UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F

☐REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from       to       

OR

☐SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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: (56-9) 9343 5500, nicolas.billikopf@enel.com, Av. Santa Rosa 76, Piso 15, Comuna de Santiago, 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:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
American Depositary Shares Representing Common Stock	ENIC	New York Stock Exchange
Common Stock, no par value *	*	New York Stock Exchange
US$ 1,000,000,000 4.875% Notes due June 12, 2028	ENIC28	New York Stock Exchange

_____________________

*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

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

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

Shares of Common Stock: 69,166,557,220

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  ☒ Yes    ☐ No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐  Yes    ☒  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.   ☒  Yes    ☐  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 during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒  Yes    ☐  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.

Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐         Emerging growth company   ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards † provided pursuant to Section 13(a) of the Exchange Act.  ☐

† 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 whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report    ☒

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

	☒
U.S. GAAP ☐	International Financial Reporting Standards as issued by the International Accounting Standards Board ☒	Other ☐

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.☐  Item 17    ☐  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). ☐ Yes    ☒  No

Enel Chile’s Simplified Organizational Structure (1)

As of the date of this Report

(1) Only principal operating consolidated entities are presented here.

(2) As of December 31, 2019 and the date of this Report, Enel S.p.A. owned 61.9% of Enel Chile. Upon the termination and settlement on May 13, 2020 of a swap transaction entered into by Enel S.p.A. with respect to Enel Chile’s American Depositary Shares, Enel S.p.A.’s beneficial ownership interest in Enel Chile is expected to increase to 62.4%.

1

TABLE OF CONTENTS

		Page
GLOSSARY		3
INTRODUCTION		6
PRESENTATION OF INFORMATION		7
FORWARD-LOOKING STATEMENTS		9
PART I
Item 1.	Identity of Directors, Senior Management and Advisers	10
Item 2.	Offer Statistics and Expected Timetable	10
Item 3.	Key Information	10
Item 4.	Information on the Company	24
Item 4A.	Unresolved Staff Comments	59
Item 5.	Operating and Financial Review and Prospects	59
Item 6.	Directors, Senior Management and Employees	92
Item 7.	Major Shareholders and Related Party Transactions	99
Item 8.	Financial Information	102
Item 9.	The Offer and Listing	104
Item 10.	Additional Information	106
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	122
Item 12.	Description of Securities Other Than Equity Securities	127
PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	129
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	129
Item 15.	Controls and Procedures	129
Item 16.	Reserved	130
Item 16A.	Audit Committee Financial Expert	130
Item 16B.	Code of Ethics	130
Item 16C.	Principal Accountant Fees and Services	131
Item 16D.	Exemptions from the Listing Standards for Audit Committees	132
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	132
Item 16F.	Change in Registrant’s Certifying Accountant	132
Item 16G.	Corporate Governance	133
Item 16H.	Mine Safety Disclosure	133
PART III
Item 17.	Financial Statements	134
Item 18.	Financial Statements	134
Item 19.	Exhibits	134

2

GLOSSARY

AFP	Administradora de Fondos de Pensiones	A legal entity that manages one of the private sector Chilean pension funds in a fully funded capitalization system implemented in 1980.
CDEC	Centro de Despacho Económico de Carga	The autonomous entity in charge of coordinating the efficient operation and dispatch of generation units to satisfy demand in the SIC and SING that was replaced by CEN in November 2017.
Celta	Compañía Eléctrica Tarapacá S.A.	Celta was a former Chilean generation subsidiary of Enel Generation that operated plants in the SING and the SIC. Celta merged into GasAtacama in November 2016.
CEN	Coordinador Eléctrico Nacional	An autonomous entity in charge of coordinating the efficient operation of the SEN, dispatching generation units to satisfy demand and known as the National Electricity Coordinator. It replaced the CDEC for both the SIC and SING in November 2017.
Chilean Stock Exchanges	Chilean Stock Exchanges	The two stock exchanges located in Chile: the Santiago Stock Exchange and the Electronic Stock Exchange.
CMF	Comisión para el Mercado Financiero	Chilean Financial Market Commission, the governmental authority that supervises the financial markets. Formerly known as the Chilean Superintendence of Securities and Insurance, or SVS in its Spanish acronym.
CNE	Comisión Nacional de Energía	Chilean National Energy Commission, governmental entity with responsibilities under the Chilean regulatory framework.
DCV	Depósito Central de Valores S.A.	Chilean Central Securities Depositary.
EGP Chile	Enel Green Power Chile S.A.	The successor by merger to Enel Green Power Chile Ltda., a subsidiary of Enel Chile engaged in non-conventional renewable electricity generation. On March 1, 2020, Enel Green Power Chile Ltda. merged into Enel Green Power del Sur SpA. On April 14, 2020, the name of Enel Green Power del Sur SpA was changed to Enel Green Power Chile S.A.
EGPL	Enel Green Power Latin America S.A.	Formerly a Chilean closely held limited liability stock corporation that held Enel Green Power Chile Ltda. and that merged with us on April 2, 2018. As a result, we consolidate Enel Green Power Chile Ltda.

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Enel	Enel S.p.A.	An Italian energy company with multinational operations in the power and gas markets. A 61.9% beneficial owner of Enel Chile and our ultimate parent company.
Enel Américas	Enel Américas S.A.	An affiliated Chilean publicly held limited liability stock corporation headquartered in Chile, with subsidiaries engaged primarily in the generation, transmission and distribution of electricity in Argentina, Brazil, Colombia, and Peru, and which is controlled by Enel.
Enel Chile	Enel Chile S.A.	Our company, a Chilean publicly held limited liability stock corporation, with subsidiaries engaged primarily in the generation and distribution of electricity in Chile. Registrant of this Report. Formerly known on an interim basis as Enersis Chile S.A.
Enel Distribution	Enel Distribución Chile S.A.	A publicly held limited liability stock corporation and our electricity distribution subsidiary operating in the Santiago Metropolitan Region. Formerly known as Chilectra S.A.
Enel Generation	Enel Generación Chile S.A.	A publicly held limited liability stock corporation and our electricity generation subsidiary in Chile. Formerly known as Empresa Nacional de Electricidad S.A. or Endesa Chile.
Enel X Chile	Enel X Chile SpA	A  Chilean closely held limited liability stock corporation and our wholly owned subsidiary.
GasAtacama	GasAtacama Chile S.A.	Formerly a subsidiary of Enel Generation engaged in gas transportation and electricity generation in northern Chile. On October 1, 2019, GasAtacama merged into Enel Generation.
GasAtacama Holding	Inversiones GasAtacama Holding Ltda.	Formerly a holding company subsidiary of Enel Generation, which previously held GasAtacama. GasAtacama Holding merged into Celta during 2016, which later merged into GasAtacama.
Gener	AES Gener S.A.	A Chilean generation company and one of our competitors in Chile.
GNL Quintero	GNL Quintero S.A.	A company created to develop, build, finance, own and operate a LNG regasification facility at Quintero Bay at which LNG is unloaded, stored and regasified. Enel Generation sold its 20% stake in this company to Enagas Chile S.p.A., an unaffiliated company, in September 2016.
GSM	General Shareholders’ Meeting	General Shareholders’ Meeting.

4

HidroAysén	Centrales Hidroeléctricas de Aysén S.A.	A company created to develop a hydroelectric project in the Aysén region, southern Chile. Enel Generation owned 51% of HidroAysén and Colbún, an unaffiliated company, owned the remaining 49%. The company terminated its activities in 2017.
IFRS	International Financial Reporting Standards	International Financial Reporting Standards as issued by the International Accounting Standards Board (IASB).
LNG	Liquefied Natural Gas.	Liquefied natural gas.
NCRE	Non-Conventional Renewable Energy	Energy sources that are continuously replenished by natural processes, such as wind, biomass, mini-hydro, geothermal, wave, solar or tidal energy.
Pehuenche	Empresa Eléctrica Pehuenche S.A.	A  Chilean publicly held limited liability stock corporation engaged in the electricity generation business, owner of three power stations in the Maule River basin and a subsidiary of Enel Generation.
SEF	Superintendencia de Electricidad y Combustible	Chilean Superintendence of Electricity and Fuels, the governmental authority that supervises the Chilean electricity industry.
SEN	Sistema Eléctrico Nacional	The National Electricity System is the Chilean national interconnected electricity system formed in November 2017 through the integration of the SIC and SING.
SIC	Sistema Interconectado Central	Chilean central interconnected electricity system that was integrated with the SING in November 2017 to form a single interconnected system, the SEN.
SING	Sistema Interconectado del Norte Grande	Chilean interconnected electric system operating in northern Chile that was integrated with the SIC in November 2017 to form a single interconnected system, the SEN.
UF	Unidad de Fomento	Chilean inflation-indexed, Chilean peso-denominated monetary unit, equivalent to Ch$ 28,309.94 as of December 31, 2019.
UTA	Unidad Tributaria Anual	Chilean annual tax unit. One UTA equals 12 Unidades Tributarias Mensuales (“UTM”), a Chilean inflation-indexed monthly tax unit used to define fines, among other purposes. For December 2019, one UTM was equivalent to Ch$ 49,623 and one UTA was equivalent to Ch$ 595,476.
VAD	Valor Agregado de Distribución	Value added from distribution of electricity.

5

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, 2019.

We are a Chilean company engaged in 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 with 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 with 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 to 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) our subsidiary Empresa Nacional de Electricidad S.A. changed its name to “Enel Generación Chile S.A.”; (ii) our subsidiary Chilectra Chile S.A. changed its name to “Enel Distribución Chile S.A.”; and (iii) we changed our name from “Enersis Chile S.A.” to “Enel Chile S.A.”

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% of us and is our ultimate controlling shareholder.

6

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, 2019, one UF was equivalent to Ch$ 28,309.94. The U.S. dollar equivalent of one UF was US$ 37.81 as of December 31, 2019, using the Observed Exchange Rate reported by the Central Bank of Chile (Banco Central de Chile) as of December 31, 2019, of Ch$ 748.74 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 web page, 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 made at the rates applicable as of December 31, 2019.

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 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 is 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.

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, 2019, 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 that are shown in this Report could have been or could be converted into U.S. dollars or Chilean pesos, 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.

7

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.

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 in such companies. In circumstances in which 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. It is possible, due to rounding, that sums shown in tables do not exactly equal the sums of the entries.

8

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 of 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, social unrest, economic fluctuations, public health crises and pandemics, 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 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.

9

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, 2019, and 2018 and for each of the years in the three-year period ended December 31, 2019, are derived from our audited consolidated financial statements included in this Report. The selected consolidated financial data as of December 31, 2017, 2016 and 2015, and for the years ended December 31, 2016, and 2015 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, 2019, has been converted at the U.S. dollar Observed Exchange Rate (dólar observado) for that date of Ch$ 748.74 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.

10

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,
	2019 (1)	2019	2018	2017	2016	2015
	(US$ millions)	(Ch$ millions)
Consolidated Statement of Comprehensive Income Data
Revenues and other operating income	3,701	2,770,834	2,457,161	2,522,978	2,541,567	2,399,029
Operating costs (2)	(2,998)	(2,244,780)	(1,786,557)	(1,944,348)	(1,973,778)	(1,873,540)
Operating income	703	526,055	670,605	578,631	567,789	525,489
Financial results (3)	(202)	(150,893)	(110,875)	(22,415)	(20,483)	(97,869)
Other non-operating income	2.4	1,793	3,410	113,241	121,490	20,056
Share of profit (loss) of associates and joint ventures accounted for using the equity method	0.5	366	3,190	(2,697)	7,878	8,905
Income before income taxes	504	377,321	566,330	666,760	676,674	456,581
Income tax expenses	(82)	(61,228)	(153,483)	(143,342)	(111,403)	(109,613)
Net income	422	316,093	412,848	523,418	565,271	346,968
Net income attributable to the parent Company	396	296,154	361,710	349,383	384,160	251,838
Net income attributable to non-controlling interests	27	19,940	51,138	174,035	181,111	95,130
Total basic and diluted earnings per average number of shares (Ch$/US$ per share)	0.006	4.28	5.66	7.12	7.83	5.13
Total basic and diluted earnings per average number of ADSs (Ch$/US$ per ADS)	0.286	214.09	282.97	355.84	391.26	256.49
Cash dividends per share (Ch$/US$ per share)(4)	0.004	3.14	3.00	3.23	2.09	—
Cash dividends per ADS (Ch$/US$ per ADS)(4)	0.210	156.89	149.89	161.72	104.65	—
Weighted average number of shares of common stock (millions)	69,167	69,167	63,913	49,093	49,093	49,093
Consolidated Statement of Financial Position Data
Total assets	10,495	7,857,988	7,488,020	5,694,773	5,398,711	5,325,469
Non-current liabilities	4,099	3,069,405	2,596,392	1,090,995	1,178,471	1,270,006
Equity attributable to the parent company	4,654	3,484,698	3,421,229	2,983,384	2,763,391	2,592,682
Equity attributable to non-controlling interests	351	262,586	252,935	803,578	699,602	609,219
Total equity	5,005	3,747,284	3,674,164	3,786,962	3,462,994	3,201,901
Capital stock	5,185	3,882,103	3,954,491	2,229,109	2,229,109	2,229,109
Other Consolidated Financial Data
Capital expenditures (CAPEX) (5)	429	321,079	300,539	266,030	222,386	309,503
Depreciation, amortization and impairment losses (6)	704	527,437	220,750	160,622	197,587	150,147

(1)Solely for the convenience of the reader, Chilean peso amounts have been converted into U.S. dollars at the exchange rate of Ch$ 748.74 per U.S. dollar, as of December 31, 2019.

(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.

(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.

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(5)Capital Expenditures (CAPEX) amounts listed in this table 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,
	2019	2018	2017	2016	2015
OPERATING DATA OF SUBSIDIARIES
Enel Distribution
Electricity sold (GWh)	17,107	16,782	16,438	15,924	15,893
Number of customers (thousands)	1,972	1,925	1,882	1,826	1,781
Total energy losses (%) (1)	5	5	5	5	5
Enel Generation
Installed capacity (MW)	6,114	6,274	6,351	6,351	6,351
Generation (GWh)	17,548	17,373	17,073	17,564	18,294
EGP Chile (2)
Installed capacity (MW)	1,189	1,189	—	—	—
Generation (GWh)	3,493	2,673	—	—	—

(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) EGP Chile has been consolidated since April 2018.

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 price in Chilean pesos 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 fluctuations in the exchange rate 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 our significant financial liabilities are denominated in foreign currencies, fluctuations in the exchange rate may have a considerable impact on our 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 consists of banks and other entities authorized by the Central Bank of Chile. The Informal Exchange Market includes entities that are not expressly permitted to operate in the Formal Exchange Market, such as 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 made on the Formal Exchange Market. Free market forces drive both the Formal and Informal Exchange Markets.  Current regulations require that the Central Bank of Chile be informed of transactions that must be effected 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 effected at an informal exchange rate. There are no limits imposed on the extent to which the exchange rate in the Informal Exchange Market can fluctuate above or below the U.S. dollar Observed Exchange Rate. Foreign currency for payments and distributions with respect to the ADSs may be

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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, 2019, the U.S. dollar Observed Exchange Rate was Ch$ 748.74 per US$ 1.00. As of April 27, 2020, the U.S. dollar Observed Exchange Rate was Ch$ 856.76 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 2019, 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 0.0014393, and the reciprocal of Ch$ 748.74, the value of one U.S. dollar as of December 31, 2019, or 0.0013356. In this example, the percentage change between the two periods is -7.2%, which represents the 2019 year-end devaluation of the Chilean peso against the 2018 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, 2015, through December 31, 2019, 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,
2019	748.74	(7.2)
2018	694.77	(11.5)
2017	614.75	8.9
2016	669.47	6.1
2015	710.16	(14.6)

Source: Central Bank of Chile.

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

B.   Capitalization and Indebtedness.

Not applicable.

C.   Reasons for the Offer and Use of Proceeds.

Not applicable.

D.  Risk Factors.

Fluctuations in the Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and worldwide may affect our results of operations, financial condition, liquidity, and the value of our securities.

All our operations are in Chile. Accordingly, our revenues are affected by the performance of the Chilean economy. Chile is also vulnerable to external shocks, such as financial and political events, that could cause significant economic difficulties and affect economic 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. Since 2018, the U.S. and China have been involved in a trade war involving protectionist measures that has 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

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worldwide, increasing the operating cost for our thermal generation plants and unfavorably affecting our results of operations and financial condition.

An international financial crisis and its disruptive effects on the financial industry could negatively affect our ability to obtain new financings under 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 Chilean and international capital markets or increase the interest rates available to us. Reduced liquidity, in turn, could adversely affect our capital expenditures, long-term investments and acquisitions, growth prospects and dividend payout policy. 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, resulting in increased costs for subsequent financings.

Future negative developments in Chile, including political events, financial or other crises, changes to policies regarding foreign exchange controls, regulations, and taxation, may impair our ability to execute our business plan and 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. Chilean financial and securities markets are influenced by economic and market conditions in other countries and may be affected by international events, which could unfavorably affect the value of our securities.

We are exposed to economic and political volatility, including civil unrest in Chile due to the challenges arising from changes in economic conditions, regulatory policies, laws governing foreign trade, manufacturing, development and investments, as well as various crises and uncertainties.  These factors, either individually or in the aggregate, could severely impact Chilean economic growth and our business, results of operations and financial condition. Starting in October 2019, Chile began to experience social turmoil throughout the country, starting initially because of a public transportation fare hike.  Almost immediately, increasingly violent student and civil protests brought about widespread and severe tensions, indiscriminate violence and vandalism, significant public and private sector property damage and disruption to institutions, commerce, general safety, civilian welfare and peace. The government initially declared a 90‑day state of emergency, extendable as necessary.  At the same time, it launched various political, social, and economic reforms, including a guaranteed minimum wage, an increase in government-subsidized pensions, stabilization of electricity costs, a higher tax bracket for high-income earners, new health insurance programs, a pay cut for the members of the Chilean Congress and certain civil servants.

In this context, the Chilean government approved calling for a national referendum, now rescheduled for October 2020, to decide whether to create a new Chilean constitution, and if so, whether a popularly elected assembly or a combination of current legislators and a popularly elected assembly would draft the new constitution. The existing constitution has been in place since 1980 and any new constitution could alter the Chilean political situation, affect the Chilean economy and the country’s business outlook.  A new constitution may also change existing rights, including rights to exploit natural resources, and water and property rights, any of which could adversely affect our business, results of operations, and financial condition.

We are subject to the adverse effects of worldwide pandemics.

An international public health crisis, such as the one attributable to the COVID‑19 pandemic that has become an increasing worldwide source of distress since December 2019, could significantly affect Chile, as well as our trading partners.

In March 2020, due to the COVID‑19 pandemic, Chilean President Sebastián Piñera decreed a state of emergency for 90 days, and such emergency measure may be subsequently extended beyond June 2020. Under such executive authority, President Piñera has instituted nighttime military curfews, selective mandatory quarantines in affected areas, control of entrance, exit and traffic within specified zones, the prohibition of mass gatherings, the closing of public schools, among other measures. The private sector has voluntarily taken further measures, such as adopting telecommuting wherever possible and the closing of commercial offices. Many businesses, such as restaurants and retail stores, have temporarily closed, either voluntarily or by executive decree, and companies associated with travel, transportation, and tourism have been severely affected and many may go bankrupt. 

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The cumulative effect of measures of this kind will likely lead to a recession, high unemployment levels, and perhaps a decline in electricity demand. If the COVID-19 pandemic is not adequately contained in 2020, the ability of our businesses to generate income and maintain liquidity levels to allow for normal operations may diminish. We may also experience increased difficulties in receiving payments from our distribution customers, especially those residential customers accustomed to making their monthly electricity bill payments in our commercial offices, some of which have closed. These customers may not have easy access to payment online or may have greater difficulties in settling their electricity bills. We are not presently able to quantify the expected negative effects of the COVID‑19 pandemic on our 2020 results; however, we expect them to be adverse, especially in the distribution business.

Our businesses depend heavily on hydrology and are affected by droughts, flooding, storms, ocean currents, and other inclement weather conditions.

Approximately 49% of our installed generation capacity in 2019 was hydroelectric. Accordingly, arid hydrological conditions could negatively 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.

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. However, if droughts persist, we may face increased pressure from the Chilean government or other third parties to further restrict our water use.

Our operating expenses increase during these drought periods when thermal power plants, which have higher operating costs relative to hydroelectric power plants, are dispatched more frequently. We may need to buy electricity at higher spot prices in order to comply with our contractual supply obligations. 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 power plants, including our facilities that use natural gas, fuel oil, or coal, in the following manner:

· Our thermal power 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 generate emissions such as nitrogen oxide (NO), carbon dioxide (CO2), carbon monoxide (CO), sulfur dioxide (SO2), and particulate matter into the atmosphere. Therefore, greater use of thermal power 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 power plants are located may last for an extended period, and new drought periods may recur in the future. Prolonged droughts may exacerbate the risks described above and have a further negative effect upon our business, results of operations, and financial condition.

