtain the required regulatory and environmental authorizations, to access domestic and international capital markets, and a variety of operating and other contingencies. We anticipate that our cash provided by operations may be insufficient to meet these planned capital expenditures, and that we may require additional financing from sources such as BNDES and the Brazilian capital markets.
ANEEL’s regulations require prior approval from ANEEL for any transfer of funds from our subsidiaries to us in the form of loans or advances. ANEEL approval is not required for cash dividends, as long as cash dividends do not exceed a dividend threshold (“Dividend Threshold”) equal to the greater of adjusted net income or income reserves available for distribution. The Dividend Threshold is established by Brazilian Corporate Law.
The cash dividends we have received from our subsidiaries have been historically sufficient to meet our cash flow requirements without exceeding the Dividend Threshold. As a result, we have not sought approval from ANEEL to receive either loans or advances from our subsidiaries or cash dividends from our subsidiaries in excess of the Dividend Threshold. We do not expect these restrictions on loans and advances and on cash dividends exceeding the Dividend Threshold to impact our ability to meet our cash obligations, since we expect cash dividends below the Dividend Threshold to be sufficient in the future.
Like other state-owned companies, we are subject to certain CMN restrictions on our ability to obtain financing from domestic and international financial institutions. CMN restrictions could limit our ability to accept bank financing but do not affect our ability to access the Brazilian and international capital markets, and do not restrict our access to banking financing for the purpose of repaying or refinancing debt.
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Our total outstanding loans and financing (including debentures) atas of December 31, 20142017 totaled R$6,054.49,830.5 million. Approximately R$71.289.3 million of the total debt outstanding atas of December 31, 20142017 was denominated in U.S. dollars. For more information on the terms of these loans and financings, including reference to their specific maturity dates and interest rate structure, see Notes 2223 and 2324 to our audited consolidated financial statements. We are not subject to seasonality with respect to our borrowing requirements. Our major loans and financing arrangements are:
Banco do Brasil:
· We have R$1,558.51,388.4 million of outstanding debt with Banco do Brasil (not including the debentures listed above)listed), consisting of financings we contracted to pay debentures issued in 2002, 2005 and 2006, as well as a September 2010 fixed-rate credit agreement.increase our working capital.
Debentures:
· On October 30, 2012, Copel DistribuiçãoIn June 2013, Compagas issued R$1,000.062.6 million in five-yearof simple non-convertible debentures, allsingle series, of which were subscribed for by Banco do Brasil S.A. These debentures havethe floating type, private issue, with an interest rate equal to CDI + 0.99%TJLP index +2.7% per year, with semiannual interest payments. As of December 31, 2014, we had an aggregate balance of R$1,019.0 million of debt related to this issuance;
·On May 2014, Copel Holding issued R$1,000 million of non-convertible debentures, with an interest rate of 115.5% of the CDI index per year and with a five year maturity and payment of interest on a semesterquarterly basis. As of December 31, 2017, we had an aggregate balance of R$19.2 million of outstanding debt related to these debentures;
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· | In September 2013, Elejor issued R$203.0 million of non-convertible debentures, with an interest rate of 101.0% of the CDI index per year, with a five year maturity and payment of interest on a monthly basis. As of December 31, 2017, we had an aggregate balance of R$30.4 million of outstanding debt related to these debentures; |
· | In May 2014, Copel Holding issued R$1,000.0 million of non-convertible debentures, with an interest rate of 111.5% of the CDI index per year and with a five year maturity and payment of interest on a semester basis. As of December 31, 2017, we had an aggregate outstanding balance of R$672.5 million; |
· | In May 2015, Copel GeT issued R$1,000.0 million in five-year non-convertible debentures, with an interest rate of 113% of the CDI index per year and payment of interest on an annual basis. As of December 31, 2017, we had an aggregate balance of R$1,059.8 million of outstanding debt related to these debentures; |
· | In October 2015, Copel Telecom issued R$160.0 million in ten-year non-convertible debentures. These debentures have an interest rate equal to IPCA index + 7.96% per year, a five-year maturity and payment of interest on an annual basis. As of December 31, 2017, we had an aggregate balance of R$184.5 million of outstanding debt related to these debentures; |
· | In March 2016, Nova Asa Branca I, Nova Asa Branca II, Nova Asa Branca III, Nova Eurus IV and Ventos de Santo Uriel Wind Farms issued R$300.8 million in non-converstible debentures, with sixteen-year maturity and payment of interest on monthly basis. The interest rate of TJLP index + 2.02% per year is applicable to R$147.6 million and IPCA index + 9.87% per year is applicable to R$153.2 million. As of December 31, 2017, we had an aggregate balance of R$281.4 million of outstanding debt related to these debentures; |
· | In April 2016, Compagas issued R$33.6 million of simple non-convertible debentures, single series, of the floating type, private issue, with an interest rate equal to TJLP index + 2.17% per year, with a five-year maturity and payment of interest on a quartely basis. As of December 31, 2017, we had an aggregate balance of R$23.5 million of outstanding debt related to these debentures; |
· | In July 2016, Copel GeT issued R$1,000.0 million of three-year non-convertible debentures, with an interest rate of 121% of the CDI index per year and payment of interest on an annual basis. As of December 31, 2017, we had an aggregate balance of R$1,037.6 million of outstanding debt related to these debentures; |
· | In October 2016, Copel Distribuição issued R$500.0 million of non-convertible debentures, with an interest rate of 124% of the CDI index per year, with a three years maturity and payment of interest on an annual basis. As of December 31, 2017, we had an aggregate outstanding balance of R$502.2 million; |
· | In June 2017, Copel Holding issued R$520.0 million of non-convertible debentures, with an interest rate of 117% of the CDI index per year, with a two years maturity and payment of interest . As of December 31, 2017, we had an aggregate outstanding balance of R$542.9 million; |
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·In July 2017, Copel Telecom issued R$220.0 million in five-year non-convertible debentures. These debentures have an interest rate equal to IPCA index + 5.4329% per year, a five-year maturity and payment of interest on an semestral basis. As of December 31, 2017, we had an aggregate outstanding balance of R$1,010.5215.7 million;
·In October 2017, Copel Distribuição issued R$500.0 million of non-convertible debentures, with an interest rate of 126% of the CDI index per year, with a 4,5 years maturity and payment of interest on a semestral basis. As of December 31, 2017, we had an aggregate outstanding balance of R$501.8 million; and
· On June 10, 2014, theIn October 2017, Copel Brisa Potiguar wind farmsGeT issued R$330.0 million in1.0 billion of non-convertible debentures, guaranteed by Copel holding, with an interest rate of 126% of the CDI index plus 0.9% per year, with a 12-month maturity. Outfive years maturity and payment of this total, R$150.0 million have been used to repay promissory notes issued in connection with this project.interest on a semestral basis. As of December 31, 2014,2017, we had an aggregate outstanding balance of R$350.3999.4 million of outstanding debt related to these debentures..
