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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 20-F

 

 

Date of event requiring this shell company report, . . . . . . . . . . . . . . . . . . .

 

Commission file number: 001-37723

 

ENEL CHILE S.A.
(Exact name of Registrant as specified in its charter)
	ENEL CHILE S.A.
	(Translation of Registrant’s name into English)
	CHILE
	(Jurisdiction of incorporation or organization)
	Santa Rosa 76, Santiago, Chile
	(Address of principal executive offices)
	Nicolás Billikopf, phone: (56-2) 2353-4628, nicolas.billikopf@enel.com, Santa Rosa 76, Piso 15, Santiago, Chile
	(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:

 

 

*              Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission.

 

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

 

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Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

x Yes   o 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.

o Yes   x No

 

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.

x Yes   o No

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

x Yes   o No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

 

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. o

 

†The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

 

 

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.

o Item 17   o Item 18

 

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 Exchange Act).

o Yes   x No

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report 

 

Shares of Common Stock: 49,092,772,762

 

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Enel Chile’s Organizational Chart(1)

As of December 31, 2018

 

 

(1)         Only principal operating consolidated entities are presented here. The percentage listed in the box for each of Enel Chile’s consolidated subsidiaries represents its economic interest in such consolidated subsidiary.

(2)         Excluding treasury stock.

 

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			Page
GLOSSARY			4
INTRODUCTION			7
PRESENTATION OF INFORMATION			8
FORWARD-LOOKING STATEMENTS			10
PART I
Item 1.	Identity of Directors, Senior Management and Advisers		11
Item 2.	Offer Statistics and Expected Timetable		11
Item 3.	Key Information		11
Item 4.	Information on the Company		22
Item 4A.	Unresolved Staff Comments		56
Item 5.	Operating and Financial Review and Prospects		56
Item 6.	Directors, Senior Management and Employees		78
Item 7.	Major Shareholders and Related Party Transactions		87
Item 8.	Financial Information		89
Item 9.	The Offer and Listing		91
Item 10.	Additional Information		92
Item 11.	Quantitative and Qualitative Disclosures About Market Risk		107
Item 12.	Description of Securities Other Than Equity Securities		110
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies		112
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds		112
Item 15.	Controls and Procedures		112
Item 16.	Reserved		113
Item 16A.	Audit Committee Financial Expert		113
Item 16B.	Code of Ethics		113
Item 16C.	Principal Accountant Fees and Services		114
Item 16D.	Exemptions from the Listing Standards for Audit Committees		115
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers		115
Item 16F.	Change in Registrant’s Certifying Accountant		115
Item 16G.	Corporate Governance		115
Item 16H.	Mine Safety Disclosure		115
PART III
Item 17.	Financial Statements		116
Item 18.	Financial Statements		116
Item 19.	Exhibits		116

 

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GLOSSARY

 

 

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INTRODUCTION

 

As used in this Report on Form 20-F (“Report”), first person personal pronouns such as “we”, “us” or “our”, as well as “Enel Chile” or the “Company”, refer to Enel Chile S.A. and our consolidated subsidiaries unless the context indicates otherwise. Unless otherwise noted, our interest in our principal subsidiaries, and jointly-controlled companies and associates is expressed in terms of our economic interest as of December 31, 2018.

 

We are a Chilean company engaged in the electricity generation and distribution businesses in Chile through our subsidiaries and affiliates. As of the date of this Report and after giving effect to the 2018 Reorganization (described in “Item 4. Information on the Company — A. History and Development of the Company — the 2018 Reorganization”), we own 93.6% of Enel Generación Chile S.A. (“Enel Generation”), a Chilean electricity generation company holding electricity generation operations in Chile, and 99.1% of Enel Distribución Chile S.A. (“Enel Distribution”), a Chilean electricity distribution company with operation in the Santiago Metropolitan Region.

 

On April 2, 2018, as part of the 2018 Reorganization, Enel Green Power Latin America S.A. (“EGPL”), a Chilean non-conventional electricity generation company holding non-conventional electricity generation operations in Chile, merged with us.  As a result, we now wholly own and consolidate Enel Green Power Chile Ltda. (“EGP Chile”).  For additional information relating the company and the corporate reorganization completed in 2018, please see “Item 4. Information on the Company — A. History and Development of the Company — The 2018 Reorganization”.

 

We are a publicly held limited liability stock corporation organized on March 1, 2016, under the laws of the Republic of Chile as a result of a corporate reorganization completed in 2016 by the former Enersis S.A., which separated its Chilean businesses from its non-Chilean businesses.  On October 18, 2016, and as part of this process, (i) Endesa Chile changed its name to Enel Generación Chile S.A.; (ii) Chilectra Chile S.A. changed its name to Enel Distribución Chile S.A.; and (iii) Enersis Chile S.A. changed its name to Enel Chile S.A. For additional information relating the company and the corporate reorganization completed in 2016, please see “Item 4. Information on the Company — A. History and Development of the Company — The 2016 Reorganization”.

 

As of the date of this Report, Enel S.p.A. (“Enel”), an Italian energy company with multinational operations in the power and gas markets, owns 61.9% (excluding treasury stock) of us and is our ultimate controlling shareholder.

 

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PRESENTATION OF INFORMATION

 

Financial Information

 

In this Report, unless otherwise specified, references to “U.S. dollars” or “US$”, are to dollars of the United States of America (“United States”); references to “pesos” or “Ch$” are to Chilean pesos, the legal currency of Chile; and references to “UF” are to Unidades de Fomento.  The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is adjusted daily to reflect changes in the official Consumer Price Index (“CPI”) of the Chilean National Institute of Statistics (Instituto Nacional de Estadísticas or “INE”).  The UF is adjusted in monthly cycles.  Each day in the period beginning on the tenth day of the current month through the ninth day of the succeeding month, the nominal peso value of the UF is indexed in order to reflect a proportionate amount of the change in the Chilean CPI during the prior calendar month.  As of December 31, 2018, one UF was equivalent to Ch$ 27,565.79.  The U.S. dollar equivalent of one UF was US$ 39.68 as of December 31, 2018, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2018 of Ch$ 694.77 per US$ 1.00.  The U.S. dollar observed exchange rate (dólar observado) (the “Observed Exchange Rate”), which is reported by the Central Bank of Chile and published daily on its webpage, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market. Unless the context specifies otherwise, all amounts translated from Chilean pesos to U.S. dollars or vice versa, or from UF to Chilean pesos, have been carried out at the rates applicable as of December 31, 2018.

 

The Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to maintain the Observed Exchange Rate within a desired range.

 

Our consolidated financial statements and, unless otherwise indicated, other financial information concerning us included in this Report are presented in Chilean pesos.  We have prepared our consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).

 

All of our subsidiaries are integrated and all their assets, liabilities, income, expenses and cash flows are included in the consolidated financial statements after making the adjustments and eliminations related to intra-group transactions.  Our participation in associated companies over which we exercise significant influence are included in our consolidated financial statements using the equity method.  For detailed information regarding consolidated entities, jointly-controlled entities and associated companies, see Appendices 1, 2 and 3 to the consolidated financial statements.

 

Solely for the convenience of the reader, this Report contains translations of certain Chilean peso amounts into U.S. dollars at specified rates.  Unless otherwise indicated, the U.S. dollar equivalent for information in Chilean pesos is based on the Observed Exchange Rate for December 31, 2018, as defined in “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”.  The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos.  No representation is made that the Chilean peso or U.S. dollar amounts shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, as the case may be, at such rate or at any other rate.  See “Item 3. Key Information — A. Selected Financial Data — Exchange Rates”.

 

Technical Terms

 

References to “TW” are to terawatts (1012 watts or a trillion watts); references to “GW” and “GWh” are to gigawatts (109 watts or a billion watts) and gigawatt hours, respectively; references to “MW” and “MWh” are to megawatts (106 watts or a million watts) and megawatt hours, respectively; references to “kW” and “kWh” are to kilowatts (103 watts or a thousand watts) and kilowatt hours, respectively; references to “kV” are to kilovolts, and references to “MVA” are to megavolt amperes. References to “BTU” and “MBTU” are to British thermal unit and million British thermal units, respectively. A “BTU” is an energy unit equal to approximately 1,055 joules. References to “Hz” are to hertz; and references to “mtpa” are to metric tons per annum. Unless otherwise indicated, statistics provided in this Report with respect to the installed capacity of electricity generation facilities are expressed in MW. One TW equals 1,000 GW, one GW equals 1,000 MW and one MW equals 1,000 kW. The installed capacity we are presenting in this Report corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its own operation.

 

Statistics relating to aggregate annual electricity production are expressed in GWh and based on a year of 8,760 hours, except for leap years, which are based on 8,784 hours. Statistics relating to installed capacity and production of the electricity industry do not include electricity of self-generators.

 

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Energy losses experienced by generation companies during transmission are calculated by subtracting the number of GWh of energy sold from the number of GWh of energy generated (excluding their own energy consumption and losses on the part of the power plant), within a given period. Losses are expressed as a percentage of total energy generated.

 

Energy losses during distribution are calculated as the difference between total energy purchased (GWh of electricity demand, including own generation) and the energy sold excluding tolls and energy consumption not billed (also measured in GWh), within a given period. Distribution losses are expressed as a percentage of total energy purchased. Losses in distribution arise from illegally tapped energy as well as technical losses.

 

Calculation of Economic Interest

 

References are made in this Report to the “economic interest” of Enel Chile in its related companies.  We could have direct and indirect interest is such companies. In circumstances where we do not directly own an interest in a related company, our economic interest in such ultimate related company is calculated by multiplying the percentage of economic interest in a directly held related company by the percentage of economic interest of any entity in the ownership chain of such related company.  For example, if we directly own a 6% equity stake in an associate company and 40% is directly held by our 60%-owned subsidiary, our economic interest in such associate would be 60% times 40% plus 6%, equal to 30%.

 

Rounding

 

Certain figures included in this Report have been rounded for ease of presentation.  Because of this rounding, it is possible that amounts in tables may not add up to exactly the same amounts as the sum of the entries.

 

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FORWARD-LOOKING STATEMENTS

 

This Report contains statements that are or may constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  These statements appear throughout this Report and include statements regarding our intent, belief or current expectations, including but not limited to any statements concerning:

 

·                           our capital investment program;

·                           trends affecting our financial condition or results from operations;

·                           our dividend policy;

·                           the future impact of competition and regulation;

·                           political and economic conditions in the countries in which we or our related companies operate or may operate in the future;

·                           any statements preceded by, followed by or that include the words “believes,” “expects,” “predicts,” “anticipates,” “intends,” “estimates,” “should,” “may” or similar expressions; and

·                           other statements contained or incorporated by reference in this Report regarding matters that are not historical facts.

 

Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements.  Factors that could cause actual results to differ materially include, but are not limited to:

 

·                           demographic developments, political events, economic fluctuations and interventionist measures by authorities in Chile;

 

·                           water supply, droughts, flooding and other weather conditions;

 

·                           changes in Chilean environmental regulations and the regulatory framework of the electricity industry;

 

·                           our ability to implement proposed capital expenditures, including our ability to arrange financing where required;

 

·                           the nature and extent of future competition in our principal markets; and

 

·                           the factors discussed below under “Risk Factors.”