Our distribution business is also affected by inclement weather. Extreme temperatures can increase demand significantly within a very short period, which may put a strain in our service and could result in service disruptions that would be 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 left without electricity. In July 2017, a strong snowstorm over the Santiago Metropolitan Region caused massive damage to the electrical infrastructure, and a blackout affected 342,000 of our customers, or 18%, and 17% of our feeders. This was the most damaging

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snowstorm in Santiago since 1970 and left parts of the capital without electricity for more than 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.

We are subject to physical, operational, and financial risks related to climate change effects, and potential business risks resulting from climate change legislation and regulation to limit greenhouse gas (GHG) emissions.

The electricity generated by our solar and wind generation facilities is highly dependent on suitable solar and wind conditions, which, even under normal operating circumstances, can be very variable. Climate change may also have long-term effects on wind patterns and the amount of solar energy received at a particular solar facility, reducing the output of electricity generated by the facilities. Although we base our business decisions for each renewable energy facility on solar and wind studies, actual conditions may not conform to the findings of these studies. They may be affected by changes in weather patterns, including the potential impact of climate change. Also, severe weather may damage critical components of our renewable power generation systems, including turbines, solar panels, and inverters.

If our renewable energy production falls below anticipated levels, we may have to dispatch our back-up thermal power plants to make up the shortfall in electricity generation. Our thermal power plants have higher operating costs and generate GHG emissions. Also, we may need to buy electricity in the spot market to fulfill the contractual supply obligations of our solar and wind generation facilities, which may be at prices higher than the contracted electricity sale prices. These impacts could increase our costs or result in losses and have a material adverse effect on our business, results of operations, and financial condition.

Future climate change legislation and regulation restricting or regulating GHG emissions could result in increased operating costs and have a material adverse effect on our business, results of operations, and financial condition. The adoption and implementation of any international treaty or any legislation or regulations imposing new or additional reporting obligations on, or limiting emissions of, GHGs from our operations could require us to incur additional costs to comply with such requirements and possibly require the reduction or limitation of GHG emissions associated with our operations. These higher compliance standards may involve additional costs to operate and maintain our equipment and facilities, install emission controls, or pay taxes and fees relating to GHG emissions, which could have a material adverse effect on our business, results of operations and financial condition.

Governmental regulations may unfavorably 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 that may negatively 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.

Some aspects of the Chilean electricity law have been subject to significant regulatory changes, and any such changes may unfavorably affect our future operations and profitability. For example, in the context of the social crisis that began in October 2019, the government established a transitional mechanism for stabilizing electricity prices for customers under the regulated price system. The mechanism eliminates the price increase of 9.2% that would have been applied to regulated customers as of July 2019 and defers the price increase for the sale of electricity under contracts between generation and distribution companies that start before 2021. A price stabilization funding program was implemented by the CNE and is effectively financed by companies in the generation industry, including our subsidiary Enel Generation, through accounts receivable that are generated by the differences between the contractual rates and the stabilized rates, which are expected to enable the generation companies to recover the lost revenues by December 31, 2027. We expect to suffer a financial loss as a result of this revenue deferral because generation companies are being asked to finance such deferral. For further information, please see Note 11 of the Notes to our consolidated financial statements. Other Chilean electricity sector regulations may also affect the ability of our generation companies to collect revenues sufficient to cover their operating costs and adversely affect our future profitability.

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With respect to distribution companies, in December 2019, the Ministry of Energy’s Law No. 21,194 lowers the profitability of distribution companies and modifies the electricity distribution tariff process. Among other things, the new law reduced the rate for calculating annual investment costs from 10% to a rate calculated by the CNE every four years (which will be an annual after-tax rate of between 6% and 8%) and established that the after-tax rate of return for each distribution company must be between three percentage points below and two percentage points above the rate calculated by the CNE. The Chilean Congress is currently discussing an electricity distribution tariff reform (“ley larga”), which, if approved, may reduce our future profitability. It is possible that social and political pressures prevailing recently may influence regulators in deferring favorable tariff adjustments for 2020 which would otherwise accrue.

Our operating subsidiaries are also subject to environmental regulations that, among other things, require us to perform environmental impact studies on future projects and obtain construction and operating permits from local and national regulators. Governmental authorities may withhold or delay the approval of these permits until the completion of environmental impact studies. Therefore, their processing time may be longer than expected. Environmental regulations for existing and future generation capacity have become stricter and require increased capital investments. Any delay in meeting the required emission standards may constitute a violation of the environmental regulations. Failure to certify the original implementation and ongoing emission standard requirements of such monitoring systems may result in significant penalties and sanctions or legal claims for damages. We expect that 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. Such taxes may increase in the future and discourage thermal electricity generation.

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

Our business faces risks from the promotion of decarbonization efforts both on a global and on a national scale.

In June 2019, the Chilean government announced its plan to phase out coal entirely from its energy mix by 2040 and achieve carbon neutrality by 2050. Under this plan, Enel Generation and GasAtacama Chile S.A (“GasAtacama,” now merged into Enel Generation) signed an agreement with the Chilean Ministry of Energy. The protocol defines the process for the progressive closure of our coal-fired power plants Tarapacá (158 MW), Bocamina I (128 MW), and Bocamina II (350 MW). Under this agreement, Enel Generation is irrevocably obligated to close Bocamina I and II, and Tarapacá’s coal plant. The Tarapacá coal plant was closed in December 2019. The deadlines for closing Bocamina I and II are December 31, 2023, and December 31, 2040, respectively.

Even though the Chilean government’s plan to achieve decarbonization may overlap with our companies’ sustainability strategy, the actual implementation of the governmental targets may exert considerable pressure on us and on our ability to satisfy our contractual obligations with other cleaner sources. In turn, this may increase our expenses, decrease our profitability, and limit our ability to satisfy electricity demand fully.

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 failures to supply energy. Our generation subsidiaries are supervised by local regulatory entities and may be subject to fines in cases where the regulator determines that the company is responsible for the operational failures that affect the regular energy supply to the system, including coordination issues. 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.

In 2017, Enel Distribution was fined by the SEF for a total amount of 90,000 UTM (Ch$ 4.5 billion) due to various claims of infractions related to extreme inclement weather in June and July 2017. During 2017, Enel Distribution was also fined for a total amount of 35,611 UTM (Ch$ 1.8 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.

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We depend on distributions 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 may be 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 do not comply with specified 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.

We are involved in litigation proceedings.

We are involved in various litigation proceedings that 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 unfavorably affected if we are unsuccessful in defending lawsuits and proceedings against us. For further information on litigation proceedings, please see “Note 36.3 of the Notes to our consolidated financial statements.

Construction and operation of power plants may encounter significant delays, stoppages, cost overruns, and 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. They may be subject to construction delays, strikes, accidents, and human error. Any such event could negatively affect our business, results of operations, and financial condition.

Market conditions may change significantly between the approval and completion of a project, which, in some cases, may decrease a project’s profitability or render it impracticable. This has been the case with many of our past projects that were initially planned under very different market conditions when energy prices were higher, and there was less competition. Deviations in market conditions, such as estimates of timing and expenditures, may lead to cost overruns and delays in project completion that widely exceed our initial forecasts. In turn, this may have a material adverse effect on our business, results of operation, and financial condition.

We may develop new projects in locations that are sometimes challenging in terms of geographical topography, in some cases on mountain slopes with limited access. These factors may also lead to delays and cost overruns. For example, Cerro Pabellón, our 48 MW geothermal power plant, was built at 4,500 meters above sea level and is currently constructing a third unit that will increase its capacity by 33 MW. We may face challenges associated with high-altitude construction, such as health concerns, and these may affect the schedule and associated investments. Additionally, given the location of some projects, there may be archaeological risks. In 2018, the Superintendence of the Environment filed charges against our subsidiary Geotérmica del Norte S.A. for infractions related to the archaeological and operational components of the Cerro Pabellón project. These charges could result in high fines and the revocation of our environmental permit.

The operation of our thermal power plants, especially those that are coal fired, may affect our goodwill with stakeholders due to greenhouse gas emissions that could unfavorably affect the environment and nearby residents. Furthermore, outside stakeholders may influence the interests and perceptions communities have of our company. If we fail to address all relevant stakeholders appropriately, we may face opposition, which could negatively affect our reputation, stall operations, or lead to litigation threats or actions. Our reputation is the foundation of our relationship

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with key stakeholders and other constituencies. If we do not effectively manage these sensitive issues, 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, possibly leading to the abandonment of projects and operations. This could cause our share prices to drop and hinder our ability to attract and retain valuable employees. Any of these outcomes could result in an impairment of our goodwill with stakeholders.

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

Chile is vulnerable to external shocks that could cause significant economic difficulties and affect growth. If Chile experiences lower than expected economic growth or a recession, it is likely that consumer demand for electricity will decrease and that some of our customers may have 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 negatively affect our business. For example, since 2018, the U.S. and China have been involved in a trade war involving protectionist measures that increased volatility in financial markets worldwide due to the uncertainty of political decisions. In addition, instability in the Middle East or any other major oil-producing region could result in higher fuel prices worldwide, which would increase the operating costs for our thermal generation power plants and unfavorably affect our results of operations and financial condition. An international financial crisis and its disruptive effects on the financial industry could adversely affect our ability to obtain new bank financings under 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 capital markets in Chile and international capital markets as sources of liquidity or increase interest rates available to us. Reduced liquidity could negatively affect our capital expenditures, long-term investments and acquisitions, growth prospects, and dividend payout policy.

The U.S. federal government has experienced shutdowns in recent years. The 2018-2019 U.S. government shutdown, the longest in U.S. history, lasted 35 days and affected many federal agencies, including the SEC. 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 financing and M&A activities.

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 provide synergies with our existing businesses, though there can be no assurance that we will be able to identify and acquire suitable companies in the future. The acquisition and integration of independent companies that we do not control is generally a complex, costly, and time-consuming process that requires significant efforts and expenditures. If we do make further acquisitions, we could incur substantial debt, assume unknown liabilities, potentially lose critical employees, be forced to amortize expenses related to tangible assets, and divert management’s attention from other business concerns.

Integrating acquired businesses may be difficult, expensive, time-consuming, and a strain on our resources and relationships with our employees and customers. Ultimately, these acquisitions may not be successful or achieve the expected benefits. Any delays or difficulties encountered in connection with acquisitions and the integration of their operations could have a material adverse effect on our business, results of operations, or financial condition.

Our business and profitability could be unfavorably 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. Currently, 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

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pay an annual license fee for unused water rights. New hydroelectric facilities are required to obtain water rights and the conditions of such water rights may affect the design, timing, or profitability of a project.

The Chilean Congress has discussed proposed amendments to the Water Code since 2014 to prioritize the use of water by defining its access as a basic human need that must be guaranteed by the state. The amendments would give precedence to water use for human consumption, domestic subsistence, and sanitation in both the granting and limiting of the exercise of rights of exploitation. Restrictions enacted to preserve environmental flows would also reduce water availability for generation purposes. To date, no resolutions regarding these amendments have been approved by the Chilean Congress.

Any limitations on our water rights, the granting of additional water rights, or on the duration of our water concessions could have a material adverse effect on our hydroelectric development projects and profitability.

Foreign exchange risks may unfavorably 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. For example, the Chilean peso depreciated by 7.2% against the U.S. dollar in 2019. The Chilean peso continues to devalue against the U.S. dollar in 2020 and the U.S. dollar Observed Exchange Rate peaked at Ch$ 867.83 per US$ 1.00 on March 19, 2020. We pay our dividends in Chilean pesos. Historically, a significant portion of our consolidated indebtedness has been in U.S. dollars. Although a substantial portion of our operating cash flows is linked to the U.S. dollar, we are exposed to fluctuations in the Chilean peso against the U.S. dollar because of time lags and other limitations to pegging our tariff rates to the U.S. dollar. This exposure can substantially decrease the value of the cash we generate in U.S. dollars due to the devaluation of the peso. 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 sales contracts are subject to fluctuations in the market prices of certain commodities, energy, and other factors.

In our generation business, we have exposure to fluctuations in the market prices of certain commodities that affect our long-term electricity sales contracts. These contracts commit us to material obligations as selling parties and contain prices that are indexed to different commodities, exchange rates, inflation, and the market price of electricity. Unfavorable changes to these indices would reduce the rates we charge under these contracts, which could adversely affect our business, results of operations, and financial condition.

We are subject to incremental risks in distribution markets that are becoming more liberalized.

In our distribution business, we are also exposed to fluctuations in electricity prices. Since 2016, some customers who had freely chosen regulated tariffs have been switching to the unregulated tariff regime due to 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 tariffs due to the former being based on contracts tendered in the past at higher prices. Lower market prices may reduce the number of customers who choose regulated tariffs as customers may choose an alternative energy provider. This would reduce our number of customers and 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 from that of our minority shareholders.

Enel, our ultimate controlling shareholder, owns 61.9% of our voting shares as of the date of this Report and has announced its intention to acquire an additional 3% by the end of 2020, which includes an additional 0.45% expected to be acquired in May 2020. Under Chilean corporate law, Enel has the power to determine the outcome of substantially all material matters that require a simple majority of shareholders’ votes,  such as the election of the majority of the seats on our board, and, subject to contractual and legal restrictions, the adoption of our dividend policy. Enel also exercises

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significant influence over our business strategy and operations. However, in some cases, its interests 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 the interests of our company or our minority shareholders.

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

Our primary facilities include power plants, and distribution assets that are exposed to damage from catastrophic natural disasters, such as earthquakes and fires, human causes, as well as acts of vandalism, protests, riots, 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 significant 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.

In mid-October 2019, widespread street demonstrations and protests erupted in Santiago and quickly spread throughout the rest of Chile. These actions have since become commonplace, and, at times, have been accompanied by looting, arson, and severe vandalism. Violent confrontations between protesters and the police and armed forces have resulted in a significant loss of human lives and severe injuries. The accumulated damage to public and private property could amount to billions of dollars. Damage to Chile’s economy, prospects for growth, perception of risk, and immediate repercussions in terms of unemployment and loss of productivity are also significant. Our corporate headquarters in Santiago suffered a severe arson attack on October 18, 2019, resulting in the dislocation of our management and headquarters employees for an extended period. An electricity substation belonging to an unrelated company in the northern city of Copiapó was set on fire on November 28, 2019. Chilean public authorities have voiced their concern for the country’s strategic electricity infrastructure, including power stations, transmission lines and distribution substations. It is not possible to estimate when such violence will come to an end or the final effects on our business, but there may be material long-term negative effects resulting from this social crisis.

Any natural or human catastrophic disruption to our electricity assets in Chile could lead to significant adverse effects on our operations and financial condition.

We are subject to financing risks, such as those associated with funding our new projects and capital expenditures or refinancing existing obligations.

As of December 31, 2019, our consolidated debt totaled Ch$ 2,661 billion (including Ch$ 781 billion with Enel Finance International N.V., a related company). As of December 31, 2019, our most material debt obligation was the US$ 1.7 billion principal amount of SEC‑registered bonds issued in the U.S. under the law of the State of New York.

Our debt agreements are subject to several of the following provisions including (1) financial covenants, (2) affirmative and negative covenants, (3) events of default, (4) mandatory prepayments for contractual breaches, (5) change of control clauses for material mergers and divestments, and (6) bankruptcy and insolvency proceeding covenants, among others.

A significant portion of our financial indebtedness is subject to cross default provisions, which have varying definitions, criteria, materiality thresholds, and applicability concerning subsidiaries that could result in cross default. Our debt may also become immediately due and payable in cases involving bankruptcy or insolvency proceedings of a significant or material subsidiary. Likewise, some of our debtholders may decide to accelerate our debt in events of cross default dealing with significant or material subsidiaries, among other potential covenant defaults.

We may be unable to refinance our debt or obtain such refinancing on terms acceptable to us. In the absence of such refinancing, we could be forced to liquidate assets at unfavorable prices in order to make payments due on our debt. Furthermore, we may be unable to sell our assets at opportune moments or sufficiently high prices to obtain proceeds that would enable us to make such payments.

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

Our inability to finance new projects or capital expenditures, refinance our existing debt, or comply with our covenants could negatively affect our results of operation and financial condition.

If third party electricity transmission facilities, gas pipeline infrastructure, or fuel supply contracts fail to provide us with adequate service, we may be unable to deliver the electricity we sell to our final customers.

We depend on transmission facilities owned and operated by other companies to deliver the electricity we sell. This dependence exposes us to several risks. If the transmission is disrupted, or transmission capacity is inadequate, we may be unable to sell and deliver our electricity. If a region’s power transmission infrastructure is inadequate, our recovery of sales costs and profits may be insufficient. If restrictive transmission price regulations are imposed, transmission companies we rely on may not have sufficient incentives to invest in expanding their infrastructure, which could unfavorably affect our results of operations and financial condition or affect our ability to deploy our portfolio of projects under development. The construction of new transmission lines may take longer than in the past, mainly because of sustainability, social, and environmental requirements that create uncertainties as to the timing of project completion. In addition, our thermal power plants connected to natural gas pipelines are subject to stoppages should material disruptions in the pipeline occur. Stoppages could force us to purchase electricity at spot market prices, which could be higher than the contracted fixed sale price to customers. This scenario could adversely affect our business, results of operations, and financial condition.

We may be unable to reach satisfactory collective bargaining agreements with our unionized employees or retain key employees in cases of labor conflict.

A large percentage of our employees are members of unions and have collective bargaining agreements that must be renewed regularly. Our business, results of operations, and financial condition could be unfavorably affected by a failure to reach a collective bargaining agreement with any labor union, 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. This is particularly true for some of our subsidiaries, including Enel Distribution, Colina, and Panguipulli, and these agreements may materially increase our costs.

We employ many highly specialized employees, and specific actions such as strikes, walkouts, or work stoppages by these employees could negatively affect our business, results of operations, financial condition, and reputation.

The Chilean legislative branch is currently analyzing proposed bills that could increase our labor costs for the Company, such as a reduction in the workweek from 45 to 40 hours, and an increase of 6% in employer contributions to employee pension funds. If enacted, these measures could lead to reduced productivity and higher expenses.

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

Chilean securities markets are substantially smaller and have less liquidity than major securities markets in the United States and other developed countries. The low liquidity of the Chilean markets 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, on Chilean stock exchanges in the amount and at the desired price and time.

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

All our operations are located outside of the United States. All our directors and officers reside outside of the United States, and substantially all their assets are located outside the United States. If any investor were to bring a lawsuit

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against our directors and officers 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 the U.S. courts based on civil liability provisions of U.S. federal securities laws against them in U.S. or Chilean courts. There is also doubt as to whether an action could be brought successfully in Chile for liability based solely on the civil liability provisions of U.S. federal securities laws.

Interruption in 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. We use our IT Systems and infrastructure to create, collect, use, disclose, store, dispose of, and otherwise process sensitive information, including company and customer data, and personal information regarding customers, employees and their dependents, contractors, shareholders, and other individuals. In our generation business, IT Systems are critical to 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, transmission, 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 information and communication among and between those parties has increased significantly since the deployment of smart meters and intelligent grids in Chile.

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 increased volume and sophistication of cybersecurity incidents from international activist organizations, nation states, and individuals, and are among the emerging risks identified in our planning process. Cybersecurity incidents could harm our businesses by limiting our generation, and distribution 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 business 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 unfavorably affect our business.

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. Significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons and could cause us to become subject to significant litigation, losses, liability, fines, or penalties, any of which could materially and adversely affect our results of operations and reputation with customers, shareholders, and regulators, among others. We may also be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems.

The cybersecurity threat is dynamic and evolving and is increasing in sophistication, magnitude, and frequency. We may not be able to implement adequate preventive measures or accurately assess the likelihood of a cybersecurity incident. We are unable to quantify the potential impact of cybersecurity incidents on our business and reputation. These potential cybersecurity incidents and corresponding regulatory action could result in a material decrease in revenues and high additional costs, including penalties, third party claims, repair costs, increased insurance expense, litigation costs, notification and remediation costs, security costs, and compliance costs.

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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.” As of the date of this Report, Enel beneficially owns 61.9% of our shares. Enel has announced its intention to acquire an additional 3% of our shares during 2020, which includes an additional 0.45% expected to be acquired in May 2020. Our shares are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELCHILE,” and our ADSs are listed and traded on the NYSE under the trading symbol “ENIC.”

Our contact information in Chile is:

Contact Person:	Nicolás Billikopf
Street Address:	Av. Santa Rosa 76 piso 15 Comuna de Santiago Santiago, Chile
Email:	nicolas.billikopf@enel.com
Telephone:	(56-9) 9343 5500
Website:	www.enel.cl; www.enelchile.cl

The information contained on or linked from our website is not included as part of, or incorporated by reference into this Report. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, such as our company, at 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, 2019, we had 7,303 MW of net installed capacity and 1.97 million distribution customers.  Our installed capacity is comprised of 48 generation facilities, of which 49% are hydroelectric power plants.  As of December 31, 2019, we had consolidated assets amounting to Ch$ 7,858 billion and operating revenues of Ch$ 2,771 billion.

We have been known as Enel Chile since the completion of the 2016 Reorganization that separated Enersis’s Chilean businesses from its non-Chilean businesses. 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 the 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.).  As of December 31, 2019, Enel Chile owns 99.1% of Enel Distribution and 93.6% of Enel Generation.  