BNDES
· In December 2013, we received approval for the BNDES financing of HPP Colíder in an aggregate amount of R$1,041.2 million. As of December 31, 2013, we had received R$840.1 million of this amount, with the remaining disbursements to be made in accordance with the construction schedule. Additionally, BNDES approved tothe finance of the Cerquilho III transmission substation in the amount of R$17.017.6 million, which was disbursed in a single installment. As of December 31, 2014,2017, the aggregate outstanding balance of these two contracts totaled R$868.1884.9 million;
· BNDES has provided a loan to Copel of R$339339.0 million to finance the construction of the Mauá Hydroelectric Plant. Mauá is owned by Consórcio Energético Cruzeiro do Sul, in which Copel has a 51.0% interest and Eletrosul has a 49.0% interest. BNDES is providing 50.0% of the loan amount, and Banco do Brasil S.A. is providing the remaining 50.0%. All the receivables arising from this plant were pledged in favor of BNDES and Banco do Brasil until full repayment of the loan. As of December 31, 2014,2017, we had an aggregate of R$298.4236.7 million in outstanding debt with BNDES and Banco do Brasil under this facility;
·We have R$130.8 million in outstanding debt with Eletrobras (i) for the Salto Caxias plant and (ii) under government programs to finance distribution projects;
·On September 2014, BNDES approved to finance the improvement of the distribution system of the greater Curitiba area. We have obtained a R$100.0 million funding on December 2014 and as of December 31, 2014, we had an aggregate outstanding balance of R$100.1 million;
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·In September 2012, we entered into a financing contract with BNDES in the total value of R$73.1 million for the construction of SHP Cavernoso II. As of December 31, 2014, we had an aggregate balance of R$67.7 million of outstanding debt related to this contract; and
· In December 2011, we entered into a financing contract with BNDES in the total value of R$44.7 million for the construction of Transmission Line Foz do Iguacu - Cascavel Oeste, with a 14 years term. As of December 31, 2014,2017, we had an aggregate of R$36.327.5 million in outstanding debt.debt;
·In March 2012, we entered into a financing contract with BNDES in the total value of R$282.1 million for the construction of GE Farol, Ge Boa Vista, GE São Bento do Norte and GE Olho D’Água Wind Farms with a 16 years term. As of December 31, 2017, we had an aggregate of R$253.8 million in outstanding debt;
·In September 2012, we entered into a financing contract with BNDES in the total value of R$73.1 million for the construction of SHP Cavernoso II. As of December 31, 2017, we had an aggregate balance of R$55.4 million of outstanding debt related to this contract;
·In December 2014, we entered into a financing contract with BNDES to finance the improvement of the distribution system of the greater Curitiba area. We have obtained a R$139.1 million funding on December 2014 and as of December 31, 2017, we had an aggregate outstanding balance of R$87.6 million; and
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·In June 2015, we entered into a financing contract with BNDES in the total value of R$124.0 million for the construction Santa Helena and Santa Maria Wind Farm. As of December 31, 2017, we had an aggregate balance of R$107.5 million of outstanding debt related to this contract.
ELETROBRAS
·We have R$35.0 million in outstanding debt with Eletrobras (i) for the Salto Caxias plant and (ii) under government programs to finance distribution projects;
FINEP
· In November 2010,July 2012, a loan agreement in the amount of R$52.2 million was signed by Copel Telecomunicações S.A. to partially support the BEL – Extra Broadband project. As of December 31, 2014,2017, we had an aggregate outstanding balance of R$33.216.3 million.
Promissory notes
·In May 2017, Copel GeT issued R$500.0 million of promissory notes with an interest rate of 117% of the CDI index per year, with a two years maturity. As of December 31, 2017, we had an aggregate outstanding balance of R$529.0 million.
We are party to several legal proceedings that could have a material adverse impact on our liquidity if the rulings are adverse to us. In addition, we are contesting a determination by ANEEL that would require us to pay additional amounts for energy we purchased for resale during the electricity-rationing period in 2001 and the first quarter of 2002. We are also involved in several lawsuits, including challenges to the legality of certain federal taxes, which have been assessed against us, claims by industrial customers that certain increases in electricity tariffs from March through November 1986 were illegal and several labor relatedlabor-related claims. These contingencies are described in “Item 8. Financial Information—Legal Proceedings”. If any of these claims are decided against us either individually or in the aggregate, they could have a material adverse effect on our liquidity and our financial condition.