 

You should not place undue reliance on such statements, which speak only as of the date that they were made.  Our independent registered public accounting firm has not examined or compiled the forward-looking statements and, accordingly, does not provide any assurance with respect to such statements.  You should consider these cautionary statements together with any written or oral forward-looking statements that we may issue in the future.  We do not undertake any obligation to release publicly any revisions to forward-looking statements contained in this Report to reflect later events or circumstances or to reflect the occurrence of unanticipated events, except as required by law.

 

For all these forward-looking statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

 

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PART I

 

Item 1.         Identity of Directors, Senior Management and Advisers

 

Not applicable.

 

Item 2.         Offer Statistics and Expected Timetable

 

Not applicable.

 

Item 3.         Key Information

 

A.                                    Selected Financial Data.

 

The following selected consolidated financial data should be read in conjunction with our consolidated financial statements included in this Report.  The selected consolidated financial data as of December 31, 2018, and 2017 and for each of the years in the three-year period ended December 31, 2016, are derived from our audited consolidated financial statements included in this Report.  The selected consolidated financial data as of December 31, 2016, 2015 and 2014, and for the years ended December 31, 2015, and 2014 are derived from our consolidated financial statements not included in this Report.  Our consolidated financial statements were prepared in accordance with IFRS, as issued by the IASB.

 

Amounts in the tables are expressed in millions, except for ratios, operating data and data for shares and American Depositary Shares (“ADS”).  For the convenience of the reader, all data presented in U.S. dollars in the following summary, as of and for the year ended December 31, 2018, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 694.77 per US$ 1.00.  The Observed Exchange Rate, which is reported and published daily on the Central Bank of Chile’s web page, corresponds to the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market.  For more information concerning historical exchange rates, see “Item 3. Key Information — A. Selected Financial Data— Exchange Rates” below.

 

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The following tables set forth our selected consolidated financial data and operating data for the years indicated:

 

 

		As of and for the year ended December 31,
		2018 (1)		2018		2017		2016		2015		2014
		(US$ millions)		(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income		3,537		2,457,161		2,522,978		2,541,567		2,399,029		2,049,065
Operating costs (2)		(2,571	)	(1,786,546	)	(1,944,348	)	(1,973,778	)	(1,873,540	)	(1,666,315	)
Operating income		965		670,605		578,631		567,789		525,489		382,750
Financial results (3)		(160	)	(110,875	)	(22,415	)	(20,483	)	(97,869	)	(67,045	)
Other non-operating income		5		3,410		113,241		121,490		20,056		70,893
Share of profit (loss) of associates and joint ventures accounted for using the equity method		5		3,190		(2,697	)	7,878		8,905		(54,353	)
Income before income taxes		815		566,330		666,760		676,674		456,581		332,245
Income tax expenses		(221	)	(153,483	)	(143,342	)	(111,403	)	(109,613	)	(132,687	)
Net income		594		412,848		523,418		565,271		346,968		199,558
Net income attributable to the parent Company		521		361,710		349,383		384,160		251,838		162,459
Net income attributable to non-controlling interests		74		51,138		174,035		181,111		95,130		37,099
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)		0.01		5.66		7.12		7.83		5.13		3.31
Total basic and diluted earnings per average number of ADSs (Ch$/US$ per ADS)		0.41		282.97		355.84		391.26		256.49		165.46
Cash dividends per share (Ch$/US$ per share)(4)		0.004		3.00		3.23		2.09		—		—
Cash dividends per ADS (Ch$/US$ per ADS)(4)		0.22		149.89		161.72		104.65		—		—
Weighted average number of shares of common stock (millions)		63,913		63,913		49,093		49,093		49,093		49,093
Consolidated Statement of Financial Position Data
Total assets		10,778		7,488,020		5,694,773		5,398,711		5,325,469		5,126,735
Non-current liabilities		3,737		2,596,392		1,090,995		1,178,471		1,270,006		1,122,585
Equity attributable to the parent company		4,924		3,421,229		2,983,384		2,763,391		2,592,682		2,472,201
Equity attributable to non-controlling interests		364		252,935		803,578		699,602		609,219		611,864
Total equity		5,288		3,674,164		3,786,962		3,462,994		3,201,901		3,084,066
Capital stock		5,692		3,954,491		2,229,109		2,229,109		2,229,109		2,229,109
Other Consolidated Financial Data
Capital expenditures (CAPEX) (5)		433		300,539		266,030		222,386		309,503		196,932
Depreciation, amortization and impairment losses (6)		318		220,750		160,622		197,587		150,147		141,623

 

(1)                  Solely for the convenience of the reader, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 694.77 per U.S. dollar, as of December 31, 2018.

(2)                  Operating costs represent raw materials and supplies used, other work performed by the entity, employee benefits expenses, depreciation and amortization expenses, impairment losses recognized in the period’s profit or loss and other expenses.

 

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(3)                  Financial results represent (+) financial income, (-) financial costs, (+/-) foreign currency exchange differences and net gains/losses from indexed assets and liabilities.

(4)                  For 2016, a payout ratio of 50% was used based on annual consolidated net income for our 2016 annual consolidated net income filed with the CMF, based on 10 months of results starting as of our incorporation on March 1, 2016, and therefore differs from the twelve-month net income included in this Report.

(5)                  CAPEX figures represent cash flows used for purchases of property, plant and equipment and intangible assets for each year.

(6)                  For further detail, please refer to Note 31 of the Notes to our consolidated financial statements.

 

		As of and for the year ended December 31,
		2018		2017		2016		2015		2014
OPERATING DATA OF SUBSIDIARIES
Enel Distribution
Electricity sold (GWh)		16,782		16,438		15,924		15,893		15,690
Number of customers (thousands)		1,925		1,882		1,826		1,781		1,737
Total energy losses (%) (1)		5.0		5.1		5.3		5.3		5.3
Enel Generation
Installed capacity (MW) (2)		6,274		6,351		6,351		6,351		6,351
Generation (GWh) (2)		17,373		17,073		17,564		18,294		18,063

 

(1)                  Energy losses in distribution arise from illegally tapped energy as well as technical losses. They are calculated as the difference between total energy generated and purchased and the energy sold, excluding tolls and energy consumption not billed (GWh), within a given period.  Losses are expressed as a percentage of total energy purchased.

(2)                  The 2015 and 2014 data includes the capacity and generation of GasAtacama, as a result of its consolidation.

 

Exchange Rates

 

Fluctuations in the exchange rate between the Chilean peso and the U.S. dollar will affect the U.S. dollar equivalent of the peso price of our shares of common stock on the Santiago Stock Exchange (Bolsa de Comercio de Santiago) and the Chilean Electronic Stock Exchange (Bolsa Electrónica de Chile).  These exchange rate fluctuations affect the price of our American Depositary Shares (“ADSs”) and the conversion of cash dividends relating to the common shares represented by ADSs from Chilean pesos to U.S. dollars. In addition, to the extent that significant financial liabilities of the Company are denominated in foreign currencies, exchange rate fluctuations may have a significant impact on earnings.

 

In Chile, there are two currency markets, the Formal Exchange Market (Mercado Cambiario Formal) and the Informal Exchange Market (Mercado Cambiario Informal).  The Formal Exchange Market is comprised of banks and other entities authorized by the Central Bank of Chile.  The Informal Exchange Market is comprised of entities that are not expressly authorized to operate in the Formal Exchange Market, such as certain foreign currency exchange houses and travel agencies, among others.  The Central Bank of Chile has the authority to require that certain purchases and sales of foreign currencies be carried out on the Formal Exchange Market.  Both the Formal and Informal Exchange Markets are driven by free market forces.  Current regulations require that the Central Bank of Chile be informed of certain transactions that must be carried out through the Formal Exchange Market.

 

The U.S. dollar Observed Exchange Rate, which is reported by the Central Bank of Chile and published daily on its web page, is the weighted average exchange rate of the previous business day’s transactions in the Formal Exchange Market.  Nevertheless, the Central Bank of Chile may intervene by buying or selling foreign currency on the Formal Exchange Market to attempt to maintain the Observed Exchange Rate within a desired range.

 

The Informal Exchange Market reflects transactions carried out at an informal exchange rate (the “Informal Exchange Rate”). There are no limits imposed on the extent to which the rate of exchange in the Informal Exchange Market can fluctuate above or below the Observed Exchange Rate.  Foreign currency for payments and distributions with respect to the ADSs may be purchased either in the Formal or the Informal Exchange Market, but such payments and distributions must be remitted through the Formal Exchange Market.

 

The Federal Reserve Bank of New York does not report a noon buying rate for Chilean pesos. As of December 31, 2018, the U.S. dollar Observed Exchange Rate was Ch$ 694.77 per US$ 1.00.

 

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As of April 22, 2019, the U.S. dollar Observed Exchange Rate was Ch$ 663.91 per US$ 1.00.

 

Calculation of the appreciation or devaluation of the Chilean peso against the U.S. dollar in any given period is made by determining the percent change between the reciprocals of the Chilean peso equivalent of US$ 1.00 at the end of the preceding period and the end of the period for which the calculation is being made.  For example, to calculate the devaluation of the year-end Chilean peso in 2018, one determines the percentage of change between the reciprocal of Ch$ 694.77, the value of one U.S. dollar as of December 31, 2018, or 0.001439, and the reciprocal of Ch$ 614.75, the value of one U.S. dollar as of December 31, 2017, or 0.001627.  In this example, the percentage change between the two periods is -11.5%, which represents the 2018 year-end devaluation of the Chilean peso against the 2017 year-end U.S. dollar.  A positive percentage change means that the Chilean peso appreciated against the U.S. dollar, while a negative percentage change means that the Chilean peso devaluated against the U.S. dollar.

 

The following table sets forth the period-end rates for U.S. dollars for the years ended December 31, 2014, through December 31, 2018, based on information published by the Central Bank of Chile.

 

		Ch$ per US$(1)
		Period End		Appreciation (Devaluation)
		(in Ch$)		(in %)
Year ended December 31,
2018		694.77		(11.5	)
2017		614.75		8.9
2016		669.47		6.1
2015		710.16		(14.6	)
2014		606.75		(13.5	)

 

Source: Central Bank of Chile.

(1)                  Calculated based on the variation of period-end exchange rates.

 

B.                     Capitalization and Indebtedness.

 

Not applicable.

 

C.                     Reasons for the Offer and Use of Proceeds.

 

Not applicable.

 

D.                     Risk Factors.

 

Chilean economic fluctuations, certain economic interventionist measures by governmental authorities as well as political events or financial or other crises in any region worldwide may affect our results of operations, financial condition and liquidity as well as the value of our securities.