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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 (“NCRE”) 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 for 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 Generation 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 in 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 in the electricity generation business in Chile through its wholly owned subsidiary Enel Green Power Chile Ltda. (“EGP Chile”).

The respective shareholders of Enel Chile, Enel Generation, and EGPL approved the different steps of the 2018 Reorganization 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 was completed and effective on April 2, 2018.

As a result of the 2018 Reorganization, we increased our economic interest in Enel Generation from 60% to 93.6%  and EGP Chile is wholly owned. We continue to own 99.1% of Enel Distribution. Currently, we consolidate our Chilean conventional electricity generation business under Enel Generation, our Chilean electricity distribution business under Enel Distribution and our Chilean NCRE generation business under EGP Chile. Enel remains as our parent company and majority shareholder, owning 61.9% of our Company as of December 31, 2019, and the date of this Report.

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.

Enel Generation

In June 2019, Enel Generation and its subsidiary GasAtacama Chile (now merged with and into Enel Generation),  signed an agreement with the Ministry of Energy that complements our sustainability strategy and strategic plan and defines how to proceed with the progressive closure of our coal-fired power plants Tarapacá, Bocamina I and Bocamina II, which have a gross installed capacity of 158 MW, 128MW and 350 MW, respectively.

The agreement is subject to the condition that the Power Transfer Regulation be fully implemented. The regulation defines the Strategic Reserve State and establishes, among others, the essential conditions that ensure non-discriminatory treatment between generation companies. Under the agreement, we are formally and irrevocably obligated to close Bocamina I and Tarapacá, respectively. The deadline for closing Tarapacá is May 31, 2020; however, we closed the plant in December 2019 upon receiving authorization from the National Energy Commission (“CNE” in its Spanish acronym) to move up the date of the closure of Tarapacá to December 31, 2019. Pursuant to the agreement, the deadline for closing Bocamina I is December 31, 2023 and for Bocamina II is December 31, 2040, but we expect to close the

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Bocamina II plant before the deadline to help meet our decarbonization goals. These steps are subject to the authorization established in the General Law of Electrical Services

We have conducted the following sales of non-core assets over the past few 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 20% 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 Quintero Bay.  Partial commercial operations of the facility began in September 2009 and full commercial operations began on January 1, 2011.

· 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, and 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 several 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  remaining 25% minority interest in 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.

In September 2019, we completed the intercompany sale of our 2.6% stake in GasAtacama to Enel Generation. On October 1, 2019, GasAtacama merged into Enel Generation. This transaction reorganized and simplified the corporate structures of the subsidiaries that comprised the GasAtacama group to generate corporate and operational efficiencies for us.

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, 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.  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 introduce 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.

Our investment plan is flexible enough to adapt to changing circumstances by giving different priorities to each project considering profitability and strategic fit, which includes sustainability considerations. We are currently focused on making investments on behalf of the distribution business related to network reliability, capacity improvement, and new technology developments, such as smart meters, while keeping in mind the environment.

For the 2020-2022 period, we expect to make capital expenditures of Ch$ 1,585 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”.

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The table below sets forth the expected capital expenditures for the 2020-2022 period and the capital expenditures incurred in 2019, 2018, and 2017:

	Estimated 2020-2022	2019	2018	2017
	(in millions of Ch$)
Capital Expenditure (1)	1,585,000	321,079	300,539	266,030

(1) Capital Expenditure amounts listed in this table represent cash flows used for purchases of property, plant and equipment and intangible assets 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 disclosed in December 2019. 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 2019, 2018, and 2017

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. We completed the upgrades to Bocamina II in 2018 and Tarapacá in 2017. We subsequently decided to shut down our coal‑fired Tarapacá plant in December 2019, in anticipation of the deadline for its closure under our decarbonization plan agreed with the Ministry of Energy. 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, automation 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 the Los Cóndores project, which began construction in 2014 with completion expected during 2021. 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 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.

We reserve a portion of our capital expenditures for maintenance and 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.

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 2019 revenues. We do not report them as separate business segment in this Report nor in our consolidated financial statements.

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The table below presents our revenues:

	Year ended December 31,
Revenues	2019	2018	2017	Change 2019 vs. 2018
	(in millions of Ch$)			(in %)
Generation	1,726,612	1,580,653	1,634,937	9.2
Distribution	1,412,872	1,263,224	1,326,659	11.8
Other businesses and intercompany transaction adjustments	(368,649)	(386,716)	(438,618)	(4.7)
Total revenues	2,770,834	2,457,161	2,522,978	12.8

For further financial information related to our revenues, see “Item 5. Operating and Financial Review and Prospects — A. Operating Results” and Note 28 of the Notes to our consolidated financial statements.

Electricity Generation Business Segment

We, through our subsidiary Enel Generation, in which we hold a 93.6% economic interest as of the date of this Report, are a generation operator in the SEN, representing 32.8% of the electricity market share in 2019.

As of December 31, 2019, we accounted for 29.7% 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 48.6%, 35.3%, 6.7%, 8.8% and 0.6% 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,
	2019	2018	2017
Number of generating units(1) (2)	1,029	1,030	111
Installed capacity (MW) (3)	7,303	7,463	6,351
Electricity generation (GWh)	21,041	20,046	17,073
Energy sales (GWh)	23,513	24,369	23,356

(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 21,041 GWh in 2019 and our sales were 23,513 GWh, which represents a 5% increase in electricity generation and a 4% decrease in sales compared to 2018.

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

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2019, 50.3% was from hydroelectric sources, 34.4% was from thermal sources and 15.4% 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,
	2019		2018		2017
	Generation	%	Generation	%	Generation	%
Hydroelectric	10,578	50.3	11,395	56.8	9,652	56.5
Thermal	7,233	34.4	6,268	31.3	7,292	42.7
Other generation(1)	3,230	15.4	2,384	11.9	129	0.8
Total generation	21,041	100.0	20,046	100.0	17,073	100.0

(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 December31,
	2019		2018		2017
	Sales	% of Sales Volume	Sales	% of Sales Volume	Sales	% of Sales  Volume
Regulated customers	12,712	54.1	15,645	64.2	17,029	72.9
Unregulated customers	9,902	42.1	7,549	31.0	5,586	23.9
Total contracted sales(1)	22,614	96.2	23,194	95.2	22,615	96.8
Electricity pool market sales	899	3.8	1,174	4.8	742	3.2
Total electricity sales	23,513	100.0	24,369	100.0	23,356	100.0

(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 their regulated customers, that is, residential, commercial, or others, are classified as regulated sales and subject to government regulated electricity tariffs. The sales of generation companies to distribution companies to supply their unregulated customers are classified as unregulated sales and governed by contracts at freely negotiated prices and terms. We directly sell to large commercial and industrial customers and other generators. The sales to generators are classified as unregulated sales and generally governed by contracts with freely negotiated prices and terms. Finally, pool market sales take place either when generation companies are dispatched by 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, they must purchase the deficit in the pool market. These purchase and sale transactions among electricity generation companies are normally made 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

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production in a dry year. We consider the available statistical information concerning rainfall, mountain snow and ice, 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 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 the El Niño phenomenon reduces the amount of water that can be accumulated in reservoirs, thereby curtailing our hydroelectric

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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 through our subsidiaries, Enel Generation, EGP Chile, and Pehuenche. Of these generation power plants, 18 are hydroelectric, with a total installed capacity of 3,548 MW, representing 49 % 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 2,580 MW, representing 35 % of our total installed capacity in 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 28.1 % of total gross electricity generation in Chile during 2019.

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

ELECTRICITY GENERATION BY COMPANY (GWh)

	Year ended December 31,
	2019	2018	2017
Enel Generation	15,428	11,314	10,976
EGP Chile (1)	3,493	2,673	—
Pehuenche	2,120	2,794	2,443
GasAtacama (2)	—	3,265	3,654
Total	21,041	20,046	17,073

(1)Includes all of EGP Chile’s subsidiaries.

(2)GasAtacama was merged into Enel Generation in October 2019.

The following table sets forth the electricity generation by type:

ELECTRICITY GENERATION BY TYPE (GWh)

	Year ended December 31,
	2019		2018		2017
	Generation	%	Generation	%	Generation	%
Hydroelectric generation	10,523	50.0	11,101	55.4	9,392	55.0
Thermal generation	7,233	34.4	6,268	31.3	7,292	42.7
Wind generation – NCRE(1)	1,845	8.8	1,352	6.7	129	0.8
Mini-hydro generation – NCRE(2)	55	0.3	293	1.5	260	1.5
Solar generation – NCRE (2)	1,190	5.7	872	4.4	—	—
Geothermal generation – NCRE (2)	194	0.9	159	0.8	—	—
Total generation	21,041	100.0	20,046	100.0	17,073	100.0

(1)Electricity generated by the Canela I and Canela II wind farms, and since 2018 all EGP Chile wind farms.

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(2)Electricity generated in 2019 refers to the Ojos de Agua mini-hydroelectric plant.  Before 2019, the information also includes generation by the Palmucho plant.

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 DOH related to Laja Lake and Maule Lagoon on October 24, 1958 and September 9, 1947, respectively.

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 the 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 for generation. It 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 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 relatively too high, if there were a shortage of supply, or if 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, our 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 2019, Enel Generation used 441 million cubic meters of LNG from Quintero LNG Terminal 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 gas supply, it was possible to reactivate the import of natural gas from Argentina. During 2019, Enel Generation imported a total of 667 million cubic meters of natural gas with a very competitive price under supply agreements with YPF and Total Austral, influencing system energy prices during the year.

The agreement of the Nueva Renca thermal power plant that was entered into by AES Gener and subsequently by Empresa Eléctrica Santiago (currently known as Generadora Metropolitana SpA), allowed natural gas to be available to Nueva Renca beginning in 2019. With this availability, the electrical energy produced by Nueva Renca, which was

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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 2019, Enel Generation had three LNG shipment sales transactions, including the sale to Enel Global Trading with delivery to the United Kingdom and Brazil, continuing international trading transactions for shipments under the contract with BG Global Energy Ltda. in relevant international markets, outside of Latin America.

In 2019, 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 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, 2019 was marked by deliveries of a total of 60 million cubic meters which represents a 36 % increase compared to 2018. During 2019, new agreements were reached that will allow the increased supply of natural gas for distribution for the next several years.

With respect to coal-based power plant operations, during 2019, 1.3 million tons of coal were consumed by the Tarapacá and Bocamina power plants. This consumption was equivalent of 2.3 TWh of energy generated by Bocamina II, 0.6 TWh generated by Bocamina I and 0.6 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 and Ojos de Agua mini-hydroelectric plant, as well as most of EGP Chile’s power plants (except the Pullinque and Pilamiquén power plants), qualify as NCRE facilities.

Electricity sales and generation

The SEN’s electricity sales increased 0.7% during 2019 compared to 2018, as set forth in the following table:

ELECTRICITY SALES IN THE SEN (GWh)

	Year ended December 31,
	2019	2018	2017
Total electricity sales (SEN)	71,670	71,179	68,256

Our electricity sales reached 23,513 GWh in 2019, 24,369 GWh in 2018, and 23,356 GWh in 2017, which represented a 32.8%, 34.2%, and 34.2% market share, respectively. The energy purchases to comply with our contractual obligations to third parties decreased by 42.8% in 2019, compared to 2018, primarily due to (i) EGP Chile’s purchases  no longer being included in the total since its acquisition because they are considered intercompany sales, and (ii) lower energy available under the contract with Nueva Renca, which is included in the total.

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The following table sets forth our electricity generation and purchases:

ELECTRICITY GENERATION AND PURCHASES (GWh)

	Year ended December 31,
	2019		2018		2017
	(GWh)	% ofVolume	(GWh)	% of Volume	(GWh)	% of Volume
Electricity generation	21,041	89.5	20,046	82.3	17,073	73.1
Electricity purchases	2,472	10.5	4,323	17.7	6,283	26.9
Total	23,513	100.0	24,369	100.0	23,356	100.0

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 upon by both parties, reflecting competitive market conditions.

In 2019, 2018, and 2017 we had 315, 294, and 152 customers, respectively. This significant increase in 2019 is mainly due the increase in the number of unregulated customers. Regulated customers of a certain size may elect to become unregulated customers in order to benefit from the current market situation, which offers lower prices than would be paid as regulated customers. In 2019 our customers included 20 regulated customers and 302 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 can reject purchases and 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, 2019, 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., 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.

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Electricity Distribution Business Segment

Through our subsidiary Enel Distribution, 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, 2019, we distributed electricity to approximately 1.97 million customers. Energy losses were 5.0% in 2019, 5.0% in 2018, and 5.1% in 2017.

For the year ended December 31, 2019, residential, commercial, industrial, and other customers, who are primarily municipalities, represented 28.6%, 28.6%, 11.4%, and 31.3%, respectively, of our total energy sales of 17,107 GWh, which is an increase of 1.9% in comparison with the same period in 2018.

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

	Year ended December 31,
	2019	2018	2017
Electricity sales (GWh)	17,107	16,782	16,438
Residential	4,897	4,702	4,676
Commercial	4,896	5,107	5,271
Industrial	1,954	2,202	2,451
Other customers (1)	5,360	4,771	4,039
Number of customers (thousands)	1,972	1,925	1,882
Residential	1,768	1,725	1,686
Commercial	152	149	146
Industrial	13	13	13
Other customers (1)	40	39	38
Energy purchased (GWh) (2)	18,115	17,718	17,373
Total energy losses (%) (3)	5	5	5

(1)The data for other customers includes tolls.

(2)During 2019, 2018, and 2017, Enel Distribution acquired from Enel Generation 33%, 37%, and 39% , 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.

The seasonally adjusted collection rate corresponds to the ratio between the amount collected in the last 12 months and the amount of debt invoiced in the same period. In 2019 this ratio was 99.28%, compared to 99.63% during the same period in 2018.

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

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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: Empresa Eléctrica Guacolda S.A., Hidroeléctrica La Higuera S.A., Hidroeléctrica La Confluencia S.A., Pacific Hydro Chile S.A., and Enel Generation.

Seasonality

Seasonal changes in energy demand directly influence the distribution business. 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. However, in the case of regulated customers, an increase in tariffs due to rate adjustments may not happen immediately, which could affect our profitability in the short term. During 2018, the effects of low temperatures (especially during the winter) positively impacted our residential customers’ per capita consumption, which represented 28% of our electricity distribution.

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.

The following chart shows the relationships among the various participants in the Chilean electricity market:

The Chilean electricity sector is physically divided into three main networks: the SEN and two smaller isolated networks (Aysén and Magallanes). The SEN was created after the integration of the SIC and the SING that took place in November 2017 and extends from Arica in the north of Chile to Chiloé in the south of Chile. CEN (Coordinador Eléctrico Nacional), a centralized dispatch center, coordinates the SEN’s operations. Until the interconnection of the SIC and SING in 2017, each system was coordinated by its respective dispatch center, the CDEC-SIC and the CDEC-SING.

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The industry’s three business segments—generation, transmission, and distribution—must operate in an interconnected and coordinated manner to supply electricity to final customers at minimum cost and within the standards of quality and security required by the industry’s rules and regulations.

i)Generators:

Generators supply electricity to end customers using lines and substations that belong to transmission and distribution companies. The generation segment operates competitively and does not require a concession granted by the authorities. Generators may sell their energy to unregulated customers and other generation companies through contracts at freely negotiated prices. They may also sell to distribution companies to supply regulated customers through contracts governed by bids defined by the authorities.

The operation of electricity generation companies is coordinated by CEN, with an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. Any differences between electricity production and generators’ contracted sales are sold in the spot market at a price equal to the hourly marginal cost of the system.

ii)Transmitters:

Transmission companies own lines and substations with a voltage higher than 23 kV flowing from generators’ production points to the centers of consumption or distribution, charging a regulated toll for the use of their installations. The transmission segment is a natural monopoly subject to special industry regulations, including antitrust legislation. Tariffs are regulated, and access must be open and guaranteed under nondiscriminatory conditions.

iii)Distributors:

Distribution companies supply electricity to end customers using electricity infrastructure lower than 23 kV. The distribution segment is a natural monopoly subject to special industry regulations as well, including antitrust legislation. The electricity network is open access, and distribution tariffs are regulated. Distribution companies must provide electricity to the regulated customers within their concession area and at regulated prices. They may sell to unregulated customers through contracts at freely negotiated prices.

Customers are classified as “regulated” or “unregulated” according to their demand. Certain customers have the choice to be either regulated or unregulated, and therefore subject to the respective price regime. Demand requirements to qualify as a regulated or unregulated customer are described below under “—3. Generation Segment — Dispatch, Customers and Pricing”.

2. Electricity Law and Authorities

The goal of the Chilean Electricity Law is to provide incentives to maximize efficiency and to provide a simplified regulatory scheme and tariff-setting process that limits the discretionary role of the government. This goal is achieved by establishing objective criteria for setting prices that offer a competitive rate of return on investment to stimulate private investment while ensuring the availability of electricity in the system to all who request it.

Since its inception, private sector companies have developed the Chilean electricity industry; however, nationalization by the government was conducted between 1970 and 1973. During the 1980s, the sector was reorganized through the Chilean Electricity Law, known as Decreto con Fuerza de Ley DFL 1 (“DFL 1”), allowing for the renewed participation of the private sector.

The industry is currently governed by the electricity law Ley General de Servicios Eléctricos No. 20,018 and its modifications, under the Electricity Law, known as Decreto con Fuerza de Ley DFL 4 (“DFL 4”), the restated DFL 1, published in 2006 by the Ministry of Economy and its respective regulations included in Decreto Supremo D.S. No. 327/1998.

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The Ministry of Energy has been the leading authority in the energy industry since February 1, 2010. It elaborates and coordinates plans, policies and standards for the proper operation of the sector and the development of the industry in Chile.

The National Energy Commission (“CNE” in its Spanish acronym) and the Superintendence of Electricity and Fuel (“SEF”) are also relevant industry authorities. They report to the Ministry of Energy.

The CNE is the entity in charge of approving the annual transmission expansion plans, elaborating the indicative plan for the construction of new electricity generation facilities, and proposing regulated tariffs to the Ministry of Energy for approval. SEF inspects and oversees compliance with the law, rules, regulations and technical norms applicable to the generation, transmission, and distribution of electricity, as well as liquid fuels and gas.

The Energy Sustainability Agency was created in 2018 and replaced the Energy Efficiency Agency that was in charge of promoting energy efficiency.

Additionally, the law provides for a “Panel of Experts,” whose primary responsibility is to acts as a court, issuing enforceable resolutions in disputes related to subjects referred to by DFL 4 and other electricity related laws. This panel is comprised of professional experts, all of whom are elected every six years by the antitrust government agency, Tribunal de la Libre Competencia (“TDLC” in its Spanish acronym).

CEN is an independent entity in charge of coordinating the operation of the electricity system with the following objectives:

· maintain service security;

· guarantee the efficient operation of facilities connected to the system; and

· guarantee open access to all transmission networks.

CEN’s main activities include:

· coordination of electricity market operations;

· authorization of connections;

· ancillary services management, implementation of information systems available for the public; and

· monitor competition and payments, among others.

CEN performs the calculation of market balances (energy injections and withdrawals), determines the transfers among generation companies, and calculates the hourly marginal cost, which is the price at which energy transfers are made in the spot market. CEN does not, however, calculate the rates of generation capacity. The CNE calculates such prices.

Limits on Integration and Concentration

The antitrust legislation established in DFL 211 (modified in 2016 by Law No. 20,945) and the regulations applicable to the electricity industry stated in DFL 4, and Law No. 20,018 have established the criteria to avoid economic concentration and abusive market practices in Chile.

Companies can participate in different market segments (generation, distribution, transmission) to the extent that they are appropriately separated, both from an accounting and corporate perspective, according to the requirements

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established in DFL 4, Law No. 20,018, and the antitrust law DL 211 referred to above. Companies must also comply with the conditions set in Resolution No. 667/2002, discussed below.

The transmission sector is subject to the most significant restrictions, mainly because of its open access requirements. DFL 4 sets limits on the shareholdings of generation and distribution companies in companies that participate in the national transmission segment of the transmission system.

The owners of the National Transmission System (“STN” in its Spanish acronym) must be limited liability stock corporations. Individual interests in the STN by companies operating in another electricity or unregulated customer segment cannot exceed, directly or indirectly, 8% of the total investment value of the STN. The aggregate interest of all such agents in the STN cannot exceed 40% of the total investment value.

According to the Electricity Law, there are no restrictions on market concentration for generation and distribution activities. However, Chilean antitrust authorities have imposed certain measures to increase transparency associated with our subsidiaries and us through Resolution No. 667/2002 issued by the TDLC.

Resolution No. 667/2002 states that:

electricity generation and distribution activities cannot be merged (Enel Chile must continue to keep both business segments separate and manage them as independent business units);

Enel Chile, Enel Generation, and Enel Distribution are registered with the CMF and must remain subject to the regulatory authority of the CMF and comply with the regulations applicable to publicly held stock corporations, even if any of these companies should lose such designation;

members of the Board of Directors must be elected from different and independent groups; and

the external auditors of the companies must be different for local statutory purposes.