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Contractual ObligationsCONTRACTUAL OBLIGATIONS
In the table below, we set forth certain of our contractual obligations as of December 31, 2014,2017, and the period in which such contractual obligations come due.
| Payments due by period | ||||
| Total | Less than | 1-3 years | 3-5 years | More than |
| (R$ million) | ||||
Contractual obligations: |
|
|
|
|
|
Loans and financing | 5,329.9 | 1,092.3 | 1,281.1 | 904.6 | 2,051.9 |
Debentures | 3,388.6 | 708.3 | 1,884.3 | 796.0 | - |
Suppliers(1) | 1,507.7 | 1,475.6 | 32.1 | - | - |
Purchase obligations(2) | 117,586.2 | 4,565.4 | 9,412.9 | 10,511.3 | 93,096.6 |
Concession payments(3) | 2,319.6 | 55.9 | 122.7 | 134.9 | 2,006.1 |
Eletrobras ‒ Itaipu | 10,327.0 | 1,163.8 | 1,931.2 | 2,221.6 | 5,010.4 |
Post-employment benefits(4) | 7,947.4 | 459.9 | 923.1 | 874.3 | 5,690.1 |
Total | 148,406.4 | 9,521.2 | 15,587.4 | 15,442.7 | 107,855.1 |
| Payments due by period | ||||||||
| Total | Less than | 1-3 years | 3-5 years | More than | ||||
| (R$ million) | ||||||||
Contractual obligations: |
|
|
|
|
| ||||
Loans and financing(1) | 4,763.9 | 994.0 | 1,992.7 | 436.7 | 1,340.5 | ||||
Debentures(2) | 7,577.0 | 1,963.0 | 3,315.4 | 1,844.8 | 453.8 | ||||
Suppliers(3) | 1,727.1 | 1,623.7 | 103.4 | - | - | ||||
Purchase obligations(4) | 111,289.9 | 5,131.9 | 8,748.0 | 9,062.0 | 88,348.0 | ||||
Concession payments(5) | 1,815.6 | 66.1 | 140.9 | 153.1 | 1,455.5 | ||||
Eletrobras ‒ Itaipu(6) | 7,298.2 | 1,099.5 | 2,454.8 | 2,550.6 | 1,193.3 | ||||
Installment due to the Federal Revenue of Brazil(7) | 926.5 | 113.5 | 190.3 | 113.7 | 509.0 | ||||
Post-employment benefits(8) | 9,710.9 | 566.0 | 1,200.1 | 1,137.6 | 6,807.2 | ||||
Sectoral Financial liabilities(9) | 300.6 | 199.8 | 100.8 |
|
| ||||
Total | 145,409.7 | 11,757.5 | 18,246.4 | 15,298.5 | 100,107.3 |
(1) Includes interest as agreed under agreements in the amount of R$1,066.4. For more details, see Note 23 to our audited consolidated financial statements.
(2)Includes interest as agreed under relevant agreements in the amount of R$1,495.4. For more details, see Note 24 to our audited consolidated financial statements.
(3)Mainly consists of Electricity purchased from Auction – CCEAR with balances falling due in less than 30 days and gas supplied by Petrobras to the Araucária Thermoelectric Plant.For more details, see Note 22 to our audited consolidates financial statements.
(2)(4)Consists of binding power purchase commitments. Includes monetary restatements as agreed under relevant agreements.
(3)(5)Payments to the federal government arising from Elejor, Mauá, Colíder, Cavernoso, Apucaraninha, Chopim I, Chaminé, Rio Jordão and Baixo Iguaçu facilities concession agreement. Includes interest and applicable monetary restatements.
(4)(6)Includes expected exchange variation.
(7)Income Tax and Social Contribution due by Copel Geração e Transmissão in 2014. Includes interest and applicable monetary restatement.
(8)For more details, see Note 2425 to our audited consolidated financial statements.
(9)For more details, see Note 9 to our audited consolidated financial statements.
We are also subject to risks with respect to tax, labor and civil claims and have provisioned R$1,546.61,512.1 million for accrued liabilities for legal proceedings related to these claims as of December 31, 2014.2017. For more information, see “Item 8. Financial Information—Legal Proceedings” and Notes 1517 and 2930 to our audited consolidated financial statements.
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Off-Balance Sheet ArrangementsOFF-BALANCE SHEET ARRANGEMENTS
We have not engaged in any off-balance sheet arrangements that have, or are reasonably likely to have a current or future effect on ourthe registrant’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
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Item 6. Directors, Senior Management and Employees
We are managed by:
· a Board of Directors, which may consist of seven toor nine members and is currently composed of nine members; and
· a Board of Executive Officers, which consists of fivesix members.
The Board of Directors ordinarily meets monthly. A majority of the members of the Board of Directors is required for the meeting to be held, and decisions are taken by a majority vote of those present at the meeting. For additional information, see “Item 10. Additional Information - Memorandum and Articles of Association”. The members of the Board of Directors are elected to serve for two-year terms and may be reelected. Among the current nine members of the Board of Directors:
·seven are elected by the controlling shareholders;
·one is elected by minority shareholders; and
·one is elected by our employees.
The member of our Board of Directors who is elected by the non-controlling shareholders has the right to veto (provided it is duly justified) the appointment of the independent accountant made by the majority of the members of our Board of Directors.