 

All of our operations are located in Chile.  Accordingly, our revenues are affected by the performance of the Chilean economy.  If local, regional or worldwide economic trends adversely affect the Chilean economy, our financial condition and results from operations could be adversely affected.  Insufficient cash flows could result in the inability to meet our debt obligations and the need to seek waivers to comply with restrictive debt covenants and increasing costs for subsequent financings. The Chilean government has exercised in the past, and continues to exercise, a substantial influence over many aspects of the private sector, which may result in changes to economic or other policies.

 

Future adverse developments in Chile or changes in policies regarding exchange controls, regulations and taxation may impair our ability to execute our business plan, which could adversely affect our results of operations and financial condition.  Inflation, devaluation, social instability and other political, economic or diplomatic developments, could also reduce our profitability.  In addition, Chilean financial and securities markets are influenced by economic and market conditions in other countries and may be affected by events in other countries, which could adversely affect the value of our securities.

 

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Our business depends heavily on hydrological conditions.

 

Approximately 48% of our installed generation capacity in 2018 was hydroelectric.  Accordingly, dry hydrological conditions could adversely affect our business, results of operations and financial condition.  Our results have been adversely affected when hydrological conditions in Chile have been significantly below average.

 

While our subsidiary, Enel Generation, has entered into certain agreements with the Chilean government and local irrigators regarding the use of water for hydroelectric generation purposes during periods of low water levels, if droughts persist we may face increased pressure by the Chilean government or other third parties to further restrict our water use.

 

Our operating expenses increase during these drought periods when thermal plants, which have higher operating costs relative to hydroelectric plants, are dispatched more frequently.  We may need to buy electricity at higher spot prices in order to comply with our contractual supply obligations and the cost of these electricity purchases may exceed our contracted electricity sale prices, thus potentially producing losses from those contracts.  For further information with respect to the effect of hydrology on our business and financial results, please refer to “Item 5. Operating and Financial Review and Prospects — A. Operating Results —1. Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company —a. Generation Business.”

 

Droughts also indirectly affect the operation of our thermal plants, including our facilities that use natural gas, fuel oil or coal, in the following manner:

 

·                           Our thermal plants require water for cooling and droughts in extreme situations may reduce the availability of water and increase the cost of transportation.  As a result, we have had to purchase water for our San Isidro power plant from agricultural areas that are also experiencing water shortages.  These water purchases may increase our operating costs and may require us to negotiate with the local communities.

 

·                           Thermal power plants that burn natural gas generate emissions such as nitrogen oxide (NO), carbon dioxide (CO2) and carbon monoxide (CO) gases.  When operating with diesel they release NO, sulfur dioxide (SO2) and particulate matter into the atmosphere. Coal fired plants generate SO2 and NO emissions. Therefore, greater use of thermal plants during droughts generally increases the risk of producing higher levels of greenhouse gas emissions, which also decreases our operating income due to the payment of so-called “green taxes.”

 

A full recovery from the drought that has been affecting the regions where most of our hydroelectric plants are located may last for an extended period but new drought periods may recur in the future.  A prolonged drought may exacerbate the risks described above and have a further adverse effect upon our business, results of operations and financial condition.

 

The distribution business is also affected by inclement weather. With extreme temperatures, demand can increase significantly within a very short period of time, which in turn affects service and could result in service disruptions that are potentially subject to fines.  Depending on weather conditions, results obtained by our distribution business can vary significantly from year to year.  For example, as a result of severe rainstorms in June 2017, with high wind gusts that brought down part of the electric network, 125,000 of our customers, or 7%, were affected adversely.  In July 2017, a strong snowstorm over the Santiago Metropolitan Region caused massive damage to the electrical infrastructure, and affected 342,000 of our customers, or 18%, and 17% of our feeders. This was the most damaging snowstorm in Santiago since 1970, and left parts of the capital without power for over a week.  These events significantly increased our costs due to emergency responses including payments related to damage compensation, fines, line maintenance and tree trimming programs.

 

Governmental regulations may adversely affect our businesses, cause delays, impede the development of new projects, or increase the costs of operations and capital expenditures.

 

Our businesses and the tariffs that we charge to our customers are subject to extensive regulation and these regulations may adversely affect our profitability. For example, governmental authorities might impose rationing policies during droughts or prolonged failures of power facilities, which may adversely affect our business, results of operations and financial condition. Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies for future projects and obtain construction and operating permits from both local and national regulators. Governmental authorities may withhold the approval of these environmental impact studies and therefore their processing time may be longer than expected.

 

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Governmental authorities may also delay the distribution tariff review process, or tariff adjustments may be insufficient to pass through all of our costs to customers.  Some aspects of the Chilean electricity law date back to 1982, and could very well experience significant regulatory changes. The government has mentioned the potential introduction of electricity distribution tariff reform, and it possible that such new regulation may adversely affect our future profitability. Similarly, electricity regulations issued by governmental authorities may affect the ability of our generation companies to collect revenues sufficient to cover their operating costs.

 

Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments.  Any delay in meeting the standards constitutes a violation of the regulations.  Failure to certify the original implementation and ongoing emission standard requirements of such monitoring system may result in significant penalties and sanctions or legal claims for damages.  We expect that even more restrictive emission limits will be established in the future.  We are also subject to an annual green tax, based on our greenhouse gas emissions in the previous year, and such taxes may increase in the future, and discourage thermal electricity generation.

 

Changes in the regulatory framework are often submitted to the legislators and administrative authorities and, some of these changes could have a material adverse impact on our business, results of operations and financial condition.

 

Regulatory authorities may impose fines on our subsidiaries due to operational failures or any breaches of regulations.

 

Our electricity businesses are subject to regulatory fines for any breach of current regulations, including energy supply failures.  Such fines may be imposed for a maximum of 10,000 Annual Tax Units (“UTA” in its Spanish acronym), or Ch$ 5.8 billion using the UTA as of December 31, 2018. Our electricity generation subsidiaries are supervised by local regulatory authorities and are subject to fines in cases where, in the opinion of the regulatory authority, operational failures affecting the regular energy supply to the system, including coordination issues, are the fault of the generator. Regulations establish a compensation fee to end customers when energy is interrupted more than the standard allowed time due to events or failures affecting transmission facilities. Compensation is a proportion of the energy not supplied with a minimum value between 20,000 UTA (Ch$ 11.6 billion) and the previous year’s energy sales revenues in the case of generators. Fines may also be associated with breach of regulations.

 

In 2015, the CDEC-SING audited GasAtacama’s thermal power plant and reported its findings to the Superintendence of Electricity and Fuels (“SEF”), which in August 2016 fined GasAtacama 10,000 UTA (Ch$ 5.8 billion) for allegedly providing inaccurate information to the CDEC-SING. In 2017, Gener and Engie, both competitors, demanded that Enel Generation pay US$ 65.8 million and US$ 160 million, respectively, as compensation for the alleged additional costs attributed to GasAtacama in the system. These costs were associated with the technical minimum capacity reported by GasAtacama at 310 MW, with a 30-hour minimum operating time that the CEN later estimated to be only 118 MW and a 2-hour minimum operating time. Further compensation claims from other market players may arise in the future and further fines to any of our plants could adversely affect our business, results of operations and financial condition.

 

In 2017, Enel Distribución was fined by the SEF for a total amount of 160,000 UTM (Ch$ 7.7 billion) due to various claims of infractions related to extreme inclement weather in June and July 2017.  During 2017, Enel Distribución was also fined for a total amount of 35,611 UTM (Ch$ 1.7 billion) associated with breaches of quality standards of supply.  For further information on fines, please refer to Note 36.3 of the Notes to our consolidated financial statements.

 

We depend on payments from our subsidiaries to meet our payment obligations.

 

In order to pay our obligations, we rely on cash from dividends, loans, interest payments, capital reductions and other distributions from our subsidiaries.  Such payments and distributions to us are subject to legal constraints such as dividend restrictions and fiduciary obligations.

 

Contractual Constraints.  Distribution restrictions included in certain credit agreements of our subsidiaries may prevent dividends and other distributions to shareholders if they are not in compliance with certain financial ratios.  Our credit agreements typically prohibit any type of distribution if there is an ongoing default.

 

Operating Results of Our Subsidiaries.  The ability of our subsidiaries to pay dividends or make loan payments or other distributions to us is limited by their operating results.  To the extent that the cash requirements of any of our subsidiaries exceed their available cash, the subsidiary will not be able to make cash available to us.

 

Any of the situations described above could adversely affect our business, results of operations and financial condition.

 

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We are involved in litigation proceedings.

 

We are involved in various litigation proceedings, which could result in unfavorable decisions or financial penalties against us.  We will continue to be subject to future litigation proceedings, which could cause material adverse consequences to our business. Our financial condition or results of operations could be adversely affected if we are unsuccessful in defending lawsuits and proceedings against us.  For further information on litigation proceedings, please see “Item 8. Financial Information — A. Consolidated Statements and Other Financial Information — Legal Proceedings” and Note 36.3 of the Notes to our consolidated financial statements.

 

Construction and operation of power plants may encounter significant delays or halt and cost over-runs as well as stakeholder opposition that may damage our reputation and result in impairment of our goodwill with stakeholders.

 

Our power plant projects may be delayed in obtaining regulatory approvals, or may face shortages and increases in the price of equipment, materials or labor, and they may be subject to construction delays, strikes, adverse weather conditions, natural disasters, civil unrest, accidents, and human error.  Any such event could adversely impact our business, results of operations and financial condition.

 

Market conditions at the time when the projects are initially approved may differ significantly from those that prevail when the projects are completed, which in some cases make such projects commercially unfeasible.  This has been the case with many of our former projects, which were initially planned under very different market conditions with higher energy prices prevailing in the market and less competition.  Deviations in these assumptions, including the estimates of the timing and expenditures related to these projects, may lead to cost over-runs and a completion time widely exceeding our initial estimates, which in turn may have a material adverse effect on our business, results of operation and financial condition.

 

The locations where we develop projects are sometimes highly challenging in terms of geographical topography, in some cases in mountain slopes with very limited access. These factors may also lead to delays and cost overruns. For example, Cerro Pabellón, our 48 MW geothermal plant, was built at 4,500 meters above sea level and currently we are constructing a third unit that will increase its capacity by 33MW. We may face challenges associated with high altitude construction, including health concerns, and these may affect the construction schedule and associated investment. Additionally, given the geographic location of some projects, there are archaeological risks. In 2018, 11 charges related to archaeological issues were brought against us in connection with Cerro Pabellón, of which three are considered material. They could lead to fines of up to 5,000 UTM (approximately US$ 241,765), a revocation of the Environmental Qualifications Resolution (“RCA” in its Spanish acronym) and even the shutdown of the plant. The claims result from not having implemented adequate and timely preventive measures associated with archaeological sites discovered in the grounds.

 

The operation of our coal-fired thermal power plants may affect our goodwill with stakeholders, due to greenhouse gas emissions, which could adversely affect the environment and local residents. In addition, communities might have their own interests and different perceptions of the company, influenced by other stakeholders or motivations unrelated to the project. If the company fails to engage with its relevant stakeholders, it may face opposition, which could adversely affect our reputation, stall operations or lead to litigation threats or action. Our reputation is the foundation of our relationship with key stakeholders.  If we are unable to effectively manage real or perceived issues that could impact us negatively, our business, results of operations and financial condition could be adversely affected.