Also, the Water Utility Services Law sets restrictions on the overlapping of different utility concessions in the same area. It establishes limits on the ownership of the property for water and sewage service concessions and utilities that are natural monopolies, such as electricity distribution, gas or home telephone networks. For example, an electricity distribution company and a water utility company that belong to the same owner cannot operate in the same concession area.

3. Generation Segment

The generation segment is comprised of companies that own electricity generation power plants. They operate under market conditions delivering their electricity to end customers through transmission and distribution networks. Generation companies freely determine whether to sell their energy and capacity to regulated or unregulated customers, but CEN decides the operation of their power plants. The surplus or deficit between a generation company’s electricity sales and production is sold or purchased, as the case may be, to other generators at the spot market price.

Law No. 20,257 (2008) promotes the development of NCRE generation. In Chile, NCRE refers to electricity from wind, solar, geothermal, biomass, ocean (movement of tides, waves, and currents, as well as the ocean’s thermal gradient) and mini-hydro power plants with a capacity under 20 MW.

Law No. 20,257 required generators, between 2010 and 2014, to supply at least 5% of their total contracted sales from NCRE sources, with progressive increases of 0.5% per year beginning in 2015, ultimately reaching 10% by 2024. Law No. 20,698 (2013) modified the requirements of Law No. 20,257 and established a mandatory 20% share of NCRE source as a percentage of total contracted energy sales by 2025 but allowed contracts signed between 2007 and 2013 to maintain the 10% target by 2024.

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Dispatch, Customers, and Pricing

Generation companies may sell to distribution companies, unregulated end customers, or other generation companies through contracts. Generation companies satisfy their contractual sales requirements with dispatched electricity, whether produced by them or purchased from other generation companies in the spot market or through contracts. They balance their contractual obligations with their dispatch by trading deficit and surplus electricity at the spot market price, which is set hourly by CEN, based on the lowest cost of production of the last kWh dispatched.

CEN operates the electricity system with an approach that minimizes costs while monitoring the quality of the service provided by the generation and transmission companies. To reduce operating costs, CEN applies an efficiency criterion in which the lowest cost producer available is usually required to satisfy demand at any moment in time. As a result, at any specific level of demand, the appropriate supply is provided at the lowest possible production cost available in the system. This marginal cost on an hourly basis is the price at which generators trade energy in the spot market, using both their injections (sales) and their withdrawals (purchases) to balance their contracted customer sales with their production determined by CEN.

The customers of generation companies are classified by the electricity capacity demand required, as follows:

i) Unregulated customers: Customers who demand over 5,000 kW of capacity, mainly industrial and mining companies. These customers freely negotiate their electricity supply prices with generators and distributors. This customer category also includes those who demand between 500 and 5,000 kW of capacity with the option to choose between the unregulated and regulated regimes and who choose the unregulated regime.

ii) Distribution companies: Distributors distinguishing between the energy they require to satisfy their regulated customers from their unregulated customers. In the former case, distributors purchase energy from generation companies through an open bid process regulated by the CNE, while in the latter case they freely negotiate bilateral contracts with unregulated customers.

iii) Generation companies trading on the spot or short-term market: The energy and capacity transactions between generation companies arise from the difference between the electricity produced by a generator, as determined by the CNE, and the contractual obligations of that generator with its customers. The price of energy traded on the spot market is the hourly marginal cost of the system and the price of capacity sold on the spot market at a specific node.

Each generator receives a capacity payment set by CEN based on the generation capacity of each power plant and the available primary resource. This capacity payment replaces the previous “firm capacity” concept. It continues to depend primarily on the availability of such facility, the type of power plant technology, and the resources used to generate. It is the maximum capacity a generator may supply to the system at certain peak hours, considering statistical information, accounting for maintenance time and arid conditions for hydroelectric power plants, but differs from firm capacity because it does not consider the power plants’ contribution to the security of the entire system.

Generation costs are passed on to distributors’ regulated end consumers through the “average node price,” which corresponds to a single price determined for each distributor by the CNE, considering the weighted-average rates of their current supply contracts for regulated customers. The node price is adjusted in three instances: (1) every six months, in January and July of each year, based on local and international indexes; (2) upon the entry of a new supply contract with any distribution company; and (3) upon indexation of a supply contract by more than 10%.

Rationing

If a rationing decree is enacted in response to prolonged periods of electricity shortages, strict penalties may be imposed on generation companies that contravene the decree. A severe drought is not considered a force majeure event under our service agreements.

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Generation companies may also be required to pay fines to the regulatory authorities, as well as compensate electricity customers affected by shortages of electricity. Penalties are related to system blackouts due to an electricity generator’s operational problems, including failures related to the coordination duties of all system agents. If generation companies cannot satisfy their contractual commitments to deliver electricity during periods when a rationing decree is in effect and there is no energy available to purchase in the system, they must compensate the customers at a rate known as the “failure cost” determined by the authority in each node price setting. This failure cost, which is updated semiannually by the CNE, is a measurement of how much end customers would pay for one extra MWh under rationing conditions.

Water Rights

Companies in Chile must pay an annual fee for unused water rights. License fees already paid may be recovered through monthly tax credits, commencing on the start-up date of the project associated with the water rights. The maximum license fees that may be recovered are those paid during the eight years before the start-up date.

The Chilean Constitution considers water as a national public good in which real utilization rights are defined. It is similar to holding private property rights over water, as outlined in article 19, paragraph 24: “The rights of individuals over water, recognized or constituted under the law, grant their holders ownership over such rights.” Notwithstanding this definition, paragraph 24 also specifies legal limitations to those water rights.

The Chilean Congress is currently discussing amendments to the Water Code to make water use for human consumption, household subsistence and sanitation a high priority.

On November 22, 2016, the Chilean House of Representatives approved an amendment that is being evaluated by the Water Resources, Desertification and Drought Commission of the Chilean Senate. The main aspects of the amendments are as follows:

· Granting of new water rights, which would be limited to a maximum period of 30 years, extendable over future terms, unless the Water Authority proves the non-use of the resources. The extension would be effective only for water rights used.

· The expiration of new non-consumptive water rights that were granted by law, if the holder does not exercise the right of use within eight years.

· The expiration of new non-consumptive water rights previously granted: If the holder does not effectively use the rights within eight years from the date of enactment of the new Water Code, the term can be extended for up to four years only in justified cases such as delays in obtaining permits or environmental approvals.

In January 2019, the president of Chile modified this amendment to state that water rights have an unlimited duration. As of the date of this Report, the Chilean Congress is still discussing the amendment.

4. Transmission Segment

The transmission segment supplies electricity over lines or substations with a voltage or tension higher than 23 kV from generators’ production points to the centers of consumption or distribution. Transmission systems are comprised of the electricity lines and substations that are not considered part of the distribution network.

Given the structural characteristics of the transmission segments, it is subject to special electricity industry regulation. Tariffs are regulated, and access must be open and guaranteed under nondiscriminatory conditions.

Law No. 20,936, published in July 2016, established a new regulatory framework for all electricity transmission systems in Chile, redefining the system into the following segments: National, Development Poles, Zonal, Dedicated, and International.

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National and Zonal Transmission Systems planning is a centralized, regulated process conducted by CEN that annually issues an expansion plan to be approved by the CNE.

The expansion of both systems is granted through an open tender process that distinguishes new installations from the enlargement of existing facilities. The tenders conducted for new installations give the winner ownership of the installation to be built. The extension of existing facilities, on the other hand, belongs to the owner of the original facility, who is obliged to tender the construction of the required extension.

The remuneration of existing National and Zonal transmission installations is determined by a tariff-setting process conducted every four years. This process determines the Annual Transmission Value that considers efficient operation and maintenance costs and an annual valuation of investments based on a discount rate determined by the authorities every four years (minimum 7% after-tax) and the useful life of the installations.

The remuneration of extensions is the value resulting from the respective bid of such extension for the first 20 years of operations. Beginning with year 21, such extension is considered an existing installation and compensated accordingly.

The regulation currently in force states that transmission remuneration is the sum of tariff revenue and the usage charge revenue received for the use of the transmission system, defined as $/kWh by the CNE. The revenue is calculated on a semi-annual basis.

Finally, in the case of a failure in electricity transmission, Law No. 20,396 defines the penalty conditions for the responsible company (transmission, generation, or other).

Transmission Tariffs

Law No. 20,936 introduced changes to the transmission tariff-setting process. In transitioning to the implementation of the new law, the existing Zonal transmission tariff-setting process has been continued, as stated by transitory Article No. 20 of Law No. 20,936. The tariff-setting process for the 2018-2019 period concluded in October 2018 and has been applied retroactively since January 1, 2018. As of the date of this Report, an analysis of National and Zonal transmission tariffs for the 2020-2023 period is still in progress.  

5. Distribution Segment

The distribution segment is comprised of electricity infrastructure with a voltage lower than 23 kV to supply electricity to end customers. Electricity distribution is considered a natural monopoly. Therefore, companies operate under a public utility concession regime, with service obligations and regulated tariffs for supplying regulated customers. They may also sell to unregulated customers at negotiated prices.

Customers are classified according to their demand as regulated or unregulated. Regulated customers are those with a connected capacity of up to 5,000 kW. Unregulated customers are those with a connected capacity of over 5,000 kW. Customers with  a connected capacity between 500 kW and 5,000 kW may choose to be regulated or unregulated, subject to the respective price regime. Customers must remain in the selected category for at least four years.

Customers subject to the unregulated price regime may negotiate their electricity supply with any generator or distributor; however, they must pay a regulated toll for using the distribution network. Regulated customers with residential generation can sell their surpluses to the distribution company under certain conditions (regulation of net billing). Since November 2018, Law No. 21,118 has permitted customers with a connected capacity up to 300 kW to sell their surpluses.

The Chilean Ministry of Energy grants distribution concessions for undefined periods, as well as the right to use public areas for building distribution lines. Distribution companies have an obligation to supply electricity to all customers who request service within their concession area; however, customers who have chosen the unregulated price regime have the option to purchase electricity directly from generators and enter into commercial contracts with them if

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they deem the terms to be more favorable than with the distribution company assigned to their concession. A concession may be declared expired if the quality of service does not meet specific minimum standards.

Regarding the supply of electricity to regulated customers, DFL 4 establishes that distribution companies must have an amount of electricity permanently available. They must contract their energy supply through open, non-discriminatory and transparent public tenders. These bidding processes are managed by the CNE and are based on distribution companies’ projections of energy demand. They are conducted at least five years in advance from the expected effective date of the energy supply contract, which has a 20-year term. In case of unforeseen deviations in the projections of demand, the regulator has the authority to carry out short-term tenders. There is also a regulated mechanism to remunerate supply not covered by a contract if this were to take place.

The latest tender was conducted in 2017. A total of 2,200 GWh/year were awarded for the period from January 1, 2024 to December 31, 2043, at an average price of 32.5 US$/MWh, which must be wholly sourced from NCRE. In September 2019, the CNE announced a new bidding process for 5,800 GWh/year to be tendered for the period from 2026 to 2040. The deadline for the submission of bids is May 27, 2020. For further detail on the outcome of tenders, please see “Item 4. Information on the Company — B. Business overview”.

Distribution Tariffs

The Chilean distribution tariff model has gone through nine tariff-setting processes since its privatization in the 1980s.

Law No. 21,194 established new limits on returns on investments for distribution companies. Tariffs charged by distribution companies to regulated end customers are set every four years. Tariffs are determined by the sum of the cost of electricity purchased by the distribution company, a transmission charge, and the value added from distribution of electricity (“VAD”), which allows distribution companies to recover their investment and operating costs, including a legally mandated return on investment. The transmission charge reflects the price paid for electricity transmission and transformation. The law also mandates that distribution companies may not operate in other sectors or industries as of 2021.

The VAD is based on a so-called “efficient model company” within a Typical Distribution Area (“TDA”).  It considers the cost of building and operating the company at the minimum price, fulfilling the quality and safety standards of a company within that TDA. Therefore, the CNE classifies all distribution companies according to their TDA and subsequently selects one distribution company from each TDA to estimate its cost as an efficient model company. Distribution companies also carry out their own studies to determine the costs of such a company as an efficient model company. Cost estimates include fixed expenses, average energy and capacity losses, standard investment costs, and operation and maintenance costs. The annual investment costs are calculated considering the replacement cost of installations, useful life, and a rate of return that the CNE calculates every four years.

The CNE determines the VAD of each TDA. Preliminary tariffs, with the resulting VAD, are tested to ensure that they provide an industry aggregate rate of return between 6% and 8%. However, Law No. 21,194 establishes that the after-tax rate of return for each distributor must be between three percentage points below and two percentage points above the rate of return calculated by the CNE.

The real return on investment for a distribution company depends on its actual performance relative to the standards chosen by the CNE for the efficient model company. The tariff system allows for a higher return to distribution companies that are more efficient than the model company.

Electricity regulation establishes tariff equality mechanisms for electrical services. Law No. 20,928 states that the maximum tariff that distribution companies may charge residential customers must not exceed the average national tariff by more than 10%. The differences arising from the application of this mechanism are progressively absorbed by the remaining customers subject to regulated prices, which are under the mentioned average, except for those residential users whose monthly average consumption of energy in the prior calendar year is less than or equal to 200 kWh.

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Additionally, Chilean law provides that transitory subsidies can be granted if the residential customer tariff increases by 5% or more within six months. The state confers this subsidy, and its application is a power of the government and the last one was granted in 2009.

The tariff-setting process for 2016-2020 concluded in August 2017 and had been effective, retroactively, since November 4, 2016. On December 18, 2017, the CNE published a resolution that set the Technical Standard of Quality of Service for Distribution Systems, establishing higher technical and commercial standards. Included in these new standards are electricity supply reliability indicators, such as the System Average Interruption Frequency Index (SAIFI), which measures the average number of times a customer’s supply is interrupted in a year and the System Average Interruption Duration Index (SAIDI), which measures the total number of minutes, on average, that a customer is without electricity in a year, among others. This resolution also refers to product quality, metering, monitoring, and controlling, and commercial service quality. In this context, in September 2018, there was an extraordinary tariff update process, which is non-retroactive and will be in effect until the tariff-setting process for the period 2020-2024 has been completed. This process began in January 2020 and is ongoing. However, due to the recent social unrest that began in October 2019, distribution tariffs for 2020 will remain unchanged for the time being

Distribution companies may be required to compensate end customers in the case of electricity shortages that exceed the authorized standards. These compensatory payments are equal to double the amount of electricity the distribution company failed to provide, using a rate equal to the “failure cost.” Also, distribution companies are subject to the provisions of SEF, including articles 15 and 16 of Law No. 18,410, in which different infractions are listed and classified according to their severity and associated fines.

Distribution-Related Services

Distribution-related services are services identified by the TDLC as subject to regulation, such as meter rentals and meter verification, among others. The CNE sets the tariffs of these services every four years, along with the VAD calculation.

The tariff-setting process for the distribution related services for the 2016-2020 period concluded in July 2018. The new tariff is non-retroactive and will be in effect until the tariff-setting process for the period 2020-2024 has been completed. This process began in January 2020 and is ongoing. However, due to the recent social unrest that began in October 2019, distribution-related tariffs for 2020 will remain unchanged for the time being

6. Environmental Regulation

Chile has numerous laws, regulations, decrees, and municipal ordinances that address environmental considerations. Among them are regulations relating to waste disposal (including the discharge of liquid industrial wastes), the establishment of industries in areas that may affect public health and the protection of water for human consumption.

Environmental Law No. 19,300 was enacted in 1994 and has been amended by several regulations, including the Environmental Impact Assessment System Rule issued in 1997 and modified in 2001. This law establishes a general framework of regulation of the right to live in a pollution-free environment, the protection of the environment, the preservation of nature, and the conservation of environmental heritage. It also regulates environmental management instruments, such as the Strategic Environmental Assessment, the Environmental Impact Assessment System and Access to Environmental Information, the Environmental Damage Liability, the Enforcement and the Environmental Protection Fund and the environmental and institutional framework of Chile. This law requires companies to conduct an environmental impact study and a declaration of any future generation or transmission projects.

In January 2010, Law No. 19,300 was modified by Law No. 20,417, and introduced changes to the environmental assessment process and in the public institutions involved, principally creating the Chilean Ministry of Environment and the Superintendence of Environment. Environmental assessment processes are coordinated by this entity and by the Environmental Assessment Service (“SEA” in its Spanish acronym).

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The Ministry of the Environment is in charge of the management, protection, and application of environmental policies. Its mission is to lead sustainable development by implementing efficient public procedures and regulations and promoting good practices that improve citizen environmental education. The Ministry works in the recovery of air quality in urban centers, management of natural resources and biodiversity, proper final disposal of solid waste, climate change and protection of water resources and environmental education and citizen participation.

SEA is in charge of guarding the regulatory integrity within the framework of the environmental impact assessment of the projects, while the Superintendence of Environment monitors compliance with the environmental qualification, standards, and plans.

In June 2011, the Ministry of the Environment published Decree 13, which establishes emission standards for thermoelectric power plants applicable to generation units of at least 50 MW. The objective of this regulation is to control atmospheric emissions of particulate matter (PM), nitrogen oxides (NOx), sulfur dioxide (SO2), and mercury (Hg), to prevent and protect the health of the population and protect the environment. Existing emission sources are required to meet emission limits as established in the regulation for PM,  SO2, and NOx emissions by June 2015 in highly polluted areas, and by June 2016 elsewhere.

In June 2012, Law No. 20,600 created the Environmental Courts, special jurisdictional courts subject to the control of the Chilean Supreme Court. Their primary function is to resolve environmental disputes within their jurisdiction and investigate other matters that are submitted for their attention under the law. The law created three such courts, all of which are in operation.

On December 28, 2012, the Superintendence of Environment was formally created and began to exercise its powers of enforcement and sanctions under Chilean environmental regulations.

On September 10, 2014, Law No. 20,780 was enacted and included fees for the emission of PM, NOx, SO2, and CO2 into the atmosphere. For CO2 emissions, the fee is US$ 5 per ton (not applicable to renewable biomass generation). PM, NOx, and SO2 emissions are charged the equivalent of US$ 0.10 per ton, multiplied by the result of a formula based on the population of the municipality where the generation power plant is located, which is an additional fee of US$ 0.90 per ton of PM emissions, US$ 0.01 per ton of SO₂ emissions, and US$ 0.025 per ton of NO_x emissions. This tax became effective in 2018, with the amount due calculated based on the emissions of the previous year.

In 2017, authorities published Exempt Resolution No. 659 related to the implementation of Article No. 8 of Law No. 20,780 regarding taxes on thermal electric power plant emissions as a result of the country’s latest tax reform.

All thermal power plants of Enel Generation and its subsidiary GasAtacama have established methodologies to measure emissions and pay related taxes in line with the requirements of the Chilean Superintendence of Environment.

Regarding biodiversity, on January 5, 2018, the Chilean Sustainable Development Board approved the 2017-2030 National Biodiversity Strategy. This strategy replaced the national policy adopted in 2003. The new plan identifies five objectives related to the sustainable use of biodiversity and the development of the institutions and regulations required for the sustainable management of ecosystems.

7. Raw Materials

For information regarding our raw materials, please see “Item 11. Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

C.Organizational Structure.

Principal Subsidiaries and Affiliates

We are part of an electricity group controlled by Enel, an Italian company and our ultimate controlling shareholder, which beneficially owned 61.9% of our shares as of December 31, 2019, and as of the date of this Report.  

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Upon the termination and settlement on May 13, 2020 of a swap transaction entered into by Enel with respect to our ADSs, Enel’s beneficial ownership interest in us is expected to increase to 62.4%. Enel is an energy company with multinational operations in the power and gas markets, focusing primarily on Europe and Latin America. Enel operates in 33 countries across five continents, produces energy through a managed installed capacity of approximately 89 GW, which includes 46 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With 73 million users worldwide, Enel has the most extensive customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity. Enel shares trade on the Milan Stock Exchange.

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Enel Chile’s Simplified Organizational Structure (1)

As of the date of this Report

(1) Only principal operating consolidated entities are presented here.

(2) As of December 31, 2019 and the date of this Report, Enel S.p.A. owned 61.9% of Enel Chile. Upon the termination and settlement on May 13, 2020 of a swap transaction entered into by Enel S.p.A. with respect to Enel Chile’s American Depositary Shares, Enel S.p.A.’s beneficial ownership interest in Enel Chile is expected to increase to 62.4%.

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We consolidated the companies listed in the following table as of December 31, 2019. In the case of subsidiaries, economic interest is calculated by multiplying our percentage of economic interest in a directly held subsidiary by the percentage economic interest of any entity in the chain of ownership of such ultimate subsidiary.