The State of Paraná and BNDES Participações S.A.– BNDESPAR (“BNDESPAR”), acting through the Company and Paraná Investimentos S.A., are parties to a Shareholders’ Agreement dated December 22, 1998, as amended on March 29, 2001, and with a term set to expire by December 21, 2018 (“Shareholders’ Agreement”). BNDESPAR is a wholly-owned subsidiary of BNDES. Under the Shareholders’ Agreement, the parties agree to exercise their voting rights so that:
·the State of Paraná appoints five members to the Board of Directors; and
·BNDESPAR appoints two members to the Board of Directors.
According to Brazilian Corporate Law, minority shareholders are entitled to appoint and remove a member of the Board of Directors, in a separate election, where such minority shareholders (i) hold at least 15% of the company’s voting shares or (ii) hold at least 10% of the company’s outstanding non-voting shares.
The terms of the current members of the Board of Directors expires in April 2019. The current members are as follows:
Name | Position | Since |
Mauricio Schulman | Chairman | 2017 |
Leila Abraham Loria | Director | 2017 |
Rogério Perna | Director | 2017 |
Olga Stankevicius Colpo | Director | 2017 |
George Hermann Rodolfo Tormin | Director | 2017 |
Sérgio Abu-Jamra Misael | Director | 2017 |
Adriana Angela Antoniolli | Director | 2017 |
Marco Antônio Barbosa Cândido | Director | 2018 |
Jonel Nazareno Iurk | Director | 2018 |
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The following are brief biographies of the current members of our Board of Directors:
Mauricio Schulman. Mr. Schulman was born onJanuary 21, 1932. He received a post-graduate degree in Business Administration (1972) and he took perfectioning training courses in Electricity and Economy in France (1960-1961). Mr. Schulman holds a degree in Civil Engineering, from Universidade Federal do Paraná (1950-1954). He was the Chief Executive Officer at Federação Nacional dos Bancos - Febraban/Fenaban (National Bank Federation) (1994-1997); Chairman of the Board of Directors at Light S.A. (1979-1980); Chairman of the Brazilian Committee at the Comisión de Integración Energética Regional - Bracier (1979-1980); Member of the Board of Directors at BNDE (1974-1980); Member of the National Monetary Council (Conselho Monetário Nacional) (1974-1979); Chief Executive Officer at the Banco Nacional de Habitação - BNH (1974-1979); State Secretary of the Treasury in the State of Paraná (1970-1974); Chief Corporate Management Officer and Chief Executive Officer at Eletrobras (1967-1970 and 1979-1980); Advisor at the Brazilian Federal Government Ministry of Planning and General Coordination (1964-1966); Chief Administrative Officer at Companhia Paranaense de Desenvolvimento Econômico do Paraná - Codepar (1962); and Civil Engineer and Chief Technical Officer at Companhia Paranaense de Energia - Copel (1956-1984).
Leila Abraham Loria. Ms. Loria was born on January 26, 1954. Ms. Loria took a Governance, Risk and Compliance training course at Risk University KPMG (2016). Ms. Loria received an MBA degree in Corporate Governance and Capital Markets for executives from B.I. International (2015) and a Master’s Degree in Business Administration from COPPEAD-UFRJ (1978). Ms. Loria holds a degree in Business Administration from Fundação Getúlio Vargas (1976). Ms. Loria is currently a Consultant/Counselor at LED Consultores. Previously, she was an Executive Officer at Telefonica Brasil and Member of the Board of Directors of Telefonica Vivo (2010-2015); Chairman and General Officer at TVA (Abril Group) and Member of the Board of Directors at Tevecap (1999-2010); General Officer and Member of the Board of Directors at Direct TV (1997-1999); Chief Business Officer at Walmart (1994-1997); and Chief Officer for Marketing, Sales, Business, Shopping and Human Resources at Mesbla (1978-1994).
Rogério Perna. Mr. Perna was born on October 5, 1969.Mr. Perna received a post-graduate degree in Controllership from Fundação Escola de Comércio Álvares Penteado - FECAP, São Paulo (1998).Mr. Perna holds a degree in Accounting Sciences from Centro de Ensino Superior de São Carlos (1991). Mr. Perna is currently the Chief Executive Officer and Chief Investors Relations Officer at Companhia Paranaense de Securitização - PRSEC; and Alternate Member of the Board of Directors at Companhia de Saneamento do Paraná - Sanepar. Previously, he was the Technical Consultant to the State Revenue Coordination - CRE, Department of Treasury of the state of Paraná (2015); Chief Financial Management and Investor Relations Officer at Companhia Paulistana de Securitização - SP (2011-2013); and Chief Financial Management Officer at Companhia São Paulo de Desenvolvimento e Mobilização de Ativos - SPDA (2011-2013).
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Olga Stankevicius Colpo. Ms. Colpo was born on May 26, 1952. Ms. Colpo received an international executive MBA degree from FIA/USP (2000); she took a specialization course inInternational Business at Harvard University (1996), a specialization course in Managing Managers at Michigan University (1986); a Continued Education Program in Human Resources Management from Fundação Getúlio Vargas (1984); and a specialization course in Organizational Psychology at UMC (1975). Ms. Colpo is currently a Member of the Board of Directors and Audit Committee at Banco BMG S.A.; Member of the Consulting Board of the International Executive MBA at FIA; Counselor and Member of the Executive Board at Childhood Brasil; Member of the Risks and Strategy Committees at AACD; Member of the Fiscal Board at Comunitas; Member of the Family Businesses Comission at IBGC; Visiting Professor at the International Executive MBA program at FIA/USP; Visiting Professor of the Board of Directors Training Course at IBGC; and Consulting specialist in Strategic Governance. Previously, she was the Chief Executive Officer at Participações Morro Vermelho S.A. (2009-2016); Partner at PWC - PricewaterhouseCoopers (1999-2009); and Partner at Coopers & Lybrand (1974-1999).