 

Damage to our reputation may exert considerable pressure on regulators, creditors, and other stakeholders and ultimately lead to projects and operations that may be abandoned, causing our share prices to drop and hindering our ability to attract and retain valuable employees, any of which could result in an impairment of our goodwill with stakeholders.

 

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Political events or financial or other crises in any region worldwide can have a significant impact in Chile, and consequently, may adversely affect our operations as well as our liquidity.

 

Chile is vulnerable to external shocks, including financial and political events, which could cause significant economic difficulties and affect growth.   If Chile experiences lower than expected economic growth or a recession, it is likely that our customers will demand less electricity and that some of our customers may experience difficulties paying their electric bills, possibly increasing our uncollectible accounts.  Any of these situations could adversely affect our results of operations and financial condition.

 

Financial and political events in other parts of the world could also adversely affect our business.  For example, since 2018, U.S. and China have been involved in a trade war involving protectionist measures, which increased the volatility of financial markets worldwide due to the uncertainty of political decisions.  Instability in the Middle East or in any other major oil-producing region could also result in higher fuel prices worldwide, increasing the operating cost for our thermal generation plants and adversely affect our results of operations and financial condition.

 

The U.S. federal government has experienced shutdowns in recent times, including the 2018—2019 U.S. government shutdown, which affected the SEC among many other federal agencies, and extended for 35 days, the longest federal government shutdown in U.S. history.  Even temporary or threatened U.S. government shutdowns could have a material adverse effect on the timing, execution and increased expense associated with our international financings and our M&A activities.

 

An international financial crisis and its disruptive effects on the financial industry could adversely impact our ability to obtain new financings on the same historical terms and conditions that we have benefited from to date.  Political events or financial or other crises could also diminish our ability to access the Chilean and international capital markets or increase the interest rates available to us.  Reduced liquidity, in turn, could adversely affect our capital expenditures, our long-term investments and acquisitions, our growth prospects and our dividend payout policy.

 

We may be unable to enter into suitable acquisitions or successfully integrate businesses that we acquire.

 

On an ongoing basis, we review acquisition prospects that may increase our market coverage or supplement our existing businesses, though there can be no assurance that we will be able to identify and consummate suitable acquisition transactions in the future.  The acquisition and integration of independent companies that we do not control is generally a complex, costly and time-consuming process and requires significant efforts and expenditures.  If we consummate an acquisition, it could result in the incurrence of substantial debt and assumption of unknown liabilities, the potential loss of key employees, amortization of expenses related to tangible assets and the diversion of management’s attention from other business concerns.  In addition, integrating acquired businesses may be difficult, expensive, time-consuming and a strain on our resources and our relationships with our employees and customers and ultimately may not be successful or achieve the benefits expected.  Any delays or difficulties encountered in connection with acquisitions and the integration of their businesses could have a material adverse effect on our business, financial condition or results of operations.

 

Our business and profitability could be adversely affected if water rights are denied or if water concessions are granted with limited duration.

 

We own water rights granted by the Chilean Water Authority (Dirección General de Aguas) for the supply of water from rivers and lakes near our production facilities.  Under current law, these water rights are (i) for unlimited duration, (ii) absolute and unconditional property rights and (iii) not subject to further challenge.  Chilean generation companies must pay an annual license fee for unused water rights.  New hydroelectric facilities are required to obtain water rights, the conditions of which may impact design, timing or profitability of a project.

 

In addition, Chilean Congress has discussed amendments to the Water Code since 2014 in order to prioritize the use of water by defining its access as a basic human need that must be guaranteed by the State.  The amendment will establish that water use for human consumption, domestic subsistence and sanitation will always take precedence, in both the granting and limiting the exercise of rights of exploitation.  Restrictions enacted to preserve environmental flows would reduce water availability for generation purposes.

 

Any limitations on our water rights, our need for additional water rights, or our unlimited duration of water concessions could have a material adverse effect on our hydroelectric development projects and our profitability.  As of the date of this Report, no resolutions have been adopted and the uncertainty remains.

 

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Foreign exchange risks may adversely affect our results and the U.S. dollar value of dividends payable to ADS holders.

 

The Chilean peso has been subject to devaluations and appreciations against the U.S. dollar and may be subject to significant fluctuations in the future. Historically, a significant portion of our consolidated indebtedness has been denominated in U.S. dollars.  Although a substantial portion of our operating cash flows is linked to the U.S. dollar (primarily coming from the generation business), we generally have been and will continue to be exposed to fluctuations of the Chilean peso against the U.S. dollar, which is due to time lags and other limitations to pegging our tariffs to the U.S. dollar and the potential difficulty of obtaining loans in the same currency as our operating cash flow.

 

Because of this exposure, the U.S. dollar value of cash generated by our subsidiaries in U.S. dollars can decrease substantially due to peso devaluations against the U.S. dollar. Future volatility in the exchange rate of the currency in which we receive revenues or incur expenditures may adversely affect our business, results of operations and financial condition.

 

Our long-term electricity sale contracts are subject to fluctuations in the market prices of certain commodities, energy and other factors.

 

In our conventional generation business, we have economic exposure to fluctuations in the market prices of certain commodities as a result of the long term electricity sales contracts into which we have entered. We have material obligations as selling parties under long term fixed-price electricity sales contracts. Prices in these contracts are indexed according to different commodities, exchange rates and inflation. Adverse changes to these indices would reduce the rates we charge under our long-term fixed-price electricity sales contracts, which could adversely affect our business, results of operations and financial condition.

 

In our distribution business, we are also exposed to fluctuations in electricity prices.  Since 2016, some customers who had freely chosen to be subject to regulated tariffs have been switching to the unregulated tariff regime instead due to the lower prices.  These customers are tendering their electricity needs, either directly or in association with other customers, because regulated tariffs are currently higher than unregulated prices, given that the former are based on contracts tendered in the past at higher prices.  Lower market prices might reduce the number of customers that choose regulated tariffs, and customers may choose an alternative energy provider, reducing our number of customers, which could adversely affect our business, results of operations and financial condition.

 

Our controlling shareholder may exert influence over us and may have a different strategic view for our development than that of our minority shareholders.

 

Enel, our controlling shareholder, owns 61.9% (excluding treasury stock) of our voting shares. Enel has the power to determine the outcome of substantially all material matters that require a simple majority of shareholders’ votes in accordance with Chilean corporate law, such as the election of the majority of our board members and, subject to contractual and legal restrictions, the adoption of our dividend policy. Enel also exercises significant influence over our business strategy and operations. Its interests, in some cases, may differ from those of our minority shareholders. Certain conflicts of interest affecting Enel in these matters may be resolved in a manner that is different from interests of our company or of our minority shareholders.

 

Our electricity business is subject to risks arising from natural disasters, catastrophic accidents and acts of terrorism that could adversely affect our operations, earnings and cash flow.

 

Our primary facilities include power plants and distribution assets. Our facilities may be damaged by earthquakes, fires and other catastrophic disasters arising from natural or accidental human causes, as well as acts of protest, vandalism, riot, and terrorism.  A catastrophic event could cause prolonged unavailability of our assets, disruptions in our business, significant decreases in revenues due to lower demand or significant additional costs to us not covered by our business interruption insurance.  There may be lags between a major accident or catastrophic event and the final reimbursement from our insurance policies, which typically carry a deductible and are subject to per event policy maximum amounts.

 

We are subject to financing risks, such as those associated with funding our new projects and capital expenditures, and risks related to refinancing our maturing debt; we are also subject to debt covenant compliance, all of which could adversely affect our liquidity.

 

As of December 31, 2018, our consolidated debt totaled Ch$ 2,479,624,032 (including Ch$ 447,317,781 in debt with EFI, a related company).

 

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Some of our debt agreements are subject to (1) financial covenants, (2) affirmative and negative covenants, (3) events of default and (4) mandatory prepayments for contractual breaches, among other provisions.  A significant portion of our financial indebtedness is subject to cross default provisions, which have varying definitions, criteria, materiality thresholds and applicability with respect to subsidiaries that could give rise to such a cross default.  We incurred debt in connection with the 2018 Reorganization.  As a result, we entered into a debt agreement and we issued US$ 1 billion in bonds in the U.S that are subject to cross default provisions.  In addition, since April 2018, we consolidate EGP Chile’s debt and we may incur in additional debt in the future, which may increase our debt leverage and associated financial risk.

 

In the event that we or our subsidiaries breach any of these contractual provisions, our debtholders may demand immediate repayment, and a significant portion of our indebtedness could become due and payable.  We may be unable to refinance our indebtedness or obtain such refinancing on terms acceptable to us.  In the absence of such refinancing, we could be forced to dispose of assets in order to make the payments due on our indebtedness under circumstances that might not be favorable to obtaining the best price for such assets.  Furthermore, we may be unable to sell our assets quickly enough, or at sufficiently high prices, to enable us to make such payments.

 

We may also be unable to raise the necessary funds required to finish our projects under development or under construction.  Market conditions prevailing at the moment we require these funds or other unforeseen project costs can compromise our ability to finance these projects and expenditures.

 

Our inability to finance new projects or capital expenditures or to refinance our existing debt could adversely affect our results of operation and financial condition.

 

We rely on electricity transmission facilities that we do not own or control.  If these facilities do not provide us with an adequate transmission service, we may not be able to deliver the power we sell to our final customers.

 

We depend on transmission facilities owned and operated by other unaffiliated companies to deliver the electricity we sell.  This dependence exposes us to several risks.  If transmission is disrupted, or transmission capacity is inadequate, we may be unable to sell and deliver our electricity, as has been the case of some of our solar and wind power plants located in northern Chile.  If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient.  If restrictive transmission price regulation is imposed, transmission companies upon whom we rely may not have sufficient incentives to invest in expansion of their transmission infrastructure, which could adversely affect our operations and financial results.  The construction of new transmission lines may take longer than in the past, mainly because of social and environmental requirements that are creating uncertainty as to the time of project completion.

 

There have been blackout events in the past due to the failure of transmission lines, which exposed weaknesses in the transmission grid and its need for expansion and technological improvements to increase its reliability.  Additional failures of transmission lines may occur in the future.

 

Any such disruption or failure of transmission facilities could interrupt our business, which could adversely affect our results of operations and financial condition.

 

Our business may experience adverse consequences if we are unable to reach satisfactory collective bargaining agreements with our unionized employees or if we are unable to retain key employees.

 

A large percentage of our employees are members of unions and have collective bargaining agreements that must be renewed on a regular basis.  Our business, financial condition and results of operations could be adversely affected by a failure to reach agreement with any labor union representing such employees or by an agreement with a labor union that contains terms we view as unfavorable.  Chilean law provides legal mechanisms for judicial authorities to impose a collective bargaining agreement if the parties are unable to come to an agreement, which may materially increase our costs beyond what we have budgeted.

 

In addition, we employ many highly-specialized employees, and certain actions such as strikes, walk-outs or work stoppages by these employees, could adversely impact our business, results of operations and financial condition as well as our reputation.