Principal Subsidiaries	% Ownership of Each Main Subsidiary by Enel Chile	Consolidated Assets of Each Main Consolidated Entity	Revenues and Other Operating Income of Each Main Subsidiary
	(in %)	(in billions of Ch$)
Electricity Generation
Enel Generation	93.6%	3,587	1,638
EGP Chile (1)	99.9%	2,148	273
Electricity Distribution
Enel Distribution	99.1%	1,465	1,413

(1) EGP Chile is the result of EGPL merging into Enel Chile during the 2018 Reorganization

Generation Business

Enel Generation

Enel Generation is a Chilean electricity generation company, which has a total installed capacity of 6,114 MW as of December 31, 2019, with 28 generation facilities. Of the total installed capacity, 57% is from hydroelectric power plants and includes, among others, Ralco with 689 MW, Pehuenche with 568 MW, Pangue with 466 MW, El Toro with 449 MW, San Isidro with 379 MW, Rapel with 376 MW, and Antuco with 319 MW. Approximately 82% of Enel Generation’s thermoelectric facilities are gas/fuel oil power plants, and the remaining are coal-fired steam power plants. Our economic interest in Enel Generation was 93.6% as of December 31, 2019.

In September 2019, Enel Generation completed the intercompany acquisition of the 2.6% interest in GasAtacama that Enel Chile owned, which resulted in Enel Generation owning 100% of GasAtacama’s shares and permitted the vertical merger of GasAtacama into Enel Generation completed on October 1, 2019.

The purpose of this transaction was to reorganize and simplify the corporate structure of the subsidiaries that comprise the GasAtacama group to generate corporate and operational efficiencies for us. The merger did not have a significant economic or financial effect on the results and financial condition of Enel Generation, given the high percentage of share ownership that Enel Generation had in GasAtacama, but it will have a positive effect in both operational and corporate terms by simplifying the organizational structure.

EGP Chile

EGP Chile is an electricity utility company engaged in the generation business in Chile and a leader in Chile’s renewable energy market with a mixed portfolio of wind (564 MW), solar (492 MW), hydroelectric (92 MW) and geothermal (41MW) power. We hold a 99.9% economic interest in EGP Chile. For additional information on the corporate reorganization, see “Item 4. Information of the Company — A. History and Development of the Company — The 2018 Reorganization”.

Pehuenche

Pehuenche, a generation company connected to the SEN, owns three hydroelectric facilities located in the hydrological basin of the Maule River, south of Santiago, with a total installed capacity of 697 MW. The 568 MW Pehuenche plant began operations in 1991, the 89 MW Curillinque plant started operations in 1993, and the 40 MW Loma Alta plant began operations in 1997. Enel Generation holds 92.7% of the economic interest in Pehuenche. As of December 31, 2019, we beneficially owned an 86.7% economic interest in Pehuenche, through Enel Generation, and consolidate Pehuenche in our consolidated financial statements.

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Distribution Business

Enel Distribution

Enel Distribution is one of the largest electricity distribution businesses in Chile, as measured by the number of regulated customers, distribution assets, and energy sales. Enel Distribution operates in a concession area of 2,105 square kilometers in the Santiago Metropolitan Region, serving approximately 1.9 million customers. As of December 31, 2019, our economic interest in Enel Distribution was 99.1%.

D.Property, Plant and Equipment.

Our property, plant, and equipment is concentrated in electricity generation and distribution assets in Chile.

We conduct our generation business through EGP Chile, Enel Generation and their subsidiaries, which together own 48 generation power plants, all located in Chile, of which 18 are hydroelectric (3,548 MW installed capacity), 11 are thermal including geothermal (2,621 MW installed capacity), ten are solar (492 MW installed capacity) and nine are wind-powered (642 MW installed capacity).

A substantial portion of our generating subsidiaries’ cash flow and net income is derived from the sale of electricity produced by our electricity generation facilities. Significant damage to one or more of our main electricity generation facilities or interruption in the production of electricity, whether resulting from an earthquake, flood, volcanic activity, severe and extended droughts, or any other such natural disasters, could have a material adverse effect on our operations.

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The following table identifies the power plants that we own, all located in Chile, at the end of each year, organized by company and technology:

Property, Plant, and Equipment of Generation Companies

			Installed Capacity(1)(2) As of December 31,
Company	Power Plant Name	Power Plant Type(3)	2019	2018	2017
			(in MW)
Enel Generation	Rapel	Reservoir	376	376	377
	Cipreses	Reservoir	106	106	106
	El Toro	Reservoir	449	449	450
	Los Molles	Run-of-the-river	18	18	18
	Sauzal	Run-of-the-river	77	77	77
	Sauzalito	Run-of-the-river	12	12	12
	Isla	Run-of-the-river	70	70	70
	Antuco	Run-of-the-river	319	319	320
	Abanico	Run-of-the-river	136	136	136
	Ralco	Reservoir	689	689	690
	Palmucho	Run-of-the-river	34	34	34
	Pangue (5)	Reservoir	466	466	467
	Ojos de Agua (5)	Run-of-the-river	9	9	9
	Total hydroelectric		2,759	2,759	2,766
	Bocamina	Steam Turbine/Coal	476	478	478
	Diego de Almagro	Gas Turbine/ Diesel Oil	24	24	24
	Huasco	Gas Turbine	64	64	64
	Taltal	Gas Turbine/Natural Gas+Diesel Oil	240	240	245
	San Isidro 2	Combined Cycle /Natural Gas+Diesel Oil	388	388	399
	Quintero	Gas Turbine/Natural Gas	257	257	257
	Atacama (5)	Combined Cycle /Natural Gas+Diesel Oil	732	732	781
	Tarapacá (5)(6)	Steam Turbine/Coal	0	158	158
	Tarapacá (5)	Gas Turbine/Diesel Oil	20	20	24
	San Isidro (5)	Combined Cycle /Natural Gas+Diesel Oil	379	379	379
	Total thermal		2,580	2,740	2,809
	Canela I (5)	Wind Farm	18	18	18
	Canela II (5)	Wind Farm	60	60	60
	Total wind farm		78	78	78
	Total		5,417	5,577	5,653
Pehuenche	Pehuenche	Reservoir	568	568	570
	Curillinque	Run-of-the-river	89	89	89
	Loma Alta	Run-of-the-river	40	40	40
	Total		697	697	699
EGP Chile (4)	Eólica Los Buenos Aires	Wind	24	24	—
	Eólica Talinay Oriente	Wind	90	90	—
	Eólica Talinay Poniente	Wind	61	61	—
	Eólica Taltal	Wind	99	99	—
	Parque Eólico Renaico	Wind	88	88	—
	Parque Eólico Sierra Gorda Este	Wind	112	112	—
	Valle De Los Vientos	Wind	90	90	—
	Cerro Pabellón	Geothermal	41	41	—
	Pilmaiquén	Reservoir	41	41	—
	Pullinque	Run-of-the-river	51	51	—
	Carrera Pinto I Etapa	Solar	20	20	—
	Carrera Pinto II Etapa	Solar	77	77	—
	Chañares	Solar	40	40	—
	Lalackama	Solar	60	60	—
	Lalackama 2	Solar	18	18	—
	Pampa Solar Norte	Solar	79	79	—
	Parque Solar Finis Terrae	Solar	160	160	—
	Solar Diego de Almagro	Solar	36	36	—
	Solar La Silla	Solar	2	2	—
	Total EGP Chile (NCRE)		1,189	1,189	—
	Total Aggregate Capacity for Enel Chile		7,303	7,463	6,351

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(1) The installed capacity corresponds to the gross installed capacity, without considering the MW that each power plant consumes for its operation.

(2) The 2018 installed capacity may differ from capacity reported in previous years since the CEN reviewed the capacity of each generation unit and adjusted their capacity.

(3) “Reservoir” and “run-of-the-river” refer to hydroelectric plants that use the force of a dam or a river, respectively, to move the turbines that generate electricity. “Steam” refers to thermal power plants fueled with natural gas, coal, diesel, or fuel oil to produce steam that moves the turbines. “Gas Turbine” or “Open Cycle” refers to thermal power that uses either diesel or natural gas to produce steam that turns the turbines. “Combined-Cycle” refers to a thermal power plant fueled with natural gas, diesel oil, or fuel oil to generate gas that first moves a turbine and then recovers the gas from that process to generate steam that turns a second turbine.

(4) The acquisition of EGP Chile by Enel Chile was completed on April 2, 2018. It includes power plants of its subsidiaries Almeyda Solar SpA, Empresa Eléctrica Panguipulli S.A, Enel Green Power del Sur SpA, Geotérmica del Norte S.A., Parque Eólico Taltal S.A., Parque Eólico Talinay Oriente S.A., and Parque Eólico Valle de Los Vientos S.A.

(5) GasAtacama was merged into Enel Generation in October 2019.

(6) The Tarapacá steam turbine and coal plant was decommissioned on December 31, 2019.

Property, Plant, and Equipment of Distribution Companies

We conduct our distribution business through Enel Distribution and its subsidiaries, Empresa Eléctrica de Colina Ltda. and Luz Andes Ltda.

A substantial portion of our distribution subsidiaries’ cash flow and net income are derived from the sale of electricity distributed through our distribution installations.  Significant damage to one or more of our principal electricity distribution installations or interruption in the distribution of electricity, whether as a result of an earthquake, flood, volcanic activity, severe snowstorms, wind storms, or any other such natural disasters, could have a material adverse effect on our operations.

The table below describes our leading electricity distribution equipment, such as distribution networks, substations, transformers, and transmission lines.  They include the consolidated property, plant, and equipment figures of our subsidiary Enel Distribution.

TABLE OF DISTRIBUTION FACILITIES

General Characteristics

		Transmission Lines(1)(2) As of December 31,
	Concession Area	2019	2018	2017
	(in km2)	(in kilometers)
Enel Distribution	2,105	683	367	367

(1) The transmission lines consist of circuits with voltages in the 35-220 kV range.  The figures correspond to the high voltage lines that may contain one or more circuits.

(2) Since 2019, the reported figures correspond to kilometers at the line circuit-level instead of at the line track-level.

Power and Interconnection Substations and Transformers (1)

	As of December 31, 2019			As of December 31, 2018			As of December 31, 2017
	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)	Number of Substations	Number of Transformers	Capacity (MVA)
Enel Distribution (2)	57	207	7,554	56	206	8,398	56	203	8,386

(1)The voltage of these transformers is in the range of 500 kV (in - high voltage) and 1 kV (out - medium voltage).

(2)As of December 31, 2017, and 2018 back-up transformers that are no longer in operation were included.

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Distribution Network - Medium and Low Voltage Lines (1)

	As of December 31, 2019		As of December 31, 2018		As of December 31, 2017
	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage	Medium Voltage	Low Voltage
			(in Kilometers)
Enel Distribution	5,349	11,819	5,331	11,678	5,298	11,519

(1) Medium voltage lines: 1 kV - 34.5 kV; low voltage lines: 380‑110 V.

Transformers for Distribution (1)

	As of December 31, 2019		As of December 31, 2018		As of December 31, 2017
	Number of Transformers	Capacity	Number of Transformers	Capacity	Number of Transformers	Capacity
		(in MVA)		(in MVA)		(in MVA)
Enel Distribution	21,839	4,963	21,767	4,739	21,838	4,575

(1) The voltage of these transformers is in the range of 34.5 kV (in - medium voltage) and 1 kV (out - low voltage).

Insurance

Our electricity generation and distribution facilities are insured against damage caused by natural disasters such as earthquakes, fires, floods, other acts of god (but not for droughts, which are not considered force majeure risks and are not covered by insurance), and from damage from third-party actions, based on the appraised value of the facilities as determined from time to time by an independent appraiser. Based on geological, hydrological, and engineering studies, we believe that the risk of the previously described events resulting in a material adverse effect on our facilities is remote. Claims under our subsidiaries’ insurance policies are subject to customary deductibles and other conditions. We also maintain business interruption insurance, providing coverage for the failure of any of our facilities for a period of up to 24 months, including the deductible period. Insurance policies include liability clauses, which protect our companies from claims made by third parties. The insurance coverage taken for our property is approved by each company’s management, taking into account the quality of the insurance companies and the coverage needs, conditions, risk evaluations of each facility, and is based on general corporate guidelines. All insurance policies are purchased from reputable international insurers. We continuously engage with the insurance companies to negotiate what we believe is the most commercially reasonable insurance coverage.

Project Investments

We are continuously analyzing potential opportunities for growth. The study and profitability assessment of our project portfolio is an ongoing effort. Industry technology is allowing for smaller, less environmentally damaging power plants. These plants can be built quicker, allow greater flexibility to activate or deactivate according to system needs, and are preferred by our stakeholders. We are favoring renewable energy technology for our new power plant investments. We seek opportunities by building new greenfield projects or by modernizing existing brownfield assets and improving (operationally or environmentally) performance. The expected start-up for each project is assessed and is defined based on the commercial opportunities and our financing capacity to fund these projects. All our projects are financed with internally generated funds. Below we list our most important projects under development; however, any decision related to the development will depend on commercial opportunities foreseen in the upcoming years, including future tenders for supplying the regulated market and the evolution of the regulatory framework (mainly associated with ancillary services).

Budgeted amounts include connecting lines that could be owned by third parties and paid as tolls unless otherwise indicated. The financing for all of our projects described below comes from internally generated sources.

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Distribution Business Projects

During 2019, our subsidiary Enel Distribution and its subsidiaries, Empresa Eléctrica de Colina and Luz Andes, invested a total of Ch$ 106 billion in projects related to our customers’ natural growth rate, service quality requirements, safety and information system needs.

The most relevant investments in 2019 include the following:

· Ch$ 26 billion in the medium and low voltage networks to allow the connection of new customers, including residential customers, large volume customers, and real estate projects.

· Ch$ 23 billion to increase our distribution capacity, in (i) the high voltage network , mainly in the Nueva Lampa, Chena, Pudahuel, Macul, Cerro Navia, Quilicura, A. Córdova, Chicureo, San Cristobal, Los Dominicos, and San Joaquín substations; (ii) the medium voltage network, by reinforcement of the Apoquindo substation, and implementing new feeders in Airport and Parque Arauco; and (iii) the low voltage network, where reinforcements and extensions of networks were implemented.

· Ch$ 17 billion to reinforce feeders, specifically those determined in our quality plan. Automation of the medium voltage network increased rapidly as a result of the installation of 414 new remote-control devices, reaching a total of 2,055 devices controlled by our Centralized Network Operations Center.

· Ch$ 9 billion to comply with regulations regarding network and substation normalization.

· Ch$ 9 billion oriented to the digitalization process.

· Ch$7 billion for corrective maintenance works of the network, installation of transmission lines, interconnection and power substations.

· Ch$ 3 billion for network relocations due to new highways and requests from municipalities.

· Ch$2 billion for anti-theft measures, such as the shielding and reinforcements of the network.

Generation Business Projects

A.Projects under Construction in 2019

Enel Generation

Antuco Hydroelectric Repowering Project

The Antuco repowering project is being executed within our existing 319 MW Antuco power plant, located in the Bíobío Region of southern Chile. Antuco is a run-of-the-river hydroelectric power plant with two Francis vertical units. It uses the resources of several estuaries, with waters coming from the Polcura, Laja, and Pichipolcura rivers, as well as the discharges from the Abanico and El Toro power plants.

The project involves replacing one turbine (Unit I) installed in 1981, with an efficiency of 88%, with a new turbine with a target efficiency rate of 94%, obtaining 204 GWh/year of new energy. Replacing the turbine in Unit I is a two-step process. Step one was conducted in September 2019, and we expect step two to begin in June 2020. We expect the project to be commercially operational in 2020-2022.

As of December 31, 2019, 53% of the project had been completed. The total approved investment is US$ 14.5 million, of which US$ 3.8 million had been incurred as of December 31, 2019.

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Bocamina Coal Plant Landfill Closure Plan

The project considers the application of the best practices for ash dumpsite facilities. It considers improvements to the landfill’s infrastructure and operations, the implementation of a high standard for its closure, and fulfillment of the obligations arising from the Environmental Qualification Resolution (“RCA” in its Spanish acronym) approved in March 2015. In summary, the closure plan comprises waterproofing materials that include a conductive geo-membrane; use of the highest thicknesses of fillers and substrates; a selection of native species; a high density of specimens per hectare and a revegetation design according to reference ecosystems in the area, with the advice of Universidad de Concepción.

The closure plan is composed of two stages:

· Stage 1: The approved project considers the closure of 67,000 m2 of the landfill.

· Stage 2: This stage will be executed when the landfill completes its operational life.

In February 2019, the Environmental Evaluation Service (“SEA” in its Spanish acronym) issued all permits. In July 2019, the revegetation pilot was completed, and a notice to proceed with a contractor to complete stage 1 was issued. As of December 31, 2019, 60% of the project had been completed. We expect the project to be ready in 2020-2022

The total approved investment is Ch$ 12,402 million, of which Ch$ 5,124 million had been incurred as of December 31, 2019.

Los Cóndores Hydroelectric Project

The Los Cóndores project is in the Maule Region, in the San Clemente area of central Chile. It consists of a 150 MW run-of-the-river hydroelectric power plant, with two Pelton vertical water turbine units, which will use water from the Maule Lagoon reservoir through a pressure tunnel. The power plant will be connected to the SEN at the Ancoa substation (220 kV) through an 87 km transmission line.

As of December 31, 2019, 82% of the project had been completed and 93% of the transmission lines had been completed and assembled. The construction of this project began in 2014 and we expect the project to be commercially operational in 2020-2022.

The total approved investment is Ch$ 713 billion, of which Ch$ 511 billion had been incurred as of December 31, 2019.

Sauzal Hydroelectric Repowering Project

The Sauzal Repowering project is being executed within our existing 77 MW Sauzal power plant, located in the Libertador General Bernardo O’Higgins Region of central Chile. It is a run-of-the-river hydroelectric power plant with three Francis vertical units that use the water of the Cachapoal and Claro Rivers.

The project involves replacing two turbines (Unit I and Unit II) installed in 1948 with an efficiency of 88%, with new turbines with expected efficiency of 94.7%, each producing 13.7 GWh/year of new energy.

As of December 31, 2019, 88% of the project had been completed. Construction for Unit I began on July 9, 2019, and we expect the construction of Unit II to begin in June 2020, with both units commercially operational in 2020-2022.

The total approved investment is US$ 10.5 million, of which US$ 5.4 million had been incurred as of December 31, 2019.  

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EGP Chile

Azabache Solar Project

Azabache is a photovoltaic (“PV”) project in Calama in the Antofagasta Region of northern Chile and is being executed within our existing 90 MW Valle de los Vientos wind farm. The project has an installed capacity of 61 MW, consisting of 154,710 monocrystalline bifacial PV modules with a solar tracking system and occupying an area of approximately 149 hectares.

The plant will be connected to the Valle de los Vientos substation, which is connected to the Calama substation. The interconnection solution includes a main transformer and a step-up substation with a conventional bay, including its ancillary elements.

A connection contract between EGP Chile and Acciona will be signed, which requires the Usya PV solar power plant project (owned by Acciona) to install the second circuit of the Valle de los Vientos – Calama transmission line (13.6 km) and the extension of Valle de los Vientos substation.

Construction began in April 2020, and we expect the project to be commercially operational in 2020-2022. The total approved investment is US$ 49 million, of which US$ 1 million had been accrued as of December 31, 2019

Campos Del Sol I Solar Project

The Campos del Sol I solar project is in the Atacama Region of northern Chile, approximately 60 km northeast of Copiapó. The PV solar power plant has 382 MW of installed capacity and consists of 974,400 crystalline bifacial PV modules with a solar tracking system. It will be the largest PV solar power plant in Chile, covering approximately 1,700 hectares. The connection point includes two main transformers through the Carrera Pinto substation, owned by Transelec, via a 7.5 km, 220 kV transmission line.

The project was awarded to EGP Chile during the 2016 Distribution Companies Tender. EGP Chile intended to bid part of this project in the bilateral processes to move up the commercial date of operation. The land has been secured, the environmental approval has been obtained, and the power purchase agreements for 2021-2045 have already been confirmed. The project has potential synergies with EGP Chile’s operational Carrera Pinto solar project.

Construction began on August 23, 2019, and we expect the project to be commercially operational in 2020-2022. The total approved investment is US$ 320.9 million, of which US$ 39 million had been accrued as of December 31, 2019.  

Cerro Pabellón Geothermal Extension Project

The Cerro Pabellón extension project is a geothermal energy plant with a capacity of 33 MW and is in the Antofagasta Region of northern Chile. It has potential synergies with our operational Cerro Pabellón geothermal project and will use existing infrastructure such as a substation and a transmission line.

Construction began in August 2019, and we expect the project to be commercially operational in 2020-2022. The total approved investment is US$ 95.8 million, of which US$ 35.5 million had been accrued as of December 31, 2019.

Finis Terrae Solar Extension Project

The Finis Terrae extension project is a PV solar power plant in María Elena in the Antofagasta Region of northern Chile and has an installed capacity of 126 MW.

The PV solar plant occupies an area of 387,5 hectares and the perimeter is about 11.2 km. It consists of 315,900 monocrystalline bifacial PV modules with a solar tracking system. The land has been secured, and environmental approval has been obtained. The project has strong operational synergies with EGP Chile’s existing 160 MW Finis

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Terrae power plant. The Finis Terrae extension project will use the same transmission infrastructure as the existing Finis Terrae power plant, with a new bay unit and new power transformer to be installed in the current substation for interconnection purposes.