George Hermann Rodolfo Tormin. Mr. Tormin was born on March 24, 1960. Mr. Tormim holds a degree in Civil Engineering from Universidade Federal do Rio de Janeiro (1983). Mr. Tormim is currently the General Director of the Department of Treasury of the state of Paraná (since 2015) and a Member of the Fiscal Council at Companhia de Saneamento do Paraná - Sanepar. Previously, he was a Member of the Fiscal Council at Companhia Paranaense de Energia - Copel (2015-2016); Assistant Secretary of the Treasury Department of Salvador City and City Treasurer (2013-2014); Assistant Secretary of the Finance Department of the City of São Paulo (2005-2006 and 2011-2012); Chief Executive Officer at Companhia São Paulo de Desenvolvimento de Ativos - SPDA (2011-2012); Chief Executive Officer at Companhia Paulistana de Securitização - SPSec (2011-2012); Assistant Secretary of the Department of Treasury of the state of São Paulo and Chief Executive Officer at Companhia Paulista de Parcerias - CPP (2007-2010); Assistant Secretary of the Treasury Department of São Paulo City (2005-2006); Chief Financial, Management and Investor Relations Officer at Companhia de Saneamento de Minas Gerais - Copasa (2003-2004); Executive Officer at Fundação Nacional de Saúde - Funasa (1999-2002); Assistant Superintendent of Operations and Projects at Zona Franca de Manaus - Suframa. (1996-1999); Assistant Secretary of the Federal Ministry of Planning and Budget (1995-1996); Head of the Technological Division of the Secretariat of the Federal Revenue (1994-1995); General Coordinator of the Management Secretariat of the Ministry of Social Welfare(1993-1994); Monitoring and Assessment Coordinator of the Secretariat of the Federal Revenue (1991-1993); and Tax Auditor at the Brazilian Federal Revenue (1986).
Sérgio Abu-Jamra Misael. Mr. Misael was born on November 6, 1949. Mr. Misael received a post-graduate degree in Business Administration - Management for Engineers from PUC-PR (1989). Mr. Misael holds a degree in Civil Engineering from UFPR (1974). He is currently the Chief Executive Officer and co-owner at Ytuporanga Engenharia, Oceanografia e Consultoria Ltda. Previously, he was the Head of the Department of Construction Support, Planning, Measurements and Contract Negotiations at Itaipu Binacional (1985-1992); Construction Superintendent at Itaipu Binacional (1992-1998); Member of the Brazilian Committee on Dams - CBDB (1993-1995); Coordinator of the CDBD Technical Commissions (1995-1998 and 2013-2016); Board Member at Fundação Itaipu de Assistência Social - FIBRA (1993-1997); President at Companhia de Habitação de Curitiba - COHAB-CT (1998-2001); and Member of the Núcleo Paranaense de Energia - NPEnergia/UTFPR – Public Policies and Energetic Planning (2012-2017).
Adriana Angela Antoniolli. Ms. Antoniolli was born on November 19, 1966.Ms. Antoniolli received a post-graduate degree in Applied Law from Escola da Magistratura do Paraná (2011) and a post-graduate degree in Marketing and Advertising from Instituto Superior de Pós-graduação - ISPG (2000). Ms. Antoniolli holds a degree in Law from Universidade Tuiuti do Paraná (2008) and a degree in Accounting from Faculdade de Educação, Ciências e Letras de Cascavel (1988). She is currently a Regulatory Analyst at Copel. Previously, she acted as Services Department Manager at Copel (2013-2015); East Revenue Department Manager at Copel (2009-2013); and Business Procedures Department Manager at Copel (2008).
Marco Antônio Barbosa Cândido. Mr. Cândido was born on March 6, 1969. Mr. Cândido holds
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a Ph.D. degree in Production Engineering from Universidade Federal de Santa Catarina - UFSC (1997), a Master degree in Production Engineering from Universidade Federal de Santa Catarina - UFSC (1994) and a degree in Aeronautical Mechanics Engineering from Instituto Tecnológico de Aeronáutica - ITA (1991). Mr. Cândido is currently a member of the Board of Directors of, Chief Executive Officer and Founding Partner at MBC Consultoria, member of the Board of Directors of Hospital Santa Rita and Santa Rita Saúde health care provider in the city of Maringá – PR, and member of the Board of Directors at the hotel group Rafain, in the city of Foz do Iguaçu - PR. Previously, he was a professor and researcher at Pontifícia Universidade Católica do Paraná - PUCPR (1995-2013); Chief Executive Officer at Associação Paranaense de Cultura - APC, a parent company of Pontifícia Universidade Católica do Paraná - PUCPR (2005-2012); Chief Executive Officer at Grupo Marista (2012-2013); Chief Executive Officer at Grupo Paysage (2013-2015); member of the Board of Directors at Sistema de Saúde Mãe de Deus, health care provider in the state of Rio Grande do Sul (2014-2015); and member of the Board of Directors at Grupo Positivo (2014-2016).