 

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The relative illiquidity and volatility of the Chilean securities markets could adversely affect the price of our common stock and ADS.

 

Chilean securities markets are substantially smaller and less liquid than the major securities markets in the United States or other developed countries.  The low liquidity of the Chilean market may impair the ability of shareholders to sell shares, or holders of ADSs to sell shares of our common stock withdrawn from the ADS program, into the Chilean market in the amount and at the price and time they wish to do so.  Also, the liquidity and the market for our shares or ADSs may be affected by a number of factors including variations in exchange and interest rates, the deterioration and volatility of the markets for similar securities and any changes in our liquidity, financial condition, creditworthiness, results and profitability.

 

The price or the liquidity of our shares or ADSs may be negatively affected by events in Latin American markets or the global economy in general.

 

Lawsuits against us brought outside Chile or complaints against us based on foreign legal concepts may be unsuccessful.

 

All of our operations are located outside of the United States.  All of our directors and officers reside outside of the United States and substantially all of their assets are located outside the United States.  If any investor were to bring a lawsuit against our directors, officers or experts in the United States, it may be difficult for them to effect service of legal process within the United States upon these persons, or to enforce judgments obtained in United States courts based upon the civil liability provisions of the federal securities laws of the United States, against them in United States or Chilean courts.  In addition, there is doubt as to whether an action could be brought successfully in Chile on the basis of liability based solely upon the civil liability provisions of the United States federal securities laws.

 

Interruption or failure of our information technology, control and communications systems or cyberattacks to or cybersecurity breaches of these systems could have a material adverse effect on our business, results of operations and financial condition.

 

We operate in an industry that requires the continued operation of sophisticated information technology, control and communications systems (“IT Systems”) and network infrastructure.  In addition, we use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals. In our generation business, IT Systems are critical in controlling and monitoring our power plants’ operations, maintaining generation and network performance, generating invoices to bill customers, achieving operating efficiencies and meeting our service targets and standards.  Our distribution business increasingly relies on IT Systems to monitor smart grids, billing processes for millions of customers and customer service platforms. The operation of our generation and distribution systems is dependent not only on the physical interconnection of our facilities with the electricity network infrastructure, but also on communications among the various parties connected to the network.  The reliance on IT Systems to manage the information and communication among and between those parties has increased significantly since the deployment of intelligent grids.

 

Our generation and distribution facilities, IT Systems and other infrastructure, as well as the information processed in our IT Systems could be affected by cybersecurity incidents, including those caused by human error. Our industry has begun to see an increase in the volume and sophistication of cyber security incidents from international activist organizations, nation states and individuals, being among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generating and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or exposing us to liability. Our generation and distribution systems are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident in the electric transmission grid, network infrastructure, fuel sources or our third party service providers’ operations could also negatively impact our business.

 

In addition, our business requires the collection and retention of personally identifiable information of our customers, employees and shareholders, who expect that we will adequately protect the privacy of such information. Cybersecurity breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs associated with notifying and protecting the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely affect our results of operations, as well as our reputation with customers, shareholders and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems.

 

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The cybersecurity threat is dynamic and evolves continually and, in the electricity industry, is increasing in sophistication, magnitude and frequency.  There can be no assurance that we can implement adequate preventative measures or accurately assess the likelihood of a cyber-incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and our reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and may result in significant additional costs, including penalties, third party claims, repair costs, additional insurance expense, litigation costs, notification and remediation costs, security costs and compliance costs. While we maintain property and casualty insurance, there can be no assurance that liabilities or losses we may incur, including as a result of cybersecurity litigation, will be covered under such policies or that the amount of insurance will be adequate.

 

Item 4.   Information on the Company

 

A.                                                     History and Development of the Company.

 

We are a publicly held limited liability stock corporation organized on March 1, 2016 under the laws of the Republic of Chile. Since April 2016, we have been registered in Santiago with the CMF under Registration No. 1139.  We are also registered with the SEC under the commission file number 001-37723. Our full name is Enel Chile S.A. and we are also known commercially as “Enel Chile”.

 

Enel beneficially owned 61.9% (excluding treasury stock) of our Company as of December 31, 2018. Our shares are listed and traded on the Chilean Stock Exchanges and our ADSs are listed and traded on the NYSE.

 

Our contact information in Chile is:

 

Contact Person:	Nicolás Billikopf
Street Address:	Santa Rosa 76, Santiago, Código Postal 8330099, Chile
email:	nicolas.billikopf@enel.com
Telephone:	(56-2) 2353-4628
Web site:	www.enelchile.cl

 

The information contained on or linked from our internet website is not included as part of, or incorporated by reference into this Report.  The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, such as our company, at http://www.sec.gov.

 

We are an electric utility company engaged, through our subsidiaries and affiliates, in the generation, transmission and distribution of electricity businesses in Chile.  As of December 31, 2018, we had 7,463 MW of installed capacity and 1.9 million distribution customers.  Our installed capacity is comprised of 48 generation facilities, of which 48% are hydroelectric power plants.  As of December 31, 2018, we had consolidated assets amounting to Ch$ 7,488 billion and operating revenues of Ch$ 2,457 billion.

 

We have been known as Enel Chile since the 2016 Reorganization described further below.  However, we trace our origins to Compañía Chilena de Electricidad Ltda. (“CCE”), which was formed in 1921 as a result of the merger of Chilean Electric Tramway and Light Co., founded in 1889, and Compañía Nacional de Fuerza Eléctrica, with operations dating back to 1919.  Following nationalization of CCE in the 1970s, during the 1980s, the Chilean electric utility sector was reorganized through the Chilean Electricity Law, known as Decree with Force of Law No. 1 of 1982 (“DFL1”).  CCE’s operations were divided into one generation company, a currently unrelated company, and two distribution companies, one with a concession in the Valparaíso Region, and the other, our predecessor company, with a concession in the Santiago Metropolitan Region.  From 1982 to 1987, the Chilean electric utility sector went through a process of re-privatization.  In August 1988, our predecessor company changed its name to Enersis S.A. (“Enersis” and currently known as Enel Américas S.A.) and became the new parent company of Distribuidora Chilectra Metropolitana S.A., later renamed Chilectra S.A (“Chilectra” and currently known as Enel Distribución Chile S.A.). In the 1990s, Enersis diversified into electricity generation through increasing equity stakes in Endesa Chile S.A. (currently known as Enel Generación Chile S.A.).

 

The 2016 Reorganization

 

During 2016, we completed a corporate reorganization to separate Enersis’s Chilean businesses from its non-Chilean businesses (the “2016 Reorganization”).

 

The 2016 Reorganization involved the separation of the respective Chilean and non-Chilean electricity generation, transmission and distribution businesses of Endesa Chile, Chilectra and Enersis by means of a “demerger” under Chilean law and the subsequent

 

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distribution of the shares of the newly created entities to each company’s respective shareholders (collectively, the “Spin-Offs”).  The “demerger” or separation of the businesses occurred on March 1, 2016 and the Spin-Offs were effective in April 2016, with the creation and public listing of the shares of the newly incorporated entities: (i) Enersis Chile S.A., which held the Chilean businesses of Enersis, (ii) Endesa Américas S.A., which held the non-Chilean businesses of Endesa Chile, and (iii) Chilectra Américas S.A., which held the non-Chilean businesses of Chilectra.  The 2016 Reorganization also involved the merger between the companies holding the non-Chilean assets.  The merger became effective on December 1, 2016 and merged Endesa Américas S.A. and Chilectra Américas S.A. with and into Enersis Américas S.A. (currently Enel Américas S.A.), with the latter continuing as the surviving company.

 

As part of this process, we changed our name from Enersis Chile S.A. to Enel Chile S.A. on October 18, 2016.  That same date, (i) Endesa Chile changed its name to Enel Generación Chile S.A.; and (ii) Chilectra changed its name to Enel Distribución Chile S.A.

 

The 2018 Reorganization

 

On August 25, 2017, we proposed a corporate reorganization (the “2018 Reorganization”) to consolidate Enel’s conventional and non-conventional renewable energy businesses in Chile under our company, Enel Chile, Enel’s only vehicle to invest in Chile.  The 2018 Reorganization involved the following transactions:

 

·                  a cash tender offer by Enel Chile of all outstanding shares of common stock (including ADSs) of Enel Generation.  The tender offer was subject to the condition that the tendering holders of Enel Generación shares and ADSs use Ch$236 of the Ch$590 tender offer consideration for each Enel Generation share and Ch$7,080 of the Ch$17,700 tender offer consideration for each Enel Generation ADS to subscribe for shares of our common stock at a subscription price of Ch$82 per Enel Chile share (or Ch$2,460 per Enel Chile ADS);

 

·                  a capital increase to make available a sufficient number of shares of common stock of Enel Chile to deliver to tendering holders of Enel Generation shares and ADSs to satisfy all conditions precedent; and

 

·                  a merger pursuant to which Enel Green Power Latin América S.A. (“EGPL”) merged into Enel Chile.  EGPL was a closely held stock corporation organized under the laws of the Republic of Chile.  Before the 2018 Reorganization, EGPL was a member of the Enel Green Power group of companies.  Enel Green Power is a transnational company dedicated to electricity generation with renewable resources, which in turn is controlled by Enel.  EGPL was a renewable energy generation holding company engaged, through its wholly owned subsidiary Enel Green Power Chile Ltda. (“EGP Chile”), in the electricity generation business in Chile.

 

The different steps of the 2018 Reorganization were approved by the respective shareholders of Enel Chile, Enel Generation and EGPL at their extraordinary shareholders’ meetings held on December 20, 2017.  The tender offer occurred between February 16, 2018 and March 22, 2018, the preemptive rights offering in connection with the capital increase took place between February 15, 2018 and March 16, 2018 and the 2018 Reorganization, in the aggregate, was completed and effective on April 2, 2018.

 

As a result of the consummation of the 2018 Reorganization, we increased our economic interest in Enel Generation from 60% to 93.6% economic interest, we continue to own 99.1% of Enel Distribución and EGP Chile is wholly-owned.  Currently, we consolidate the Chilean conventional and renewable electricity generation business through Enel Generation, the Chilean electricity distribution business through Enel Distribución and the Chilean non-conventional renewable electricity generation business through EGP Chile.  Enel remains as our parent company and our majority shareholder owning 61.9% (excluding treasury stock) of our Company.

 

During the last few years, our business strategy has focused on our core business.  We have increased our shareholdings in subsidiaries related to electricity generation, divested certain non-strategic assets and reduced the number of our companies, simplifying our corporate structure, mainly through mergers.

 

We have conducted the following sales of non-core assets over the past three years:

 

·                           On September 14, 2016, we sold our 20% equity interest in GNL Quintero S.A. (“GNL Quintero”), to Enagás Chile S.p.A.  We obtained this interest in GNL Quintero in 2007, as part of a consortium we formed along with ENAP, Metrogas and British Gas to build the LNG regasification facility in the Quintero Bay.  Partial commercial operations of the facility began in September 2009 and full commercial operations began on January 1, 2011.