Construction began in April 2020, and we expect the project to be commercially operational in 2020-2022. The total approved investment is US$ 94.4 million, of which US$ 0.5 million had been accrued as of December 31, 2019.  

Renaico II Wind Project

The Renaico II wind project is in the Araucanía Region of southern Chile. It consists of a 144 MW power plant with two farms: (i) the Las Viñas project, which includes a 58.5 MW wind power plant built by EGP Chile and (ii) the Puelche project, which consists of a 85.5 MW wind power plant developed independently by Pacific Energy. The Puelche project will be acquired in its entirety by EGP Chile.

The project consists of 32 wind turbine generators, interconnected to the SEN through the existing Renaico I 220 kV substation in which a new bay will be installed with a main transformer of 165 MVA. The Renaico II wind project has potential synergies with EGP Chile’s operational Renaico I wind project and will use existing infrastructure such as a substation and a transmission line. The land has been secured, and the environmental approval is in process.

We expect construction to begin in May 2020 and the project to be commercially operational in 2020-2022. The total approved investment is US$ 175.6 million, of which US$ 13.3 million had been accrued as of December 31, 2019.

Sol de Lila Solar Project

Sol de Lila is a PV solar project in the Atacama Desert in the Antofagasta Region of northern Chile, at an altitude of 2,700 meters and approximately 250 km southeast of the city of Antofagasta.  Due to the remoteness of the project, the construction of a camp with a capacity for 400 people is required.

It is a greenfield solar project with an installed capacity of 163 MW that consists of 407,400 crystalline bifacial PV modules with a solar tracking system. The solar plant is connected to the Andes substation, owned by AES Gener, and includes one main transformer and a 1.2 km, 220 kV transmission line.

Construction began in March 2020, and we expect the project to be commercially operational in 2020-2022. The total approved investment is US$ 129.6 million, of which US$ 2 million had been accrued as of December 31,  2019.

B.Projects under Development

We are currently evaluating the development of the following projects, which we classify as “under development.” We will decide whether to proceed or not with each project depending on the commercial and other opportunities foreseen in upcoming years, as well as future tender prices for supplying the energy requirements of the regulated market and negotiations with existing or new unregulated customers.

Enel Generation

Quintero Combined-Cycle Thermal Project

The Quintero project is in the Valparaíso Region of central Chile. It is an energy efficiency project that would take advantage of the heat of the gases emitted by the existing turbines to produce steam through the installation of a steam turbine and a generator, which would convert the existing open-cycle plant into a combined-cycle gas plant. Currently, the Quintero plant has two gas turbines with a total capacity of 257 MW. With the addition of a steam turbine unit of 130 MW capacity, the Quintero plant would reach a full capacity of 387 MW. We would deliver the produced energy to the SEN through the existing Quintero-San Luis line, a simple 220 kV circuit built to transmit the energy produced by the combined-cycle power plant.

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In 2017, we started the preparation of the EIA and the implementation of the sustainability plan. However, during August 2018, the Quintero and Puchuncaví areas suffered an ecological crisis that left more than 300 people suffering from the toxic effects associated with gas emissions of other industries. As a result, the project was indefinitely postponed, and the EIA has been suspended.

The total estimated investment is for Ch$ 162,128 million, of which Ch$ 2,855 million had been incurred as of December 31, 2019. We  expect the project to be commercially operational in 2020-2022.

Taltal Combined-Cycle Thermal Project

The Taltal power plant is in the Antofagasta Region of northern Chile and has an installed capacity of 240 MW comprised of two 120-MW gas turbines. The project would convert the existing Taltal gas-fired, open-cycle plant into a combined-cycle plant by adding a turbine to the vapor phase. This turbine would use the steam generated by the gas turbines’ heat emissions to produce energy and considerably improve its efficiency. The steam turbine would add 130 MW of installed capacity, and therefore, the Taltal power plant would reach a total capacity of 370 MW. We would supply the energy produced to the SEN via the existing 220 kV, double circuit, Diego de Almagro — Paposo transmission line.

The environmental permit, requested through an EIA and submitted in December 2013, was approved in January 2017 by the SEA of the Antofagasta region. Any decision related to the development of the project will depend primarily on the commercial opportunities foreseen in the upcoming years (prices in future tenders and negotiations with unregulated customers, among others).

The total estimated investment is for Ch$ 147,585 million, of which Ch$ 2,873 million had been incurred as of December 31, 2019. We  expect the project to be commercially operational in 2020-2022.

Taltal Battery Energy Storage System

The project consists of the installation of a battery energy storage system (BESS) in the Taltal power plant in the Antofagasta Region of northern Chile, to provide ancillary services in upcoming years. The project would add 12 MW of installed capacity and 12 MWh of energy storage connected to the 15 kV bar of one of the existing 120-MW turbines installed in the Taltal power plant.

In May 2018, the SEA of the Antofagasta Region issued a resolution waiving the obligation to submit the project to an EIA before its construction. Any decision related to the development of the project will depend primarily on the commercial opportunities foreseen in the upcoming years and, mainly, on the evolution of the regulatory framework for the provision and remuneration of the ancillary services, as well as the annual analysis to be conducted by the system operator of the required volumes of those services.

The total estimated investment is for Ch$ 9,182 million, of which Ch$ 36 million had been incurred as of December 31, 2019. We  expect the project to be commercially operational in 2020-2022.

Tarapacá Battery Energy Storage System

The project consists of installing a BESS in the Tarapacá power plant in the Tarapacá Region of northern Chile, and providing ancillary services in upcoming years. The BESS would add approximately 14 MW of installed capacity and 14 MWh of energy storage and would be connected to the 11.5 kV bar of the existing 23 MW turbine installed in the Tarapacá power plant.

In December 2017, the SEA of the Tarapacá Region issued the resolution waiving the obligation to submit the project to an EIA before its construction. Any decision related to the development of the project will depend on the commercial opportunities foreseen in the upcoming years and, mainly, on the evolution of the regulatory framework for the provision and remuneration of the ancillary services, as well as the annual analysis to be conducted by the system operator of the volumes of those services.

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The total estimated investment is for Ch$ 10,769 million, of which Ch$ 102 million had been incurred as of December 31, 2019. We  expect the project to be commercially operational in 2020-2022.

EGP Chile

Campos del Sol II Solar Project

The Campos del Sol II solar project is in Copiapó in the Atacama Region of northern Chile and has an installed capacity of 398 MW. Campos del Sol II is a PV solar power plant consisting of 893,508 crystalline bifacial PV modules with a solar tracking system. The plant is built on an area of approximately 1,000 hectares.

The connection point will be the Bella Mónica step-up substation, located between Campos del Sol I and Campos del Sol II. Bella Mónica is located 8 km from the Illapa substation, owned by Celeo Redes Chile Ltda, and is connected via a 220kV transmission line.

We expect construction to begin in 2020-2022. The total estimated investment is for US$ 274.1 million, of which US$2 million had been incurred as of December 31, 2019.

Domeyko Solar Project

The Domeyko PV solar project is in Antofagasta in the Antofagasta Region of northern Chile. It has an installed capacity of 204 MW, consisting of 486,720 bifacial PV modules with a solar tracking system and occupying approximately 700 hectares.

The Domeyko project will be connected to Puri substation via an 18 km, 220 kV interconnection line. The interconnection substation has a gas insulated substation (GIS) configuration, while the step-up substation will have a single bar configuration.

The Domeyko project will sell energy to Enel Generation under a 20-year power purchase agreement. We expect construction to begin in 2020-2022. The total estimated investment is for US$ 164.2 million, of which US$ 0.7 million had been accrued as of December 31, 2019.

Sierra Gorda Solar Project

The Sierra Gorda PV solar project is in Sierra Gorda, near Calama, in the Antofagasta Region of northern Chile. The PV solar power plant has an installed capacity of 375 MW and occupies 850 hectares, with a perimeter of approximately 28 km.

It is a greenfield project that will be constructed inside the existing Sierra Gorda wind farm, which is owned by EGP Chile. The project has five main areas for PV modules (inside wind farm) and an independent space for the medium voltage/high voltage (MV/HV) substation. It consists of 830,000 monocrystalline bifacial PV modules with a solar tracking system. The interconnection substation is located 19 km from the solar plant, in the Centinela substation owned by Red Eléctrica Chile.

We expect construction to begin in 2020-2022. The total estimated investment is for US$ 252.5 million, of which US$ 0.03 million had been incurred as of December 31, 2019. 

Valle del Sol Solar Project

The Valle del Sol PV solar project is in the Atacama Desert, approximately 100 km west of Calama in the Antofagasta Region of northern Chile. It was awarded a 20-year power purchase agreement in context of the energy Distribution Companies Tender 2017 (2024-2043).

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It is a greenfield solar project with an installed capacity of 163 MW that consists of 406,980 monocrystalline bifacial PV modules with a solar tracking system and occupying 320 hectares. Valle del Sol will connect to the Miraje substation, owned by Transelec, via a new 220 kV bay. The connection solution includes step-up substation, one main transformer of 144/180 MVA (33/33/220 kV), and the interconnection 220 kV transmission line with a length of 10 km.

We expect construction to begin in 2020-2022. The total estimated investment is for US$ 125.4 million, of which US$ 1.3 million had been accrued as of December 31,  2019.

Flor del Desierto Solar Project

The Flor del Desierto solar project is located in the Antofagasta Region of northern Chile. It has an installed capacity of 50 MW. The land has been secured, and environmental approval has been obtained. We expect the project to be commercially operational in 2025. The total estimated investment is for US$39.4 million, of which US$0.19 million had been accrued as of December 31, 2019.

Los Manolos Solar Project

The Los Manolos solar project is located in the Arica Region of northern Chile. It has an installed capacity of 80 MW. The land has been secured, and environmental approval has been obtained. We expect the project to be commercially operational in 2025. The total estimated investment is for US$62.6 million, of which US$0.27 million had been accrued as of December 31, 2019.

Major Encumbrances

As of December 31, 2019, we do not have any major encumbrances.

Item  4A.      Unresolved Staff Comments

None.

Item  5.      Operating and Financial Review and Prospects

A. Operating Results.

General

The following discussion should be read in conjunction with our audited consolidated financial statements and the notes thereto, included in Item 18 in this Report, and “Selected Financial Data,” included in Item 3 herein. Our audited consolidated financial statements as of December 31, 2019, and 2018 and for each of the years in the three-year period ended December 31, 2019, have been prepared in accordance with IFRS, as issued by the IASB.

1.Discussion of Main Factors Affecting Operating Results and Financial Condition of the Company

Through our subsidiaries, we own and operate electricity generation and distribution companies in Chile. Our revenues, income, and cash flow are derived primarily from the operations of our subsidiaries and associates in Chile.

Factors such as (i) hydrological conditions, (ii) fuel prices, (iii) regulatory developments, (iv) extraordinary actions adopted by governmental authorities, and (v) changes in economic conditions may materially affect our financial results. Also, our results from operations and financial condition are affected by variations in the exchange rate between the Chilean peso and the U.S. dollar. We have certain critical accounting policies that affect our consolidated operating results. The impact of these factors on us, for the years covered by this Report, is discussed below.

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As of April 2, 2018, we own 93.6% of Enel Generation and consolidate operations and results of EGP Chile, a wholly owned subsidiary. For further information regarding our incremental acquisition of this company, please refer to “Item 4. Information on the Company — A. History and Development of the Company. — History.”  The effects of this transaction on our consolidated financial statements as of December 31, 2019 are described in Note 6 to our consolidated financial statements.

On November 2, 2019, the Ministry of Energy published the Law No. 21,185, which sets up a Transitional Mechanism for the Stabilization of Electric Power Prices for Customers subject to Tariff Regulation (the “Tariff Stabilization Law”). The effects of the Tariff Stabilization Law as of December 31, 2019 are described in Note 11 to our consolidated financial statements.

Additionally, during 2019 two extraordinary transactions affected our results. First, we recorded an impairment cost associated with accelerating the closures of the Tarapacá and Bocamina I coal-fired power plants (see Notes 18.e.x and 31.b. to our consolidated financial statements). We accounted for non-recurring income derived from the early termination of three energy supply contracts signed in 2016 between Enel Generation and Anglo American Sur. The effects are described in Note 28.3 to our consolidated financial statements.

a. Generation Business

A substantial part of our generation capacity is hydroelectric and depends on the prevailing hydrological conditions in Chile. Our installed capacity as of December 31, 2019, 2018 and 2017 was 7,303 MW, 7,463 MW and 6,351 MW, respectively, of which 49%, 48% and 55% was hydroelectric, respectively. See “Item 4. Information on the Company — D. Property, Plant and Equipment.”

Hydroelectric generation was 10,578 GWh, 11,395 GWh and 9,652 GWh in 2019, 2018 and 2017, respectively. Our hydroelectric generation decreased in 2019 compared to 2018, mainly related to the lower hydrological production due to the drier hydrological conditions in the country. Since 2010, some critical reservoirs have been at relatively low levels due to several years of accumulated drought, characterized by low rainfall levels and poor snowmelt.

Hydrological conditions in Chile can range from very wet, as a result of several years of abundant rainfall and lakes at their peak capacity, to extremely dry, as a consequence of prolonged drought lasting for several years, the partial or material depletion of water reservoirs, and the significant reduction of snow and ice in the mountains, which in turn leads to materially lower levels of available water as a consequence of lower melts. Between these two extremes, there is a wide range of possible hydrological conditions, and their final effect on us often depends on accumulated hydrology. For instance, a new year with drought conditions has less of an impact on us if it follows several periods of abundant rainfall, as opposed to exacerbating a prolonged drought. Likewise, an excellent hydrological year has a less marginal effect if it comes after several wet years as opposed to after prolonged drought.

In Chile, the period of the year that typically has the most precipitation is from May through August, and the period in which snow and ice in the mountains melt at higher levels is during the warmer months, from October through March, providing water flow to lakes, reservoirs, and rivers, which supply our hydroelectric plants, most of them located in southern Chile.

For purposes of discussing the impact of hydrological conditions on our business, we generally classify our hydrological conditions as either dry or wet, although there are several other intermediate scenarios. Extreme hydrological conditions materially affect our operating results and financial condition. However, it is difficult to indicate the effects of hydrology on our operating income, without concurrently considering other factors, because our operating income can only be explained by looking at a combination of factors and not each one on a stand-alone basis.

Hydrological conditions affect electricity market prices, generation costs, spot prices, tariffs, and the mix of hydroelectric, thermal, and NCRE generation, which is continually being determined by the CEN to minimize the operating costs of the entire system. According to the current regulatory framework, the price at which energy is traded on the spot market (known as the “spot price”) is determined by the marginal cost of the system. The marginal cost is the

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cost of the most expensive power plant in operation, given an efficiency-based dispatch. The regulations also consider capacity payments to generators, which remunerates each power plant’s installed capacity according to its availability and contribution to the system’s safety. This capacity payment is determined by the regulator every six months. Hydroelectric and NCRE generation are almost always the least expensive generation technology and typically have a marginal cost close to zero. Water from reservoirs used to generate electricity, on the other hand, is assigned an opportunity cost for the use of water, which may lead to hydroelectric generation using water from reservoirs having a high cost in extended drought conditions. The cost of thermal generation does not depend on hydrological conditions but instead on international commodity prices for LNG, coal, diesel, and fuel oil. Solar and wind sources are currently the NCRE technologies most widely used. NCRE facilities can dispatch energy to the system at very low marginal costs, but they depend on the blowing of the wind or the shining of the sun.

Spot prices primarily depend on hydrological conditions and commodity prices and, to a lesser extent, on NCRE availability. Under most circumstances, abundant hydrological conditions lower spot prices while dry conditions typically increase spot prices. Spot market prices affect our results because we must purchase electricity in the spot market when our contracted energy sales are more than our generation, and we sell electricity in the spot market when we have electricity surpluses.

Hydrological conditions do not have an isolated effect but need to be evaluated in conjunction with other factors to better understand the impact on our operating results. Many other factors may affect our operating income, including the level of contracted sales, purchases and sales in the spot market, commodity prices, energy demand and supply, technical and unforeseen problems that can affect the availability of our thermal plants, plant locations in relation to urban demand centers, and transmission system conditions, among others.

To illustrate the effects of hydrology on our operating results, the following table describes certain hydrological conditions, their expected effects on spot prices and generation, and the expected impact on our operating income, assuming that other factors remain unchanged.

Hydrological conditions	Expected effects on spot prices and generation	Expected impact on our operating results
Dry	Higher spot prices	Positive: if our generation is higher than our contracted energy sales, energy surpluses are sold in the spot market at higher prices. Negative: if our generation is lower than our contracted sales, we have an energy deficit and must purchase energy in the spot market at higher prices.
	Reduced hydroelectric generation	Negative: less energy available to sell in the spot market.
	Increased thermal generation	Positive: increases our energy available for sale and either reduces purchases in the spot market or increases sales in the spot market at higher prices.
Wet	Lower spot prices	Positive: if our generation is lower than contracted energy sales, the energy deficit is covered by purchases in the spot market at lower prices. Negative: if we have energy surpluses, they are sold in the spot market at lower prices.
	Increased hydroelectric generation	Positive: more energy available to sell in the spot market at lower prices.
	Reduced thermal generation	Negative: less energy available to sell in the spot market.

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If factors other than those described above apply, the expected impact of hydrological conditions on operating results will be different from those shown above. For instance, in a dry year with lower commodity prices, spot prices may decrease, or in a wet year, if demand increases, or generation plants are not available for technical or other reasons, the spot price may increase, altering the impact of hydrological conditions discussed in the table above.

b.Distribution Business

Our electricity distribution business is conducted through Enel Distribution in the Santiago metropolitan area, providing electricity to more than 1.9 million customers. Santiago is the country’s most densely populated area and has the highest concentration of industries, industrial parks and office facilities in the country.

For the year ended December 31, 2019, electricity sales amounted to 17,107 GWh, representing a 1.9% increase when compared to 2018. For the year ended December 31, 2018, electricity sales amounted to 16,782 GWh, representing a 2.1% increase when compared to 2017.

Distribution revenues are mainly derived from the resale of electricity purchased from generators. Revenues associated with distribution include the recovery of the cost of electricity purchased and the resulting revenues from the “Value Added from Distribution,” or VAD, plus the physical energy losses permitted by the regulator. Other revenues derived from our distribution business typically consist of transmission revenues, charges for new connections and the maintenance, and rental of meters, among others. It also includes revenues derived from public lighting, infrastructure projects mainly associated with real estate development and energy efficiency solutions, including air conditioning equipment, LED lights, etc., in all cases, including customers outside of our concession area.

Although these other sources of revenue have increased, our core business continues to be the distribution of electricity at regulated prices. Therefore, the electricity regulatory framework has a substantive impact on our distribution business results.

In particular, regulators set distribution tariffs taking into account the cost of electricity purchases paid by distribution companies (which distribution companies pass on to their customers) and the VAD, all of which are intended to reflect the investment and operating costs incurred by distribution and generation companies and to allow them to earn a regulated level of return on their investments and guarantee service quality and reliability. Our earnings are determined to a large degree by government regulation, mainly through the tariff setting process. Our ability to buy electricity relies highly on generation availability and on regulation, to a lesser degree. The cost of electricity purchases is passed on to end-users through tariffs that are set for multi-year periods. Therefore, variations in the price at which a distribution company purchases electricity do not have an impact on our profitability.

In the past, we focused on reducing physical losses, especially those due to illegally tapped energy. Our physical losses have generally been around 5% over 20 years, a level close to the distribution technical loss threshold for our concession. Reducing losses below this level requires additional investments to reduce illegal tapping and would not be expected to have an economically attractive return. Currently, we are working instead on improving our efficiency, primarily through new technologies to automate our networks as well as in increasing our quality of service to enhance the effectiveness of our facilities, profitability of our business and increase our capacity to satisfy our growing number of customers and their increasing demands.

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. Tariffs for residential, commercial and industrial customers changed, but the changes offset each other, and Enel Distribution’s revenues remained stable. In September 2018, there was an extraordinary and non-retroactive tariff update process that will be effective until the next tariff setting process. This tariff increase is to recognize the necessary investments to comply with the new requirements on the quality of service standards. Tariff reviews seek to capture distribution efficiencies and economies of scale resulting from economic growth.

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c.Economic Conditions

Macroeconomic conditions, such as changes in employment levels, and inflation or deflation may have a significant effect on our operating results. Macroeconomic factors, such as the variation of the Chilean peso against the U.S. dollar, may impact our operating results, as well as our assets and liabilities, depending on the amounts denominated in U.S. dollars. For example, a devaluation of the Chilean peso against the U.S. dollar increases the cost of capital expenditure plans. For additional information, see “Item 3. Key Information — D. Risk Factors — Foreign exchange risks may adversely affect our results and the U.S. dollar value of dividends payable to ADS holders.” and “Item 3. Key Information — D. Risk Factors — Fluctuations in the Chilean economy, economic interventionist measures by governmental authorities, political and financial events, or other crises in Chile and worldwide may affect our results of operations, financial condition, liquidity, and the value of our securities.”