Jonel Nazareno Iurk.Mr. Iurk was born on April 09, 1955. Mr. Iurk received his Master’s degree in Soil Science, from Universidade Federal do Parana - UFPR (2005); and Specialization in Management and Environmental Engineering, from Universidade Federal do Paraná - UFPR (1999). Mr. Iurk holds a Bachelor’s degree in Civil Engineering from Universidade Estadual de Ponta Grossa - UEPG (1978); and a Teaching degree in Mathematics, from Universidade Estadual de Ponta Grossa - UEPG (1975). He is currently Copel’s Chief Executive Officer. Previously he acted as the Chief Executive Officer at Companhia Paranaense de Gás - Compagas (2017-2018); Chief Business Development Officer at Companhia Paranaense de Energia - Copel (2013-2017); Chairman of the Board of Directors at Copel Telecomunicações S.A. and Copel Renováveis S.A., and member of the Board of Directors at Copel Geração e Transmissão S.A. and Copel Renováveis S.A. (2015-2017); Chief Environmental and Corporate Citzenship Officer at Companhia Paranaense de Energia - Copel (2012-2013); Secretary of Environment and Water Resources for the State of Paraná (2011-2013); Executive Technical Officer at ECOBR - Engenharia e Consultoria Ambiental (2002-2010); Chief Official at Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis - Ibama for the State of Paraná (1995-1999); Environmental Sanitation Coordinator at Coordenação da Região Metropolitana de Curitiba - Comec (1994); and Operational Development Engineer and Coordinator of Rural Sanitation and Environmental Studies at Companhia de Saneamento do Paraná - Sanepar (1992-2002).
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Our Board of Executive Officers meets every two weeks and is responsible for the daily management of the Company. Each Executive Officer also has individual responsibilities established by the Board’s internal rules.
According to our bylaws, our Board of Executive Officers consists of six members. The Executive Officers are elected by the Board of Directors for two-year terms but may be removed by the Board of Directors at any time. Under the Shareholders’ Agreement, BNDESPAR has the right to appoint one member to the Board of Executive Officers. The terms of the current members of the Board of Executive Officers expire in December 2019. The current members are as follows:
Name | Position | Since |
Jonel Nazareno Iurk | Chief Executive Officer | 2018 |
Vacant | Chief Business Management Officer | 2018 |
Adriano Rudek de Moura | Chief Financial and Investor Relations Officer | 2017 |
José Marques Filho | Chief Business Development Officer | 2018 |
Harry Françóia Junior | Chief Legal and Institutional Relations Officer | 2018 |
Vicente Loiacono Neto | Chief Governance, Risk and Compliance Officer | 2018 |
The following are brief biographies of the current members of our Board of Executive Officers:
Jonel Nazareno Iurk.Mr. Iurk has been our Chief Executive Officer since April 16, 2018. For biographical information regarding Mr. Iurk, see “Board of Directors”.
Adriano Rudek de Moura. Mr. Moura was born on September 25, 1962. Mr. Moura took a professional development course at Duke’s Fuqua School of Business (2010) and a professional development course at Harvard Business School (2007). Mr. Moura received a post-graduation degree in Finance and Controllership from Fundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI/USP (1997). Mr. Moura holds a degree in Accounting from Centro Universitário Ítalo Brasileiro – Unítalo (1985). Mr. Moura is currently the Chief Financial Officer of Copel Geração e Transmissão S.A. - Copel GeT; Chief Financial Officer of Copel Distribuição S.A. - Copel DIS; Chief Financial Officer of Copel Comercialização S.A. - Copel COM; and Chief Financial Officer of Copel Renováveis S.A. - Copel REN. Previously, he was the Vice-president and Chief Management, Financial and Investor Relations Officer at Elecrolux for Latin America (2003-2017); Chief Management, Financial and Investor Relations Officer at Electrolux do Brasil (1999-2003); Controller at Electrolux do Brasil (1997-1999); Vice-president at Associação Nacional de Fabricantes de Produtos Eletroeletrônicos (National Association of Home Appliance Manufacturers) - Eletros (2013-2015); Member of the Board of Directors at CTI (2011-2017); Member of the Board of Directors at Eletros (2013-2015); Member of the Fiscal Council at Gafisa (2009-2014); Member of the Fiscal Council at Tenda (2009-2014); Member of the Fiscal Council at Alphaville (2012-2013); graduate school Professor at Fundação Armando Alvares Penteado - FAAP (1999); Professor at Faculdade de Administração de Empresas e Economia do Paraná – FAE (1995); and Auditor and consultant at Arthur Andersen (1982-1997).
Harry Françóia Junior. Mr. Françóia Junior was born onFebruary 5, 1971. Mr. Françóia Junior took a course in Contemporary Law at Levin College of Law - University of Florida, Gainesville, FL, USA. (2003). Mr. Françóia Junior received a post-graduate degree in Administrative Law from Universidade Federal de Santa Catarina (2001) and in Civil Procedure Law from Instituto Brasileiro de Estudos Jurídicos - IBEJ (1997). Mr. Françóia Junior holds a degree in Law from Pontifícia Universidade Católica - PUC - PR (1996). Mr. Françóia Junior is currently Chief Legal and Institutional RelationsOfficer of Copel Geração e Transmissão S.A., Copel Distribuição S.A., Copel Comercialização S.A. and Copel Renováveis S.A. Previously, he was a Member of the Board of Directors of Copel Geração e Transmissão S.A. and Member of the Board of Directors of Copel Renováveis S.A. Previously, he was Chief Business Development Officer (2017-2018), and the Chief Assistant Officer of Copel Comercialização S.A. (2013-2017); Managing Director and Presidential General Secretary for Assembleia Legislativa do Estado do Paraná (2015-2016); Vice President of Comissão de Sociedade de Advogados for OAB/PR - gestão (2007-2009 and 2013-2015); Vice President of Juridical and Political Affairs for Federação das Associações Comerciais e Industriais do Paraná - Faciap (2002-2006); Member of the Environmental Law and Consumer Defense Commission for OAB/PR - (1998-2003); Lawyer in Corporate Law segment mainly in the areas of Company and Tax Law for Harry Françóia - Advogados Associados (1999-2016); Legal and Accounting Adviser for Harry Françóia - Assessoria e Consultoria Empresarial S.C. Ltda. (1996-1999); and he carried out activities in the following banks: Banorte S.A. - management accounting (1993-1995); Citibank S.A. - serving companies (1991-1992); Bamerindus do Brasil S.A. - management assistant, accounting and clearing (1989-1991); and Meridional S.A. (1985-1986).