 

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·                           On December 16, 2016, we sold our 42.5% equity interest in Electrogas S.A. (“Electrogas”).  Electrogas is a company dedicated to the transportation of natural gas and other fuels, which serves our San Isidro and Quintero power plants, among others.  We received the proceeds of this sale, amounting to US$ 180 million (Ch$ 115 billion at that time), on February 7, 2017.

 

In order to simplify our corporate structure, we have continued to reduce the number of our companies over the last three years:

 

·                           During 2016, Inversiones GasAtacama Holding Ltda. merged into Celta, which later merged into GasAtacama, the surviving company on November 1, 2016.  Celta was our investment vehicle through which we owned the San Isidro thermal plants, the Pangue hydroelectric plant and the Tarapacá thermal generation facility, in addition to our interest in Central Eólica Canela S.A., which owns the Canela wind farms.

 

·                           On November 9, 2017, GasAtacama purchased the 25% minority interest of Central Eólica Canela S.A, which was dissolved on December 22, 2017.  Our economic interest in GasAtacama was 93.7% as of December 31, 2018.

 

EGP Chile

 

EGP Chile currently has 20 operational power plants with a total installed capacity of 1,189 MW consisting of 92 MW of hydroelectric power, 564 MW of wind power, 492 MW of solar power, and 41 MW of geothermal power.

 

In 2015, EGP Chile focused on continued growth as well as maintenance of existing facilities impacted by natural disasters.  In particular, it rebuilt the Diego de Almagro solar power plant after it was damaged by floods, as well as the Talinay Oriente and Talinay Poniente wind plants which were damaged by an 8.4-magnitude earthquake in Northeast Chile.  A volcanic eruption in Southern Chile also affected plant operations.  That year, EGP Chile also began construction on the Cerro Pabellón geothermal plant (the first in South America at 4,500 meters above sea level), the Los Buenos Aires and Renaico wind farms, and the Pampa Norte solar plant.  By the end of 2015, EGP Chile totaled 606 MW of installed capacity and completed construction of the Carrera Pinto solar plant.  In 2016, EGP Chile began operating the La Silla solar plant and began construction on the Sierra Gorda Este wind plant and by the end of that year, it reached its goal of 1 GW of installed capacity in Chile, well before the 2017 target.

 

During 2017, Cerro Pabellón geothermal plant start operation adding 48 MW to the total installed capacity, consolidating us as the Chilean multi-technology leader with a very well diversified portfolio of renewable energy.  EGP Chile has become a leader in Chile’s renewable energy market (in terms of installed capacity) with a mixed portfolio of wind, solar, hydroelectric and geothermal power.

 

Enel X Chile

 

On September 7, 2018, we formed a new wholly-owned subsidiary, Enel X Chile SpA (“Enel X Chile”), to develop, implement and sell products and services that incorporate innovation and cutting-edge technology and are different from the sale of energy or concessioned energy distribution.  Enel X Chile expects to offer turnkey projects for municipalities and other public and governmental entities, industrial or residential customer appliances such as photovoltaic systems, heating ventilation air conditioning, led lighting, projects related to energy efficiency, and the development of public and private electric mobility and charging infrastructure, in all cases including customers outside of our concession area.  As of December 31, 2018, we supported installation of over 40 public charge stations, some of which located outside the Metropolitan Region concession area.  In addition, we are offering smart charging solutions, including household devices or office devices having a load capacity of 2 to 4 times faster than a conventional plug.

 

Capital Investments, Capital Expenditures and Divestitures

 

We coordinate our overall financing strategy, including the terms and conditions of loans and intercompany advances entered into by our subsidiaries, in order to optimize debt and liquidity management. Generally, our operating subsidiaries independently plan capital expenditures financed by internally generated funds or direct financings. One of our goals is to focus on investments that will provide long-term benefits and sustainability initiatives. On the other hand, in the distribution business we will continue investing with the aim to allow the connection of new customers, increase the quality of our service and in new technologies (such as smart meters) to automate our networks. Although we have considered how these investments will be financed as part of our budget process, we have not committed to any particular financing structure, and investments will depend on the prevailing market conditions at the time the cash flows are needed.

 

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Our investment plan is flexible enough to adapt to changing circumstances by giving different priorities to each project in accordance with profitability and strategic fit. Investment priorities are currently focused on the distribution business, related to network reliability, capacity improvement and new technology developments such as smart meters.

 

For the 2019-2021 period, we expect to make capital expenditures of Ch$ 1,355 billion in our subsidiaries, related to investments currently in progress, maintenance of our distribution network and generation plants and in studies required to develop other potential generation and distribution projects. For further detail regarding these projects, please see “Item 4. Information on the Company — D. Property, Plant and Equipment — Projects Under Development”.

 

The table below sets forth the expected capital expenditures for the 2019-2021 period and the capital expenditures incurred in 2018, 2017 and 2016:

 

		Estimated 2019-2021		2018		2017		2016
		(in millions of Ch$)
Capital Expenditure(1)		1,355,018		300,539		266,030		222,386

 

(1)           Capex amounts represent effective payments for each year, except for future projections.

 

While our planned investments go beyond the three years highlighted in this table, we are reporting three years to be aligned with Enel’s three-year industrial plan that was disclosed in November 2018.  For further information, please refer to “Item 4. Information on the Company — D. Property, Plant and Equipment — Project Investments” and “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations”.

 

Capital Expenditures in 2018, 2017 and 2016

 

Our capital expenditures in the last three years were principally related to the optimization of the 350 MW Bocamina II power plant, improvements to the Tarapacá coal-fired power plant, the construction of the 150 MW Los Cóndores power plant and maintenance of our current power plants.  Investments related to the Bocamina II and Tarapacá power plants focused on making improvements to reduce environmental impact.  These improvements were the consequence of environmental injunctions in the case of Bocamina II and new environmental regulations in the case of Tarapacá.  The improvements to Bocamina II were completed in 2018, while those of Tarapacá in 2017.  During 2018, we also concluded investments associated with the 48 MW Cerro Pabellón power plant, the first geothermal plant in South America.

 

In 2018, our investments in the distribution business were focused on connections of new customers, reinforcing feeders mainly to increase our service quality, increasing the capacity of our substations, automatization of our systems through the installation of control remote devices and smart meters for residential customers.

 

In our generation business, material plans in progress include Los Cóndores project, which began construction in 2014 with completion expected during 2020. For further detail of the Los Cóndores project, please see “Item 4. Information on the Company — D. Property, Plant and Equipment. — Projects Under Construction.”

 

In our distribution business, we plan to continue to expand our services, control energy losses and increase our quality of service in order to improve the efficiency of our facilities, profitability of our business and increase our capacity to satisfy our growing number of customers and their increasing demands.

 

A portion of our capital expenditures is reserved for maintenance, and for the assurance of quality and operational standards of our facilities.  Projects in progress will be financed with resources provided by external financing as well as internally generated funds.

 

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B.                                                     Business Overview.

 

We are a publicly held limited liability stock corporation that operates in Chile. Our core business is electricity, both generation and distribution. We conduct our business through Enel Generation and Enel Distribution, and their respective subsidiaries.

 

We also participate in other activities but that are not core businesses and represent less than 1% of our 2018 revenues. We do not report them as separate business segment in this Report nor in our consolidated financial statements.

 

The table below presents our revenues:

 

		Year ended December 31,
Revenues		2018		2017		2016		Change 2018 vs. 2017
		(in millions of Ch$)						(in %)
Generation		1,580,653		1,634,937		1,659,727		(3.3	)
Distribution		1,263,224		1,326,659		1,315,761		(4.8	)
Other businesses and intercompany transaction adjustments		(386,716	)	(438,618	)	(433,921	)	(11.8	)
Total revenues		2,457,161		2,522,978		2,541,567		(2.6	)

 

For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 35 of the Notes to our consolidated financial statements.

 

Electricity Generation Business Segment

 

We, through our subsidiary Enel Generation, in which we hold a 94% economic interest as of the date hereof, are a generation operator in the SEN, representing 34.2% of the electricity market share in 2018.

 

As of December 31, 2018, we accounted for 31.5% of the SEN’s total generation capacity, measured by the installed capacity, according to figures published by the National Electricity Coordinator (“CEN” in its Spanish acronym). Hydroelectric, thermal, solar, wind and geothermal power represent 47.5%, 36.7%, 6.6%, 8.6% and 0.5% of our total installed capacity in Chile, respectively.

 

For additional detail on our historical capacity, see “Item 4. Information on the Company — D. Property, Plant and Equipment.”

 

The following tables summarize the information relating to our capacity, electricity generation and energy sales:

 

ELECTRICITY DATA

 

		Year ended December 31,
		2018		2017		2016
Number of generating units(1) (2)		1,030		111		111
Installed capacity (MW)(3)		7,463		6,351		6,351
Electricity generation (GWh)		20,046		17,073		17,564
Energy sales (GWh)		24,369		23,356		23,689

 

(1)                  For details on generation facilities, see “Item 4. Information on the Company — D. Property, Plant and Equipment — Property, Plant and Equipment of Generation Companies.”

(2)                  The increase in the number of generating units from 2017 to 2018 is the result of including the EGP Chile solar plants, since each inverter element is considered a generating unit.

(3)                  Total installed capacity is defined as the maximum capacity (MW), under specific technical conditions and characteristics. In most cases, installed capacity is confirmed by satisfaction guarantee tests performed by equipment suppliers. Figures may differ from installed capacity declared to governmental authorities and customers, according to criteria defined by such authorities and relevant contracts.

 

Our consolidated electricity generation was 20,046 GWh in 2018 and our sales were 24,369 GWh, which represents a 17% and 4% increase, when compared to 2017, respectively.

 

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Dividing the electricity generation business into hydroelectric, thermoelectric and other generation is customary in the electricity industry, because each generation type has significantly different variable costs. Thermoelectric generation, for instance, requires the purchase of fuel, which generally leads to higher variable costs than hydroelectric generation from reservoirs or rivers that normally has minimal variable costs. Of our total consolidated generation in 2018, 56.8% was from hydroelectric sources, 31.3% was from thermal sources and 11.9% was from solar and wind energy.

 

The following table summarizes our consolidated generation by type of energy:

 

GENERATION BY TYPE OF ENERGY (GWh)

 

		Year ended December 31,
		2018				2017				2016
		Generation		%		Generation		%		Generation		%
Hydroelectric		11,395		56.8		9,652		56.5		9,078		51.7
Thermal		6,268		31.3		7,292		42.7		8,379		47.7
Other generation(1)		2,384		11.9		129		0.8		107		0.6
Total generation		20,046		100		17,073		100		17,564		100

 

(1)                  Other generation refers to the generation from wind and solar energy.