The following table sets forth the closing and average Chilean pesos per U.S. dollar exchange rates for the years indicated:

	Local Currency U.S. Dollar Exchange Rates
	2019		2018		2017
	Average	Year End	Average	Year End	Average	Year End
Chilean pesos per U.S. dollar	702.63	748.74	640.29	694.77	649.33	614.75

Source: Central Bank of Chile

d.Critical Accounting Policies

Critical accounting policies are defined as those that reflect significant judgments and uncertainties that would potentially result in materially different results under different assumptions and conditions. We believe that our most critical accounting policies regarding the preparation of our consolidated financial statements under IFRS are those described below.

For further detail of the accounting policies and the methods used in the preparation of the consolidated financial statements, see Notes 2 and 3 of the Notes to our consolidated financial statements.

Impairment of Non-Financial Assets

From time to time, and principally at the end of each fiscal year, we evaluate whether there is any indication that an asset has been impaired. Should any such evidence exist, we estimate the recoverable amount of that asset to determine the amount of the impairment loss. In the case of identifiable assets that do not generate cash flows independently, we estimate the recoverability of the cash-generating unit to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

Notwithstanding the preceding paragraph, in the case of cash-generating units to which goodwill or intangible assets with an indefinite useful life have been allocated, a recoverability analysis is performed routinely at each period end.

The criteria used to identify the cash-generating units is in line with the strategic and operational vision of our management, within the specific characteristics of the business, the operating rules and regulations of the market in which we operate, and the corporate organization.

The recoverable amount is the greater of (i) the fair value less the cost needed to sell and (ii) the value in use, which is defined as the present value of the estimated future cash flows. To calculate the recoverable value of property, plant and equipment, goodwill and intangible assets that form part of a cash-generating unit, we use “value in use” criteria in practically all cases.

To estimate the value in use, we prepare future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of cash-generating units’, revenues and costs using sector projections, past experience, and future expectations.

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In general, these projections cover the next five years, estimating cash flows for future years and applying reasonable growth rates, which in no case are increasing nor exceed the average long-term growth rates for the Chilean electricity sector in which we operate. At the end of December 2019, projected cash flows were extrapolated using an annual growth rate of between 2.0 and 3.0%.

These future cash flows are discounted at a given pre-tax rate to calculate their present value. This rate reflects the cost of capital of the business in Chile. The discount rate is calculated by taking into account the current time value of money and the risk premiums generally used by market analysts for the specific business activity.

The pre-tax nominal discount rates applied in 2019, 2018 and 2017 are as follows:

Year ended December 31,
2019		2018		2017
Minimum	Maximum	Minimum	Maximum	Minimum	Maximum
7.7%	10.7%	6.9%	11.0%	7.5%	10.7%

If the recoverable amount of the cash-generating unit is less than the net carrying amount of the asset, the corresponding impairment loss provision is recognized for the difference and charged to “Reversal of impairment losses (impairment losses) recognized on non-financial assets” in the consolidated statement of comprehensive income.

Impairment losses recognized for an asset other than goodwill in prior periods are reversed when its estimated recoverable amount changes, increasing the asset’s value with a credit to earnings, limited to the asset’s carrying amount if no impairment loss had been recognized for the asset. Impairment losses for goodwill are not reversible.

Litigation and Contingencies

We are currently involved in legal and tax proceedings. As discussed in Note 25 of the Notes to our consolidated financial statements, we recognized provisions for legal and tax proceedings in an aggregate amount of Ch$ 13.5 billion as of December 31, 2019. This amount was based on consultations with our legal and tax advisors, who are carrying out our defense in these matters and an analysis of potential results, assuming a combination of litigation and settlement strategies.

Hedges of Cash Revenues Directly Linked to the U.S. Dollar

We have established a policy to hedge the portion of our revenues directly linked to the U.S. dollar by obtaining financing in U.S. dollars. Exchange differences related to this debt, as they are cash flow hedge transactions, are charged net of taxes to an equity reserve account that forms part of “Other Comprehensive Income” and recorded as income during the period in which the hedged cash flows are realized. This term has been estimated at ten years.

This policy reflects a detailed analysis of our future revenues directly linked to the U.S. dollar, to confirm that hedge accounting is applicable. Such analysis may change in the future due to new electricity regulations limiting the cash flows tied to the U.S. dollar.

Pension and Post-Employment Benefit Liabilities

We have various defined benefit plans for our employees. These plans pay benefits to employees at retirement and use formulas based on years of service and employee compensations. We also offer certain additional benefits for some specific retired employees.

The liabilities shown for the pensions and post-employment benefits reflect our best estimate of the future cost of meeting our obligations under these plans. The accounting applied to these defined benefit plans involves actuarial calculations, which contain key assumptions that include employee turnover, life expectancy, retirement age, discount rates, the future level of employee compensations and benefits, the claims rate under medical plans, and future medical

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costs. These assumptions change as economic and market conditions vary, and any change in any of these assumptions could have a material effect on the reported results from operations.

The effect of an increase of 100 basis points in the discount rate used to determine the present value of the post-employment defined benefits would decrease the liability by Ch$ 5.3 billion as of December 31, 2019, and the effect of a decrease of 100 basis points in the rate used to determine the present value of the post-employment defined benefits would increase the liability by Ch$ 5.8 billion as of December 31, 2019.

Revenue and expense recognition

Revenue is recognized when the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which it is expected to be entitled to upon the transfer of control, excluding the amounts collected on behalf of third parties.

We analyze and take into consideration all relevant facts and circumstances for revenue recognition, applying the five-step model established by IFRS 15: 1) identifying the contract with a customer; 2) identifying the performance obligations; 3) determining the transaction price; 4) allocating the transaction price; and 5) recognizing revenue.

The following are the criteria for revenue recognition by type of good or service that we provide:

(i) Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer several different goods or services that are substantially the same and that have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits that we provide, it is considered a performance obligation met over time. In these cases, we apply an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

a. Generation: Revenue is recognized according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices stipulated in the electricity market by the current regulations, or at the marginal cost of energy and power, depending on whether unregulated customers, regulated customers or energy trading in the spot market are involved, respectively.

b. Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

The above revenue includes an estimate of the service provided and not invoiced at the balance sheet date (See Notes 2.3, 28 and Appendix 2.2 of our consolidated financial statements).

(ii) Sale and transportation of gas: Revenue is recognized over time, based on the actual physical deliveries of gas in the period of consumption, at the prices established in the respective contracts.

(iii) Other services: Mainly the provision of supplementary services to the electricity business, construction of works and engineering, and consulting services. Customers control committed assets as they are created or improved. Therefore, we recognize this revenue over time,  based on the progress, measuring progress through output methods (performance completed to date, milestones reached, etc.), or resource methods (resources consumed, hours of labor spent, etc.), as appropriate in each case.

(iv) Sale of goods: Revenue from the sale of goods is recognized at a particular time, when control of the goods has been transferred to the client, which generally occurs at the time of the physical delivery of the goods. Revenues are measured at the independent sale price of each good, and any type of appropriate variable compensation.

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligations of the transaction, based on the control transfer pattern of each good or

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service that is separate and an independent selling price allocated to each of them, or two or more transactions jointly, when these are linked to contracts with customers that are negotiated with a single commercial purpose and the goods and services committed represent a single performance obligation, and their selling prices are not independent.

We determine the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable, and reflecting the effects of the time value of money. However, we apply the practical solution provided by IFRS 15. It will not adjust the amount of the consideration committed for a significant financing component, if we expect, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.

We exclude the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue figure. We only record as revenue the payment or commission to which we expect to be entitled.

Given that we mainly recognize revenue for the amount to which it has the right to invoice, it has decided to apply the practical disclosure solution provided in IFRS 15, through which it is not required to disclose the aggregate amount of the transaction price allocated to the obligations of performance not met (or partially not met) at the end of the reporting period.

Also, we evaluate the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset if their recovery is expected with the transfer of the related goods or services, and amortized in a manner consistent with the transfer of the related goods or services. The incremental costs of obtaining a contract are expensed if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses at the time they are incurred unless they are explicitly attributable to the customer.

As of December 31, 2019, and 2018, we had not incurred costs to obtain or fulfill a contract that met the conditions for such capitalization. The expenses incurred to gain a contract are substantially commission payments for sales that, even though they are incremental costs, are related to short-term contracts or performance obligations that are met at a certain point; therefore, we would recognize these costs as an expense if these occurred.

Interest revenue (expenses) are recorded considering the effective interest rate applicable to the principal with pending amortization during the corresponding accrual period.

Impairment of financial assets

Under IFRS 9 Financial Instruments,  we apply an impairment model based on expected credit losses, based on our history, existing market conditions, and prospective estimates at the end of each reporting period. The new impairment model is applied to financial assets measured at amortized cost and those measured at fair value through other comprehensive income, except for investments in equity instruments.

The expected credit loss, determined considering Probability of Default (PD), Loss Given Default (LGD) and Exposure at Default (EAD), is the difference between all cash flows that are owed under the contract and all the cash flows that are expected to be received (that is, all cash deficiencies), discounted at the original effective interest rate.

To determine the expected credit losses we apply two separate approaches:

· General approach: Applied to financial assets other than trade accounts receivable, contractual assets or lease receivables. This approach is based on the evaluation of significant increases in the credit risk of financial assets, from the date of initial recognition. If on the date of issuance of the financial statements the credit risk has not increased significantly, the impairment losses are measured by reference to the expected credit losses in the next 12 months. If, on the other hand, the credit risk has increased significantly, the impairment is measured considering the expected credit losses for the lifetime of the

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asset. In general, the measurement of expected credit losses under the general approach is performed on an individual basis.

· Simplified approach: Applied to trade receivables, contract assets and lease receivables. The impairment provision is always recognized by reference to the expected credit losses for the lifetime of the asset. This is our most commonly applied approach since trade receivables represent the main financial asset of Enel Chile and our subsidiaries.

For trade accounts receivable, contractual assets and accounts receivable for lease, we apply two types of evaluations of expected credit losses:

· Collective evaluation: Based on grouping accounts receivable into specific groups or “clusters”, taking into account each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of client portfolios in terms of credit risk, maturity information and recovery rates. A specific definition of default is considered for each group.

· Analytical or individual evaluation: If accounts receivable are considered individually significant by management, and there is specific information on any significant increase in credit risk, we apply an individual evaluation of accounts receivable. For the individual evaluation, the PD is obtained mainly from an external provider.

On the basis of the reference market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for such accounts receivable, we mainly apply a default definition of 180 days after maturity to determine the expected credit losses, since this is considered an effective indicator of a significant increase in credit risk. Consequently, financial assets that are more than 90 days are generally not considered in default.

To measure the expected credit losses collectively, we consider the following assumptions:

· PD: average default estimate, calculated for each group of trade accounts receivable, taking into account a minimum of 24-month historical data.

· LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and

· EAD: accounting exposure on the date of the financial report, net of cash deposits, including invoices issued, but not due and invoices to be issued.

Based on specific evaluations of management, the prospective adjustment can be applied considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios, which may affect the risk of the portfolio or the financial instrument.

Recent Accounting Pronouncements

Please see Note 2.2 of the Notes to our consolidated financial statements for additional information regarding recent accounting pronouncements.

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2.Analysis of Results of Operations for the Years Ended December 31, 2019 and 2018

Consolidated Revenues and other operating income

The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 2019 and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,726,612	1,580,653	145,959	9.2
Distribution Business
Enel Distribution and subsidiaries	1,412,872	1,263,224	149,648	11.8
Non-electricity business and consolidation adjustments	(368,650)	(386,716)	18,066	(4.7)
Total Revenues	2,770,834	2,457,161	313,673	12.8

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business increased Ch$ 146 billion in 2019 compared to 2018, explained by:

(i) an increase of Ch$ 105 billion in other operating income, mainly due to:

(a) an increase of Ch$ 121.1 billion in non-recurring income from the early termination of three energy supply contracts with Anglo American Sur, offset by

(b) a decrease of Ch$ 16.5 billion in revenues due to the non-recurring income from insurance compensation for claims related to incidents at Tarapacá received in 2018.

(ii) an increase of Ch$ 46.6 billion in revenues from electricity sales, mainly attributable to:

(a) an increase of Ch$ 183.3 billion in sales due to a higher average sales price in Chilean pesos as a result of a higher average exchange rate for the period, offset by a decrease of Ch$ 92.2 billion due to a decline of 855 GWh in physical sales (2,933 GWh less to regulated customers and 275 GWh less in spot market sales, partially compensated by 2,353 GWh more to non-regulated customers). The lower physical sales to the regulated customers are due to the migration of customers from the regulated to a non-regulated market, together with a strong contraction in demand in October and November 2019 explained by the social crisis in Chile. In the case of spot market sales, the reduction is primarily due to lower hydrological generation of our plants;

(b) a decrease of Ch$ 40.8 billion in revenues from exchange rate hedging derivatives; and

(c) a decrease of Ch$ 7.5 billion in revenues from commodities hedging, such as coal and Brent oil; and

(iii) a decrease of Ch$ 5.9 billion in other sales mainly due to a reduction of Ch$ 6.1 billion in gas sales.

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Distribution Business: Revenues and other operating income

Revenues and other operating income from our distribution business increased Ch$ 150 billion in 2019 compared to 2018, primarily due to:

(i) An increase of Ch$ 114.5 billion in sales due to a higher average sale price in Chilean pesos as a result of a higher exchange rate for the period;

(ii) an increase of Ch$ 22.6 billion due to higher physical sales of 325 GWh; and

(iii) an increase of Ch$ 11.1 billion due to the positive effect on the tariff that originated from the application of the technical standard of quality of service for distribution systems, which was established by the CNE in a resolution promulgated on December 2017.

The number of customers rose by 47,229 in 2019 to a total of 1,972,216. The increase in customers was mainly in the residential segment.

Consolidated Operating Costs

Our operating costs are primarily energy purchases from third parties, fuel consumption, and tolls paid to transmission companies, depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses.

The following two tables set forth the consolidated operating costs (excluding depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses, which are discussed below under Consolidated Selling and Administrative Expenses) for the years ended December 31, 2019, and 2018, by category and by business segment.

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Energy purchases	835,285	747,647	87,638	11.7
Fuel consumption	230,944	231,028	(84)	—
Transmission costs	196,849	166,876	29,973	18.0
Other variable procurement and services	158,127	146,627	11,501	7.8
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,421,205	1,292,177	129,028	10.0

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	678,188	709,506	(31,318)	(4.4)
Distribution Business
Enel Distribution and subsidiaries	1,114,936	972,500	142,436	14.6
Non-electricity business and consolidation adjustments	(371,919)	(389,829)	17,910	(4.6)
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,421,205	1,292,177	129,028	10.0

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Generation Business: Operating Costs

Operating costs of our generation business decreased Ch$ 31 billion in 2019 compared to 2018, mainly due to:

(i) a decrease of Ch$ 53 billion in energy purchases, equivalent to a reduction of 24.9% compared to 2018, partly explained by a decline of 1,850 GWh in physical energy purchases (1,216 GWh in spot market purchases and 634 GWh in contracted energy purchases), explained by the higher availability of our power plants and a decrease in physical sales. This lower cost includes the positive effect of the consolidation of EGP Chile with Enel Chile, which led to a net Ch$ 60.2 billion decrease in Enel Chile’s cost of energy purchases due to the elimination of related-party transactions (sales between EGP Chile and Enel Generation).

(ii) Fuel consumption costs remained unchanged in the aggregate, with higher coal costs completely offsetting lower fuel oil and gas costs:

(a) a decrease of Ch$ 7.8 billion in fuel oil consumption significantly related to the lower dispatch of the power plants that operate with fuel oil;

(b) a decrease of Ch$ 6 billion in gas consumption cost, mainly due to the lower price of gas as a result of an increase in the supply of gas from Argentina; and

(c) an increase of Ch$ 13.7 billion in coal consumption costs due to higher thermal dispatch as a consequence of the poorer hydrologic conditions in Chile in 2019.

(iii) an increase of Ch$ 15 billion in transportation costs, mainly due to:

(a) an increase of Ch$ 14.7 billion in gas transportation costs;

(b) an increase of Ch$ 0.7 billion in regasification costs related to higher gas fueled electricity generation; and

(c) a decrease of Ch$ 0.5 billion in toll expenses.

(iv) An increase of Ch$ 6.8 billion in other variable procurement and services costs, mainly due to:

(a) an increase of Ch$ 10.5 billion in thermal emissions tax cost;

(b) an increase of Ch$ 1.7 billion in other various electricity generation supply costs (such as water, chemicals, etc.); and

(c) a decrease of Ch$ 5.5 billion in costs of sales in the gas commercialization business.

Distribution Business: Operating Costs

Operating costs of our distribution business increased Ch$ 142 billion in 2019 compared to 2018, mainly due to:

(i) an increase of Ch$ 109.4 billion due to a higher average purchase price;

(ii) an increase of 397 GWh in physical purchases required to satisfy demand, equivalent to Ch$ 20.8 billion;

(iii) an increase of Ch$ 12.9 billion due to higher transportation costs; and

(iv) a decrease of Ch$ 0.6 billion in other variable procurement and services.

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Consolidated Selling and Administrative Expenses

Our selling and administrative expenses are salaries and other compensation expenses, depreciation, amortization and impairment losses, and office materials and supplies.

The following two tables set forth our selling and administrative expenses for the years ended December 31, 2019, and 2018, by category and by business segment:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Depreciation, amortization and impairment losses	527,437	220,750	306,687	138.9
Other fixed costs	184,143	167,211	16,932	10.1
Employee benefit expenses and others	111,994	106,419	5,575	5.2
Total Consolidated Selling and Administrative Expenses	823,574	494,380	329,194	66.6

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	652,489	337,527	314,962	93.3
Distribution Business
Enel Distribution and subsidiaries	145,642	131,465	14,177	10.8
Non-electricity business and consolidation adjustments	25,443	25,388	55	0.2
Total Consolidated Selling and Administrative Expenses	823,574	494,380	329,194	66.6

Consolidated selling and administrative expenses increased Ch$ 329 billion in 2019 compared to 2018, mainly due to an increase in the generation business, explained by:

(i) the impairment expense associated with the Tarapacá and Bocamina I coal-fired generating units of Ch$ 197.2 billion and Ch$ 82.8 billion, respectively, as a result of their announced closures as part of our decarbonization process, and higher depreciation contributed by EGP Chile of Ch$ 27 billion;

(ii) an increase of Ch$ 8.9 billion  in costs of maintenance and repair services in the generation segment, an increase of Ch$ 3.8 billion in maintenance costs associated with the technical distribution standard, and an increase of Ch$ 3.5 billion in disposals and removals from service in property, plant, and equipment; and

(iii) an increase in employee benefit expenses corresponding to (i) an increase of Ch$ 3.1 billion in personnel expense, mainly due to higher staffing and the effect of the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018; and (ii) a decrease of Ch$ 2.1 billion in the capitalization of personnel cost. 

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Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2019, and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	395,935	533,620	(137,685)	(25.8)
Distribution Business
Enel Distribution and subsidiaries	152,294	159,259	(6,966)	(4.4)
Non-electricity business and consolidation adjustments	(22,174)	(22,274)	101	(0.5)
Total Consolidated Operating Income	526,055	670,605	(144,550)	(21.6)
Operating margin (1)	19.0%	27.3%	—	—

(1) Operating margin, a measure of efficiency, represents operating income as a percentage of revenues. However, caution must be applied in making comparisons among periods, which may have experienced non-recurring gains or losses, as was the case in 2019 with the expense related to the closure of two coal-fired power plants.

Our operating income in 2019 decreased compared to 2018 due to:

Generation Business 

Operating income was affected by the non-recurring loss generated from the impairment related to the announcement of the closure of the Tarapacá and Bocamina I coal-fired power plants, partially offset by the non-recurring income generated by the early termination of three energy supply contracts with Anglo American Sur.

On the other hand, during 2019, hydrological conditions were one of the driest in the last 10 years in Chile, causing a decrease in the generation of electricity from hydroelectric plants. As a result, we increased thermal generation, which increased our operating costs.

The commissioning of new NCRE plants and the interconnection between the central and northern interconnected systems helped to reduce the impact of the change in our energy matrix and stabilize the marginal operating costs in 2019 compared to 2018. As a result, we were able to cover our energy deficit in the spot market at lower prices. This energy deficit decreased mainly due to i) greater generation from our thermal plants, and ii) increased availability of Argentine natural gas for our combined cycles.

Although our physical sales decreased in 2019, they were sold at higher average sales prices expressed in Chilean peso due to a higher average exchange rate, which was partially offset by lower revenues as a result of the migration of customers from the regulated market to the non-regulated market.

Distribution Business

Operating costs increased due to a higher average energy purchase price, higher physical purchases, and, to a lesser degree, higher operation and maintenance costs, depreciation of fixed assets and amortization of intangible assets due to higher transfers of constructions in progress to assets in operation. As a result, our distribution business operating income decreased in 2019.