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Vicente Loiacono Neto.Mr. Loiácono was born on June 4, 1983. He received a Post-Graduate degree in Civil Procedure Law from Universidade do Sul de Santa Catarina (2010). He holds a Bachelor’s degree in Law from Faculdades Integradas Curitiba (2007) and he is currently Chief Governance, Risk and Compliance Officer at Companhia Paranaense de Energia - Copel. Mr. Loiácono has been a Lawyer at Company since 2011, where he also served as Advisor to the CEO (2017-2018); Regulatory Area Manager at Copel Distribuição S.A. (2016-2017); Advisor to the Chief Corporate Management Officer of Companhia Paranaense de Energia - Copel (2013-2016); Member of the Fiscal Council of Fundação Copel de Previdência e Assistência Social (2015); Member of the Ethical Guidance Council of Companhia Paranaense de Energia - Copel (2014); and Advisor to the Chief Legal Officer of Companhia Paranaense de Energia - Copel (2013). Previously, Mr. Loiácono had served as Lawyer at Punho Construtora e Serviços Ltda. (2008-2010); Advisor to the Appeal Panel of Tribunal de Justiça do Paraná (2007-2008); and Legal Assistant at Instituto Curitiba de Informática (2005-2006).
José Marques Filho.Mr. Marques Filho was born on April 11, 1958. He received a Doctor’s degree in Civil Engineering from Universidade Federal do Rio Grande do Sul – UFRGS (2005); and a Master’s degree in Civil Engineering from Universidade de São Paulo – USP (1990). He holds a Bachelor’s degree in Civil Engineering from Universidade de São Paulo – USP (1980). He is currently Chief Business Development Officer; Vice Chairman of Comitê Brasileiro de Barragens - CBDB (since 2017), where he serves as Coordinator of the Comitê Técnico de Uso de Concreto em Barragens (since 2003) and represents Brazil on the Committee on Concrete Dams of the International Commission on Large Dams - ICOLD; Chief Executive Officer of Paraná Gás (since 2015); Member of the Board of Directors of Instituto Brasileiro do Concreto - Ibracon (since 2014); Member of the Board of Directors of Sistema Metereológico do Paraná - Simepar (since 2013); General Coordinator and Technical Officer of Consórcio São Jerônimo (since 1996); and Assistant Professor at Universidade Federal do Paraná - UFPR (since 1992). Previously, he was an Advisor to the Chief Executive Officer of Companhia Paranaense de Gás - Compagas (2017-2018), where he was also a Member of the Board of Directors (2003); Advisor to the Chief Business Development Officer (2013-2017) and to the Chief Environment and Corporate Citizenship Officer of Companhia Paranaense de Energia - Copel (2011-2013); CEO and Deputy CEO of Instituto Brasileiro do Concreto - Ibracon (2012-2013 e 2010-2011); General coordinator of the Materials and Structures Laboratory at Institutos Lactec (2003-2004), where he was also a Member of the Board of Directors (2000-2002); Chairman of the Board of Directors of Centrais Elétricas do Rio Jordão - Elejor (2001-2003); and civil engineer at Companhia Paranaense de Energia - Copel (1994-2017).
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We have a permanent Fiscal Council, which generally meets monthly. The Fiscal Council consists of five members and five alternates elected for one-year terms by the shareholders at the annual meeting. The Fiscal Council, which is independent of our management and of our external auditors, is responsible for:
·reviewing our financial statements and reporting on them to our shareholders;
·issuing special reports on proposed changes in capitalization, corporate budgets and proposed dividend distributions and any corporate reorganization; and
·in general, supervising the activities of management and reporting on them to our shareholders.
The following table lists the current and alternate members of the Fiscal Council, who were appointed at the 62nd annual shareholders’ meeting held on April 28, 2017. The term of all members of the Fiscal Council indicated below will expire in April 2018, but, under Brazilian law, such members should remain in office until a new member is appointed by the Company’s Shareholders Annual Meeting, which was convened to occur on June 15, 2018.
Name | Since |
Mauro Ricardo Machado Costa | 2017 |
Roberto Lamb | 2017 |
Letícia Pedercini Issa Maia | 2017 |
Alternates | |
Roberto Brunner | 2011 |
Gilmar Mendes Lourenço | 2013 |
Kurt Janos Toth | 2017 |
Alexandre Pedercini Issa | 2017 |
* Two position are vacant.