 

The following table contains information regarding our consolidated sales of electricity by type of customer for each of the periods indicated:

 

ELECTRICITY SALES BY CUSTOMER TYPE (GWh)

 

		Year ended December 31,
		2018				2017				2016
		Sales		% of Sales Volume		Sales		% of Sales Volume		Sales		% of Sales Volume
Regulated customers		15,645		64.2		17,029		72.9		18,516		78.2
Unregulated customers		7,549		31.0		5,586		23.9		4,321		18.2
Total contracted sales(1)		23,194		95.2		22,615		96.8		22,838		96.4
Electricity pool market sales		1,174		4.8		742		3.2		852		3.6
Total electricity sales		24,369		100		23,356		100		23,689		100

 

(1)                  Includes sales to distribution companies not backed by contracts.

 

Dividing sales by customer type in terms of regulated and unregulated customer is useful in managing and understanding the business. We sell electricity to regulated customers through distribution companies and to unregulated customers directly. The sales to distribution companies to supply the distributors’ regulated customers, that is, either residential, commercial or others, are classified as regulated sales and are subject to government regulated electricity tariffs. The sales of generation companies to distribution companies to supply the distributors’ unregulated customers are also classified as unregulated sales and are also governed by contracts at a freely negotiated prices and terms. We directly sell to large commercial and industrial customers and other generators are classified as unregulated sales and are generally governed by contracts with freely negotiated prices and terms. Finally, pool market sales are the sales that take place when generation companies are dispatched by the CEN in excess of their contractual obligations and therefore must sell their surplus electricity in the pool market, or when the generators electricity dispatched is less than their contractual commitments with their customers and therefore must purchase the deficit in the pool market. These purchase and sale transactions among electricity companies are normally carried out in the pool market at the spot price, and do not require a contractual agreement.

 

The regulatory framework often requires that electricity distribution companies have contracts to support their commitments to small volume customers. Chilean regulations also determine which customers can purchase energy directly in the electricity pool market.

 

We attempt to minimize the risk of electricity generation deficits resulting from poor hydrological conditions in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year.  We consider the available statistical information concerning rainfall, mountain snow and ice, and when they are expected to melt, hydrological levels, and the capacity of key reservoirs to determine our estimated production for a dry year.  In addition to limiting contracted sales, we may adopt other strategies including installing temporary thermal capacity, negotiating lower consumption levels

 

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with unregulated customers, negotiating with other water users and including pass-through cost clauses in contracts with customers to cover the cost of spot market purchases.

 

In 2022, distribution company contracts awarded in the August 2016 auction will come into effect and therefore the tariffs of our regulated contracts will decrease by 6% as a consequence of the lower prices offered by NCRE providers in the energy auction for distribution companies.  In 2024, contracts awarded in the November 2017 auction will come into effect with an average price of US$ 32.5 per MWh, which is 31% lower than the average price of the previous tender process.  We routinely participate in energy bids and we have been awarded long-term energy sale contracts that incorporate the expected variable costs considering changes to the most relevant variables.  These contracts secure the sale of our current and expected new capacity and allow us to stabilize our income.

 

In November 2017, the outcome of the latest bidding process was announced.  This process tendered 2,200 GWh per year to be delivered between 2024 and 2043. The total amount of energy tendered was based on renewable energy offers, thus representing a milestone in the industry.  We, through Enel Generation, were awarded 54% of the tender, corresponding to 1.2 TWh at an average price of US$ 34.7 per MWh with a mix of wind, solar and geothermal generation, these prices are 6.8% higher than the average price.

 

In terms of expenses, the primary variable costs involved in the electricity generation business, in addition to the direct variable cost of generating hydroelectric or thermal electricity such as fuel costs, are energy purchases and transportation costs. During periods of relatively low hydrology, the amount of our thermal generation increases. This involves an increase in the amount of fuel required and the costs of its transportation to the thermal generation power plants. Under dry conditions, electricity that we have contractually agreed to provide may exceed the amount of electricity that we are able to generate. Therefore, to satisfy our contractual commitments, we may be required to purchase electricity in the pool at spot market prices. The cost of these purchases at spot prices, under certain circumstances, may exceed the price at which we sell electricity under contracts and, therefore, may result in a loss. We attempt to minimize the effect of poor hydrological conditions on our operations in any given year by limiting our contractual sales requirements to a quantity that does not exceed our estimated electricity production in a dry year. We consider the available statistical information concerning rainfall, mountain snow and ice and when they are expected to melt, hydrological levels, and the capacity of key reservoirs to determine our estimated production for a dry year. In addition to limiting contracted sales, we may adopt other strategies including installing temporary thermal capacity, negotiating lower consumption levels with unregulated customers, negotiating with other water users and including pass-through cost clauses in contracts with customers.

 

Seasonality

 

While our core business is subject to weather patterns, generally only extreme events such as prolonged droughts, which may adversely affect our generation capacity, rather than seasonal weather variations, materially affect our operating results and financial condition.

 

The generation business is affected by seasonal changes throughout the year. During normal hydrological years, snowmelts typically occur during the warmer months of October through March. These snowmelts increase the level of water in our reservoirs. The months with most precipitation are typically May through August.

 

When there is more precipitation, hydroelectric generating facilities can accumulate additional water to be used for generation. The increased level of our reservoirs allows us to generate more electricity with hydro power plants during months in which marginal electricity costs are lower.

 

In general, hydrological conditions such as droughts and insufficient rainfall adversely affect our generation capacity. For example, severe prolonged drought conditions or reduced rainfall levels in Chile caused by El Niño phenomenon reduces the amount of water that can be accumulated in reservoirs, thereby curtailing our hydroelectric generation capacity. In order to mitigate hydrological risk, hydroelectric generation may be substituted with thermal generation (natural gas, LNG, coal or diesel) and energy purchases on the spot market, both of which could result in higher costs, in order to meet our obligations under contracts with both regulated and unregulated customers.

 

Operations

 

We own and operate a total of 48 generation power plants in Chile both directly and through our subsidiaries, EGP Chile, GasAtacama and Pehuenche. Of these generation power plants, 18 are hydroelectric, with a total installed capacity of 3,548 MW, representing 48 % of our total installed capacity in Chile. There are 11 thermal generation power plants (including a geothermal power plant) that operate with gas, coal or oil with a total installed capacity of 2,781 MW, representing 37 % of our total installed capacity in

 

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Chile. There are 9 wind powered generation power plants with an aggregate installed capacity of 642 MW, representing 9% of our total installed capacity in Chile. There are 10 solar powered generation power plants with an aggregate installed capacity of 492 MW, representing 7% of our total installed capacity in Chile. On November 21, 2017, the integration of the SIC and the SING into one interconnected system was completed and resulted in the creation of the SEN, a new national interconnected system that extends from Arica in the north of Chile to Chiloé in the south of Chile.

 

For information on the installed generation capacity for each of our subsidiaries, see “Item 4. Information on the Company — D. Property, Plant and Equipment.”

 

Our total gross electricity generation in Chile accounted for 27.8 % of total gross electricity generation in Chile during 2018.

 

The following table sets forth the electricity generation by each of our generation companies:

 

ELECTRICITY GENERATION BY COMPANY (GWh)

 

		Year ended December 31,
		2018		2017		2016
Enel Generation		11,314		10,976		11,538
EGP Chile(1)		2,673		—		—
Pehuenche		2,794		2,443		2,369
GasAtacama		3,265		3,654		3,657
Total		20,046		17,073		17,564

 

(1)                  Includes all of EGP Chile’s subsidiaries

 

The following table sets forth the electricity generation by type:

 

ELECTRICITY GENERATION BY TYPE (GWh)

 

		Year ended December 31,
		2018				2017				2016
		Generation		%		Generation		%		Generation		%
Hydroelectric generation		11,101		55.4		9,392		55.0		8,815		50.2
Thermal generation		6,268		31.3		7,292		42.7		8,379		47.7
Wind generation — NCRE(1)(3)		1,352		6.7		129		0.8		107		0.6
Mini-hydro generation — NCRE(2)		293		1.5		260		1.5		263		1.5
Solar generation — NCRE(2)		872		4.4		—		—		—		—
Geothermal generation — NCRE(2)		159		0.8		—		—		—		—
Total generation		20,046		100		17,073		100		17,564		100

 

(1)                  For 2017, electricity generated by the Canela I and Canela II wind farms.

(2)                  For 2017, electricity generated by the Palmucho and the Ojos de Agua mini-hydroelectric plants.

(3)                  Includes all EGP Chile wind farms.

 

Water Agreements

 

Water agreements refer to the right of a user to utilize water from a particular source, such as a river, stream, pond or groundwater. In times of good hydrological conditions, water agreements are generally not complicated or contentious. However, in times of poor hydrological conditions, water agreements protect our right to use water resources for hydroelectric generation.

 

Through our subsidiaries, we have three agreements in force with the purpose of utilizing water for both irrigation and hydroelectric generation more efficiently.  Two of them are agreements between Enel Generation and the Chilean Water Works Authority (“DOH” in its Spanish acronym) and are related to the water consumption during the most intense irrigation period (normally from September to April) from Laja Lake and Maule Lagoon, both located in southern Chile. Enel Generation signed the first agreement with the DOH related to Laja Lake and Maule Lagoon on October 24, 1958 and September 9, 1947, respectively.

 

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After four years of studies and dialogue with different sectors making use of water from the Laja Lake, on November 16, 2017, the Operation and Recovery of Laja Lake Agreement was signed, which complements the agreement signed with DOH in 1958. This agreement provides reasonable irrigation security to irrigators in the area, giving priority to extractions for irrigation when the reservoir is at low levels, which are also used by generation. It also contemplates the use of a certain volume of water to maintain the scenic beauty of Salto del Laja, a well-known tourist attraction in the area. It also significantly improves the flexibility in the use of water, eliminating most of the restrictions that existed in the form of water extraction, replacing it by annual volumes that will manage irrigation and generation according to their needs. Another agreement was signed in October 2018 between our subsidiary Pehuenche and the irrigators of the Maule Lagoon Monitoring Board to optimize the use of water during drought periods.  These agreements allow us to use the water more efficiently and to avoid further litigation with the local community, especially with farmers.

 

Thermal Generation

 

Our thermal electricity generation facilities use mostly LNG, coal and to a lesser extent, diesel. This mix allows us to use other fuels if the price of LNG were to be relatively too high, if there were to be a shortage of supply, or another circumstance were to make LNG unavailable. To satisfy our natural gas and transportation requirements, we signed a long-term gas supply contract with suppliers that establishes maximum supply amounts and prices, as well as long-term gas transportation agreements with the pipeline companies. Gasoducto GasAndes S.A. and Electrogas S.A. are our current gas transportation providers. Since March 2008, all of our natural gas units can operate using either natural gas or diesel and since December 2009, San Isidro, San Isidro 2 and Quintero power plants operate using LNG.

 

The LNG contract is the largest supply contract and is based on long-term agreements between us and Quintero LNG Terminal for regasification services and British Gas for supply. Our LNG Sale and Purchase Agreement is in force through 2030 and is indexed to the Henry Hub/Brent commodity prices. During 2018, the Quintero LNG Terminal unloaded 44 shipments, with a content equivalent to 3,523 million cubic meters of natural gas, of which 1,096 million cubic meters corresponded to Enel Generation for its generation and commercialization requirements.

 

Regarding the supply of natural gas, a milestone was achieved during the last quarter of 2018. In a new environment of cooperation and promotion of energy integration by governments and private actors in Argentina and Chile, and after eleven years of interrupted supply gas supply, it was possible to reactivate the import of natural gas from Argentina. In this context, Enel Generation signed interruptible supply agreements for natural gas with YPF and Total Austral and the corresponding export permits were obtained in Argentina, allowing the supply of natural gas to begin on December 28, 2018, to be used in the operation of the San Isidro power plant.

 

The agreement of the Nueva Renca thermal power plant that were entered into by AES Gener and subsequently by Empresa Eléctrica Santiago (currently known as Empresa de Mercado Eléctrico S.A.), allowed natural gas to be available to Nueva Renca in 2010. With this availability, the electrical energy produced by Nueva Renca, which was approximately 0.5 TWh, accounted for the electrical energy balance of Enel Generation and helped to reduce our spot energy purchases.

 

From the point of view of gas commercialization, during 2018, Enel Generation had five LNG shipment sales transactions, including the sale to Enel Trade of two LNG shipments with delivery to the United Kingdom, continuing international trading transactions for shipments under the contract with BG Global Energy Ltda. in relevant international markets, outside of Latin America.

 

In addition, Enel Generation, together with ENAP and Agesa, implemented a new agreement for the export of natural gas from the Quintero LNG Terminal to Argentina with Empresa Nacional de Energía Argentina in 2018. Gas shipments totaled 90.6 million cubic meters, of which Enel Generation contributed 55% of the total exported volume.

 

In 2018, the Terminal Use Agreement signed with GNL Mejillones allowed the unloading of an LNG shipment at this terminal. This agreement allowed the renewal of gas purchase agreements with important mining and industrial customers in the north of Chile, making of Enel Generation the main industrial gas trader in the north of Chile, in addition to having volumes of this gas available to Enel Generation thermal units connected to the northern gas pipeline network (Taltal and GasAtacama).

 

In relation to the commercialization of LNG by trucks, 2018 was marked by a 30% increase compared to 2017. During 2018, new agreements were reached that will allow distribute natural gas to two new cities.

 

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With respect to coal-based power plant operations, during 2018, 1,037 kilotons of coal were consumed by Tarapacá and Bocamina power plants. This consumption was equivalent of 2.3 TWh of energy generated by Bocamina 2, 0.6 TWh generated by Bocamina and 0.01 TWh generated by Tarapacá.

 

Generation from NCRE sources

 

Under Chilean law, electricity generation companies must derive a minimum amount of their energy sales from NCRE. This minimum amount depends on the date of execution of the sale contract and ranges from zero, for those signed prior to 2007, to 20% for those signed starting in July 2013. Currently, our Canela wind farms, Ojos de Agua mini-hydroelectric plant, 40% of the installed capacity of our Palmucho mini-hydroelectric plant, as well as most of EGP Chile’s power plants (except Pullinque y Pilamiquén power plants) qualify as NCRE facilities.

 

Electricity sales and generation

 

The SEN’s electricity sales increased 4.3% during 2018 compared to 2017, as set forth in the following table:

 

ELECTRICITY SALES PER SYSTEM (GWh)

 

		Year ended December 31,
		2018(1)		2017		2016
Electricity sales in the SIC		—		—		50,516
Electricity sales in the SING		—		—		16,960
Total electricity sales (SEN)		71,179		68,256		67,476

 

(1)         On November 21, 2017, the SIC and the SING were integrated into one interconnected system and resulted in the creation of SEN.

 

Our electricity sales reached 24,369 GWh in 2018, 23,356 GWh in 2017 and 23,689 GWh in 2016, which represented a 34.2%, 34.2% and 35.1% market share, respectively. The energy purchases to comply with our contractual obligations to third parties decreased by 31% in 2018 when compared to 2017 primarily due to the fact that (i) EGP Chile’s purchases are not included in the total since they are considered as intercompany sales, and (ii) to lower energy available in the contract with Nueva Renca, which is also included in this total.

 

The following table sets forth our electricity generation and purchases:

 

ELECTRICITY GENERATION AND PURCHASES (GWh)

 

		Year ended December 31,
		2018				2017				2016
		(GWh)		% of Volume		(GWh)		% of Volume		(GWh)		% of Volume
Electricity generation		20,046		82.3		17,073		73.1		17,564		74.1
Electricity purchases		4,323		17.7		6,283		26.9		6,125		25.9
Total		24,369		100		23,356		100		23,689		100

 

We supply electricity to the major regulated electricity distribution companies, large unregulated industrial firms (primarily in the mining, pulp and steel sectors) and the pool market. Commercial relationships with our customers are usually governed by contracts. Supply contracts with distribution companies must be auctioned, and are generally standardized with an average term of ten years.

 

Supply contracts with unregulated customers (large industrial customers) are specific to the needs of each customer, and the conditions are agreed between both parties, reflecting competitive market conditions.

 

In 2018, 2017 and 2016, we had 294, 152 and 46 customers, respectively. This significant increase in 2018 is mainly due the increase in the number of unregulated customers. Regulated customers of a certain size may use their option to become

 

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unregulated customers in order to benefit from the current market situation, which offers lower prices than would be paid as regulated customers. In 2018, our customers included 20 regulated customers and 274 unregulated customers.

 

The most significant supply contracts with regulated customers are with our subsidiary Enel Distribution and with Compañía General de Electricidad S.A. (“CGE”), an unaffiliated entity. These are the two largest electricity distribution companies in Chile in terms of sales.

 

Our generation contracts with unregulated customers are generally on a long-term basis and typically range from five to fifteen years. Such contracts are usually automatically extended at the end of the applicable term, unless terminated by either party upon prior notice. Contracts with unregulated customers may also include specifications regarding power sources and equipment, which may be provided at special rates, as well as provisions for technical assistance to the customer. We have not experienced any supply interruptions under our contracts. If we experienced a force majeure event, as defined in the contract, we are allowed to reject purchases and we have no obligation to supply electricity to our unregulated customers. Disputes are typically subject to binding arbitration between the parties, with limited exceptions.

 

For the year ended December 31, 2018, our principal distribution customers were (in alphabetical order): Enel Distribution. Grupo CGE, Grupo Chilquinta and Grupo Saesa.

 

Our principal unregulated customers were (in alphabetical order): Compañia Minera Doña Inés de Collahuasi SCM, Enel Distribution, Empresa CMPC S.A., Minera Valle Central S.A. and SCM Minera Lumina Copper Chile.

 

Electricity generation companies compete largely based on price, technical experience and reliability. In addition, because 48% of our installed capacity connected to the SEN is hydroelectric, we have lower marginal production costs than companies whose installed capacity is primarily thermal. Our installed thermal capacity benefits from access to gas from the Quintero LNG Terminal. However, during periods of extended droughts, we may be forced to buy more expensive electricity from thermal generators at spot prices in order to comply with our contractual obligations.

 

Electricity Distribution Business Segment

 

Through our subsidiary Enel Distribución, in which we have a 99.1% economic interest, we are one of the largest electricity distribution companies in Chile in terms of the number of regulated customers, distribution assets and energy sales.

 

We operate in a concession area of 2,105 square kilometers, under an indefinite concession granted by the Chilean government. We transmit and distribute electricity in 33 municipalities in the Santiago metropolitan region. Our service area is primarily defined as a densely populated area under the Chilean tariff regulations, which govern electricity distribution companies and includes all residential, commercial, industrial, governmental electricity customers, and toll customers. The Santiago metropolitan region, which includes the capital of Chile, is the country’s most densely populated area and has the highest concentration of industries, industrial parks and office facilities in the country. As of December 31, 2018, we distributed electricity to approximately 1.9 million customers. Energy losses were 5.0% in 2018, 5.1% in 2017 and 5.3% in 2016.

 

For the year ended December 31, 2018, residential, commercial, industrial and other customers, who are primarily municipalities, represented 28%, 30%, 13%, and 28%, respectively, of our total energy sales of 16.782 GWh, which is an increase of 2.1% in comparison with the same period in 2017.

 

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The following table sets forth our principal operating data for each of the periods indicated:

 

		Year ended December 31,
		2018		2017		2016
Electricity sales (GWh)		16,782		16,438		15,924
Residential		4,702		4,676		4,442
Commercial		5,107		5,271		5,075
Industrial		2,202		2,451		2,536
Other customers(1)		4,771		4,039		3,871
Number of customers (thousands)		1,925		1,882		1,826
Residential		1,725		1,686		1,634
Commercial		149		146		142
Industrial		13		13		13
Other customers		39		38		37
Energy purchased (GWh)(2)		17,718		17,373		16,803
Total energy losses (%)(3)		5.0		5.1		5.3

 

(1)                  The data for other customers includes tolls.

(2)                  During 2018, 2017, and 2016, Enel Distribution acquired from Enel Generation 37%, 39% and 38%, respectively, of its electricity purchases.

(3)                  Energy losses are calculated as the percent difference between energy purchased and energy sold excluding tolls and energy consumption not billed (GWh) within a given period. Losses in distribution arise from illegally tapped lines as well as technical losses.

 

Enel Distribution’s tariff review process, which set the tariffs for the 2016-2020 period, was finalized in August 2017.  The new tariffs were applied retroactively as of November 2016 and the review did not have a significant effect on Enel Distribution’s tariffs.

 

For the year ended December 31, 2018, the collection rate was 98.6%, compared to 99.6% during the same period in 2017.

 

For the supply to regulated distribution customers, Enel Distribución has entered into contracts with the following generation companies: Enel Generation., AES Gener S.A., Colbún S.A. and others companies.

 

In 2017, the distribution companies of the former SIC jointly submitted a 2,200 GWh/year bid for the period of 2024 through 2043. In November 2017, the following generation companies were awarded the most relevant amounts of the bid companies: Enel Generation, Energía Renovable Verano Tres SpA, Cox Energía SpA, Atacama Energy Holdings S.A. and Atacama Solar S.A.

 

For the supply to unregulated distribution customers, Enel Distribution has contracts with the following generation companies:  Parque Eólico Los Cururos Ltda., Latin América Power, Orazul Energy Duqueco SpA., Enel Generation., Empresa Electrica Puntilla S.A. and KDM.

 

Seasonality

 

The distribution business is directly influenced by seasonal changes in energy demand. Although the price at which a distribution company purchases electricity can change seasonally and has an impact on the price at which it is sold to end users, it does not have an impact on our profitability since the cost of electricity purchased is passed to end users through tariffs that are set for multi-year periods. In general, moderate temperatures reduce the need for electric heating and air conditioning. During 2018, the effects of low temperatures (especially during winter) positively impacted our residential customers’ per capita consumption, which represented 28% of our electricity distribution during 2018.

 

ELECTRICITY INDUSTRY STRUCTURE AND REGULATORY FRAMEWORK

 

1. Overview and Industry Structure

 

In the Chilean Electricity Market, there are four categories of local agents: generators, transmitters, distributors and large customers.

 

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