** One position is vacant.
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Pursuant to Rule 10A-3 under the Securities Exchange Act and our bylaws, our Audit Committee is composed of at least three members of our Board of Directors, each of whom serves a term of two years, and may be re-elected. Pursuant to the Statutory Audit Committee charter, the Statutory Audit Committee members are appointed by, and may be replaced by, a resolution taken by our Board of Directors. The members of the Statutory Audit Committee are Mr. Mauricio Schulman (chairman), Mr. Rogério Perna (financial expert), Ms. Leila Abraham Loria, Ms. Olga Stankevicius Colpo and Mr. Marco Antônio Barbosa Cândido. All of the members of the Statutory Audit Committee are members of our Board of Directors. The Statutory Audit Committee is responsible for helping to prepare our financial statements, ensuring that we are in compliance with all legal requirements related to our reporting obligations, monitoring the work of the independent auditors and our staff who are responsible for internal auditing of the Company and reviewing the effectiveness of our internal control and risk management procedures and staff.
Under Brazilian Corporate Law, the function of hiring independent auditors is reserved for the board of directors of a company. As a result, our Board of Directors acts as our Statutory Audit Committee, as specified in Section 3(a)(58) of the Securities Exchange Act, for the purposes of approving, on a case-by-case basis, any engagement of our independent auditors for audit and non-audit services provided to us or our subsidiaries. Except in these respects, our Statutory Audit Committee is comparable to and performs the functions of audit committees of U.S. companies.
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COMPENSATION OF DIRECTORS, OFFICERS, FISCAL COUNCIL MEMBERS AND AUDIT COMMITTEE MEMBERS
Under Brazilian law, the total compensation of the Board of Directors, Executive Board and Fiscal Council is established annually by our general shareholders meeting. Under Section 162 of the Brazilian Corporate Law, the compensation of the members of our fiscal council must be equal to, or greater than, 10% of the average compensation paid to the members of our Executive Board (excluding benefits and profit-sharing plans, if applicable). The members of our Fiscal Council receive 15% of the monthly compensation of the Chief Executive Officer. Finally, the members of our audit committee (who are also members of our Board of Directors) receive R$5,000 in addition to the monthly compensation paid to the members of the Fiscal Council.
For the year ended December 31, 2017, the aggregate amount of compensation paid by us to the members of our Board of Directors, Board of Executive Officers and Fiscal Council was R$8.5 million, of which 80.1% was for our Board of Executive Officers, 13.0% was for our Board of Directors, and 6.9% was for our Fiscal Council, as approved by our 62nd annual shareholders’ meeting held on April 28, 2017.
The following table shows additional details about the compensation paid to the members of our Board of Directors, Executive Board and Fiscal Council for the periods indicated.
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Adriano Rudek de Moura. Mr. Moura was born on September 25, 1962. Mr. Moura took a professional development course at Duke’s Fuqua School of Business (2010) and a professional development course at Harvard Business School (2007). Mr. Moura received a post-graduation degree in Finance and Controllership from Fundação Instituto de Pesquisas Contábeis, Atuariais e Financeiras - FIPECAFI/USP (1997). Mr. Moura holds a degree in Accounting from Centro Universitário Ítalo Brasileiro – Unítalo (1985). Mr. Moura is currently the Chief Financial Officer of Copel Geração e Transmissão S.A. - Copel GeT; Chief Financial Officer of Copel Distribuição S.A. - Copel DIS; Chief Financial Officer of Copel Comercialização S.A. - Copel COM; and Chief Financial Officer of Copel Renováveis S.A. - Copel REN. Previously, he
117 Vicente Loiacono Neto.Mr. Loiácono was born on June 4, 1983. He received a Post-Graduate degree in Civil Procedure Law from Universidade do Sul de Santa Catarina (2010). He holds a Bachelor’s degree in Law from Faculdades Integradas Curitiba (2007) and he is currently Chief Governance, José Marques Filho.Mr. Marques Filho was born on April 11, 1958. He received a Doctor’s degree in Civil Engineering from Universidade Federal do Rio Grande do Sul – UFRGS (2005); and a Master’s degree in Civil Engineering from Universidade de São Paulo – USP (1990). He holds a Bachelor’s degree in Civil Engineering from Universidade de São Paulo – USP (1980). He is currently Chief Business Development Officer; Vice Chairman of Comitê Brasileiro de Barragens - CBDB (since 2017), where he serves as Coordinator of the Comitê Técnico de Uso de Concreto em Barragens (since 2003) and represents Brazil on the Committee on Concrete Dams of the International Commission on Large Dams - ICOLD; Chief Executive Officer of Paraná Gás (since 2015); Member of the Board of Directors of Instituto Brasileiro do Concreto - Ibracon (since 2014); Member of the Board of Directors of Sistema Metereológico do Paraná - Simepar (since 2013); General Coordinator and Technical Officer of Consórcio São Jerônimo (since 1996); and Assistant Professor at Universidade Federal do Paraná - UFPR (since 1992). Previously, he was an Advisor to the Chief Executive Officer of Companhia Paranaense de 118 We have a permanent Fiscal Council, which generally meets monthly. The Fiscal Council consists of five members and five alternates elected for one-year terms by the shareholders at the annual meeting. The Fiscal Council, which is independent of our management and of our external auditors, is responsible for: ·reviewing our financial statements and reporting on them to our shareholders; ·issuing special reports on proposed changes in capitalization, corporate budgets and proposed dividend distributions and any corporate reorganization; and ·in general, supervising the activities of management and reporting on them to our shareholders. The following table lists the current and alternate members of the
* Two position are vacant. ** One position is vacant. 119
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Under Brazilian law, the For the year ended December 31, 2017, the aggregate amount of compensation paid by us to the members of our Board of Directors, The following table shows additional details about the compensation paid to the members of
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