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Consolidated Financial and Other Results

The following table sets forth our financial and other results for the years ended December 31, 2019, and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Financial results
Financial income	27,399	19,934	7,465	37.5
Financial costs	(164,898)	(122,184)	(42,714)	35.0
Gain (loss) from indexed assets and liabilities	(2,982)	(818)	(2,164)	264.5
Foreign currency exchange differences	(10,412)	(7,807)	(2,605)	33.4
Total financial results	(150,893)	(110,875)	(40,018)	36.1
Other Results
Share of the profit (loss) of associates and joint ventures accounted for using the equity method	366	3,190	(2,824)	(88.5)
Gain (loss) from sales of assets	1,793	3,411	(1,618)	(47.4)
Total Other results	2,159	6,601	(4,442)	(67.3)
Total Consolidated Financial and Other Results	(148,734)	(104,274)	(44,460)	42.6

Financial Results

We recorded a higher net financial expense for 2019, compared to 2018, primarily attributable to:

(i) financial costs increased Ch$ 42.7 billion, mainly due to:

(a) an increase of Ch$ 19 billion in expenses related to the Tariff Stabilization Law;

(b) an increase of Ch$ 14.8 billion in financial expenses due to the consolidation of EGP Chile for a full year in 2019 compared to nine months in 2018;

(c) an increase of Ch$ 11.9 billion in interest on bank loans related to our corporate reorganization carried out in 2018;

(d) an increase of Ch$ 1.8 billion in financial expenses due to factoring operations; and

(e) a decrease of Ch$ 4.9 billion in financial expenses due to the loan renegotiation between EGP del Sur and Enel Finance International.

(ii) an increase of Ch$ 7.5 billion in financial income, mainly due to:

(a) an increase of Ch$ 5.2 billion in interest income related to the application of the Tariff Stabilization Law;

(b) an increase of Ch$ 5.3 billion in interest income related to regulated customer accounts receivables to be billed before to the application of the Tariff Stabilization Law; and

(c) a decrease of Ch$ 2.4 billion in interest income on short-term fixed income investments, and Ch$ 0.2 billion in lower interest income from refinancing to customers.

(iii) an increase of Ch$ 2.2 billion in losses related to indexation primarily due to:

(a) a increase of Ch$ 1.6 billion in losses due to a negative impact of IAS 29 “Financial Reporting in Hyperinflationary Economies” on the branch of the Enel Generación Group located in Argentina;

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(b) a decrease of Ch$ 0.8 billion in income from recoverable taxes;

(c) a decrease of Ch$ 0.5 billion in income from hedging derivative contracts; partially offset by

(d) a decrease of Ch$ 0.7 billion in losses as a result of indexation of financial liabilities recorded in U.F.

(iv) a decrease of Ch$ 2.6 billion in income from exchange rate differences, mainly due to negative exchange rate arising from:

(a) a decrease of Ch$ 6.4 billion in forward contracts; and

(b) a decrease of Ch$ 0.5 billion in cash and cash equivalents; partially offset by

(c) the positive effects of (i) an increase of Ch$ 3 billion in trade accounts payable, and (ii) an increase of Ch$ 1.1 billion in trade accounts receivable, including an increase of Ch$ 3.8 billion due to the Tariff Stabilization Law that dollarized the regulated customer accounts receivable whose bills are outstanding.

Other Results

Our gain from disposition of assets decreased in 2019 compared to 2018, primarily due to a decrease of Ch$ 1.7 billion in sales of Enel Generation to third parties.

We also registered a decrease of Ch$ 2.8 billion in the share of the profit (loss) of associates and joint ventures accounted for using the equity method in 2019 when compared to 2018, mainly due to lower results compared to 2018 from (i) HidroAysén, which was liquidated in 2018, amounting to Ch$ 1.7 billion, and (ii) GNL Chile S.A. of Ch$ 1.1 billion.

Consolidated Income Tax Expenses

The effective tax rate decreased to 16.2% in 2019 compared to 27.1% in 2018.

Consolidated income tax expenses decrease of Ch$ 92.2 billion in 2019 compared to 2018. This decrease is mainly due to:

(i) a decrease of Ch$ 75.6 billion in tax expense as a result of the impairment of Bocamina I and Tarapacá coal-fired power plants in relation to their announced closures as part of the decarbonization process;

(ii) a decrease of Ch $ 29.3 billion, arising from the absorption of GasAtacama Argentina by GasAtacama Chile;

(iii) a decrease of Ch$ 8.1 billion in income tax expense associated with lower results;

(iv) a decrease of Ch$ 6.3 billion in expense corresponding to non-refundable credits attributed to tax losses in 2018;

(v) a decrease of Ch$ 5.1 billion in income tax expense for Enel Chile due to a loss incurred on the sale of its interest in GasAtacama Chile to Enel Generation; and

(vi) an increase of Ch$ 32.7 billion in income tax expense for the non-recurring revenues generated by the early termination of three energy supply contracts with Anglo American Sur.

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For further details, please refer to Note 20 of the Notes to our consolidated financial statements.

Consolidated Net Income

The following table sets forth our consolidated net income before taxes, income tax expenses and net income for the years ended December 31, 2019 and 2018:

	Years ended December 31,
	2019	2018	Change	Change
	(in millions of Ch$)			(in %)
Operating income	526,055	670,605	(144,550)	(21.6)
Other results	(148,734)	(104,274)	(44,460)	42.6
Net income before taxes	377,321	566,331	(189,010)	(33.4)
Income tax expenses	(61,228)	(153,483)	92,255	(60.1)
Consolidated Net income	316,093	412,848	(96,755)	(23.4)
Net income attributable to the Parent Company	296,154	361,710	(65,556)	(18.1)
Net income attributable to non-controlling interests	19,939	51,138	(31,199)	(61.0)

The decrease in net income attributable to non-controlling interests in 2019 compared to 2018 of Ch$ 31.2 billion is primarily due to the decrease in the percentage of minority shareholders of Enel Generation corresponding to Enel Chile’s increased economic interest in Enel Generation after the completion of the 2018 Reorganization.

3. Analysis of Results of Operations for the Years Ended December 31, 2018 and 2017

Consolidated Revenues and other operating income

The following table sets forth our revenues and other operating income by reportable segment for the years ended December 31, 2018, and 2017:

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	1,580,653	1,634,937	(54,284)	(3.3)
Distribution Business
Enel Distribution and subsidiaries	1,263,224	1,326,659	(63,435)	(4.8)
Non-electricity business and consolidation adjustments	(386,716)	(438,618)	51,902	(11.8)
Total Revenues and other operating income	2,457,161	2,522,978	(65,817)	(2.6)

Generation Business: Revenues and other operating income

Revenues and other operating income from our generation business (which include EGP Chile revenues of Ch$ 49.7 billion for the nine-month period ended December 31, 2018) decreased in 2018 compared to 2017, primarily explained by:

(i)a decrease of Ch$ 31.7 billion in revenues from energy sales, which was primarily attributable to:

a.a decrease of Ch$ 29.1 billion in capacity payments;

b.a decrease of Ch$ 21.9 billion in revenues as a result of settlements performed by the CEN associated with price and quantity adjustments registered in 2017;

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c.a decrease of Ch$ 11 billion associated with a lower average energy sales price in Chilean pesos due to the lower average exchange rate of the period; and

d.an increase of Ch$ 32.9 billion in physical sales as a result of an 8% decrease in sales to regulated customers; and

(ii)a decrease of Ch$ 35.4 billion in toll revenues.

These were partially offset by an increase of Ch$ 9.3 billion in commodity sales, mainly an increase of Ch$ 12.1 billion in gas sales, offset by a decrease of Ch$ 2.8 billion in coal sales.

Distribution Business: Revenues and other operating income

Revenues and other operating income from our distribution business decreased in 2018 compared to 2017, primarily due to:

(i)a decrease of Ch$ 60.9 billion in other services revenues, namely lower revenues from transmission tolls as a result of the new zonal transmission decree;

(ii)a decrease of Ch$ 10.3 billion in energy sales revenues mainly due to a decrease of Ch$ 33.7 billion due to lower average sales prices resulting from the transfer of lower purchase prices;

(iii)an increase of 345 GWh in physical sales equivalent to Ch$ 23.4 billion; and

(iv)an increase of Ch$ 4 billion in products and services sales.

The number of customers increased by 42,590 in 2018 compared to 2017, amounting to 1,924,984. The increase in customers was mainly in the residential segment.

Consolidated Operating Costs

Our operating costs are primarily energy purchases from third parties, fuel purchases, and tolls paid to transmission companies, depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses.

The following two tables set forth the consolidated operating costs (excluding depreciation, amortization and impairment losses, maintenance costs, employee salaries, and administrative and selling expenses, which are explained below under Consolidated Selling and Administrative Expenses)for the years ended December 31, 2018, and 2017, by category and by business segment.

	Years ended December 31,
	2018	2017	Change		Change
	(in millions of Ch$)			(in %)
Energy purchases	747,647	902,435	(154,788)		(17.2)
Fuel consumption	231,028	280,739	(49,711)		(17.7)
Transmission costs	166,876	155,879	10,997		7.1
Other variable procurement and services	146,627	175,733	(29,107)		(16.6)
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,292,177	1,514,787	(222,610)		(14.7)

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	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	709,506	903,978	(194,472)	(21.5)
Distribution Business
Enel Distribution and subsidiaries	972,500	1,055,708	(83,208)	(7.9)
Non-electricity business and consolidation adjustments	(389,829)	(444,899)	55,070	(12.4)
Total Consolidated Operating Costs (excluding Selling and Administrative Expenses)	1,292,177	1,514,787	(222,610)	(14.7)

Generation Business: Operating Costs

Operating costs of our generation business decreased in 2018 compared to 2017, mainly due to: 

· a decrease of Ch$ 133.8 billion in the value of energy purchases primarily explained by a decrease of 1,960 GWh in physical energy purchases, as a result of a decrease of 2,733 GWh in contracted energy purchases that were partially compensated by an increase of 773 GWh in spot market purchases. This positive variation includes the consolidation effect of including EGP Chile in the consolidated group in 2018, which led to a net decrease of Ch$ 115.3 billion in our consolidated energy purchase costs due to the elimination of related-party transactions (sales of energy by EGP Chile to Enel Generation);

· a decrease of Ch$ 49.7 billion in fuel costs, primarily due to a decrease of Ch$ 30.5 billion in gas consumption, a decrease of Ch$ 9.2 billion in coal consumption, and a decrease of Ch$ 9.9 billion in fuel oil costs, primarily responding to the lower level of thermal dispatch; and

· a decrease of Ch$ 12.1 billion in other variable procurement and services costs, which in turn was mostly attributable to (i) a decrease of Ch$ 8.3 billion related to the lease agreement with Eléctrica Santiago S.A., an unrelated company, to use its Nueva Renca combined-cycle power plant, allowing us to use our available LNG; (ii) a decrease of Ch$ 3.7 billion in thermal emissions taxes; (iii) a decrease of Ch$ 1.7 billion in commodity derivative costs; and (iv) a decrease of Ch$ 1.1 billion in water consumption costs. These cost decreases were partly offset by an increase of Ch$ 4.8 billion in costs in the gas commercialization business.

Distribution Business: Operating Costs

Operating costs of our distribution business decreased in 2018 compared to 2017, mainly due to (i) a decrease of Ch$ 53.2 billion in transportation costs due to the new Zonal transmission decree; (ii) a decrease of Ch$ 11.7 billion in energy purchases mainly attributable to a decrease of Ch$ 30.3 billion due to lower average energy purchase prices, as a result of changes in node prices and lower surcharges homogenizing tariffs nationwide, offset by an increase of Ch$ 18.6 billion in physical purchases required to satisfy demand; and (iii) a decrease of Ch$ 18.3 billion in variable procurement and services costs, primarily for fines and compensations derived from extraordinary weather events that occurred in 2017, an insurance recovery in 2018, and other businesses such as meter rentals and street lighting services.

Consolidated Selling and Administrative Expenses

Our selling and administrative expenses are salaries, compensation, administrative expenses, depreciation, amortization and impairment losses, and office materials and supplies.

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The following tables set forth our consolidated selling and administrative expenses for the years ended December 31, 2018, and 2017, by category and by business segment:

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Depreciation, amortization and impairment losses	220,750	160,621	60,129	37.4
Other fixed costs	167,211	161,824	5,387	3.3
Employee benefit expense and others	106,419	107,115	(696)	(0.7)
Total Consolidated Selling and Administrative Expenses	494,380	429,560	64,820	15.1

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	337,527	267,099	70,428	26.4
Distribution Business
Enel Distribution and subsidiaries	131,465	138,441	(6,976)	(5.0)
Non-electricity business and consolidation adjustments	25,388	24,020	1,368	5.7
Total Consolidated Selling and Administrative Expenses	494,380	429,560	64,820	15.1

Consolidated selling and administrative expenses from continuing operations increased in 2018 compared to 2017, mainly due to an increase in the generation business, from the inclusion of the depreciation expense of EGP Chile that amounted to Ch$ 62.1 billion.

Selling and administrative expenses in our distribution business decreased in 2018 compared to 2017, primarily due to the non-recurrence of Ch$ 5.9 billion in payroll expenses associated with extraordinary employee bonuses given to employees during 2017.

Consolidated Operating Income

The following table sets forth our operating income by reportable segment for the years ended December 31, 2018, and 2017:

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Generation Business
Enel Generation, EGP Chile, and subsidiaries	533,620	463,860	69,760	15.0
Distribution Business
Enel Distribution and subsidiaries	159,259	132,510	26,749	20.2
Non-electricity business and consolidation adjustments	(22,274)	(17,740)	(4,535)	25.6
Total Consolidated Operating Income	670,605	578,631	91,974	15.9
Operating margin(1)	27.3%	22.9%	—	—

(1) Operating margin, a measure of efficiency, represents operating income as a percentage of revenues.

Our operating income in 2018 increased slightly compared to 2017 primarily due to the combination of:

· Hydrological conditions in Chile have been below the historical average since 2010. However, in 2018 hydrological conditions were more humid than in 2017. This allowed us to produce more electricity through hydroelectric generation rather than through thermal generation, which is more expensive. In addition, the commissioning of new NCRE plants reduced the impact of dry conditions and the interconnection between

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the SIC and SING also helped to reduce or stabilize marginal costs. Therefore, the marginal cost of electricity generation decreased in 2018 when compared to 2017 notwithstanding higher prices for our fuels. As a result, we were able to cover our energy deficit in the spot market at lower prices. While our physical sales increased when compared to 2017, they were at lower average sales prices, and our customer mix changed because during 2018 a portion of our regulated customers chose the unregulated tariff regime instead, all of which led to a decrease of our consolidated revenues. However, due to the incorporation of EGP Chile, our operating costs (mainly energy purchases) considerably decreased in 2018, which compensated the lower revenues and the increase in our selling and administrative expenses, also due to the inclusion of EGP Chile.

· In the distribution business, although our revenues decreased in 2018 when compared to 2017, our operating costs also significantly decreased when compared to 2017, due primarily to the weather emergencies we faced in 2017, and to a lesser degree, lower selling and administrative expenses. As a result, our distribution business operating income increased in 2018.

Consolidated Financial and Other Results

The following table sets forth our financial and other results for the years ended December 31, 2018 and 2017:

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Financial results
Financial income	19,934	21,663	(1,729)	(8.0)
Financial costs	(122,184)	(53,511)	(68,673)	128.3
Gain (loss) from indexed assets and liabilities	(818)	916	(1,734)	(189.3)
Foreign currency exchange differences	(7,807)	8,517	(16,324)	(191.7)
Total financial results	(110,875)	(22,415)	(88,460)	394.6
Other Results
Share of the profit (loss) of associates and joint ventures accounted for using the equity method	3,190	(2,697)	5,887	(218.3)
Gain (loss) from sales of assets	3,411	113,241	(109,830)	(97.0)
Total Other results	6,601	110,544	(103,943)	(94.0)
Total Consolidated Financial and Other Results	(104,274)	88,129	(192,403)	(218.3)

Financial Results

We recorded a higher net financial expense for the year ended December 31, 2018 compared to 2017. This is primarily attributable to: (i) higher financial costs mainly due to an increase of Ch$ 37 billion in interest on bank loans and bonds mainly related to our new debt to finance the 2018 Reorganization, plus an increase of Ch$ 31.7 billion in interest expense related to the consolidation of EGP Chile; (ii) higher losses from foreign currency exchange differences, mainly as a result of an increase of Ch$ 5.4 billion in negative exchange differences on forward contracts, Ch$ 4.2 billion on supplier accounts, and Ch$ 3.3 billion on cash and cash equivalents; and (iii) a decrease of Ch$ 1.7 billion in financial income due to a decrease of Ch$ 2.4 billion in income related to customer refinancing offset by an increase of Ch$ 0.7 billion in income from short-term fixed income investments.

Other Results

Our gain from disposition of assets decreased in 2018 compared to 2017, primarily explained by the sale of Electrogas in February 2017 for Ch$ 105.3 billion.

We also registered a higher share of the profit (loss) of associates and joint ventures accounted for using the equity method in 2018 when compared to 2017, mainly explained by better results from HidroAysén amounting to Ch$ 5.9 billion until its liquidation in 2018.

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Consolidated Income Tax Expenses

Consolidated income tax expenses amounted to Ch$ 153.5 billion in 2018, an increase of Ch$ 10.1 billion, or 7.1%, when compared to 2017.

The increase in consolidated income tax expenses was primarily due to an increase of the statutory corporate income tax rate from 25.5% in 2017 to 27% in 2018 leading to an increase of Ch$ 8.5 billion in taxes. As a result, the effective tax rate increased to 27.1% in 2018 compared to 21.5% in 2017. For further details, please refer to Note 20 of the Notes to our consolidated financial statements.

Consolidated Net Income

The following table sets forth our consolidated net income before taxes, income tax expenses and net income for the years ended December 31, 2018, and 2017:

	Years ended December 31,
	2018	2017	Change	Change
	(in millions of Ch$)			(in %)
Consolidated Operating income	670,605	578,631	91,974	15.9
Consolidated Other results	(104,274)	88,129	(192,403)	(218.3)
Consolidated Net income before taxes	566,331	666,760	(100,430)	(15.1)
Income tax expenses	(153,483)	(143,342)	(10,140)	7.1
Consolidated Net income	412,848	523,418	(110,570)	(21.1)
Net income attributable to the Parent Company	361,710	349,383	12,327	3.5
Net income attributable to non-controlling interests	51,138	174,035	(122,897)	(70.6)

The decrease in net income attributable to non-controlling interests in 2018 compared to 2017 is primarily due to a decrease of Ch$ 124.6 billion in net income attributable to the non-controlling interests of Enel Generation for 2018, which in turn is mainly due to the decrease of percentage of minority shareholders of Enel Generation as a result of the increase in our controlling and economic interest in Enel Generation after the completion of the 2018 Reorganization.

B.Liquidity and Capital Resources.

Our main assets are our consolidated Chilean subsidiaries, Enel Generation, EGP Chile, and Enel Distribution. The following discussion of cash sources and uses reflects the key drivers of our cash flow.

We receive cash inflows from our subsidiaries and related companies. Our subsidiaries’ and associates’ cash flows may not always be available to satisfy our own liquidity needs because there may be a time lag before we have effective access to those funds through dividends or capital reductions. However, we believe that cash flow generated from our business operations, as well as cash balances, borrowings from commercial banks, short- and long-term intercompany loans, and ample access to the capital markets will be sufficient to satisfy all our needs for working capital, expected debt service, dividends, and planned capital expenditures in the foreseeable future.

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Set forth below is a summary of our consolidated cash flow information for the years ended December 31, 2019, 2018, and 2017:

	Year ended December 31,
	2019	2018	2017
	(in billions of Ch$)
Net cash flows provided by operating activities	744	736	636
Net cash flows used in investing activities	(312)	(1,882)	(146)
Net cash flows provided by (used in) financing activities	(440)	967	(318)
Net increase (decrease) in cash and cash equivalents before effect of exchange rates changes	(8)	(179)	172
Effect of exchange rate changes on cash and cash equivalents	(1)	5	2
Cash and cash equivalents at beginning of period	245	419	246
Cash and cash equivalents at end of period	236	245	419

For the year ended December 31, 2019, net cash flow provided by operating activities increased 1.1% compared to the same period in 2018. The increase was in part the result of:

(i) a decrease of Ch$ 52 billion in income tax payments during 2019, explained by Enel Generation’s lower income tax payments due to lower monthly and annual tax payments of Ch$ 82.8 billion and an increase of Ch$ 17.9 billion in tax refunds, offset by (i) Ch$ 45 billion of higher income tax payments by GasAtacama Chile due to tax refunds received in 2018 from the recognition of tax losses in Celta and monthly tax payments and (ii) Ch$ 5 billion of higher monthly tax payments, by Enel Distribution.  

(ii) an increase of Ch$ 21 billion in collections from insurance claims mainly due to insurance policies for Tarapacá for Ch$ 12.5 billion and Los Cóndores for Ch$ 9.7 billion; and

(iii) an increase of Ch$ 16 billion in collections from the sale of goods and services, comprised mainly of:

a. an increase of Ch$ 7 billion in Enel Distribution, due to higher physical sales; and

b. an increase of Ch$ 6 billion in Enel X Chile, a new business line, mainly related to electric buses and energy-efficient consumer products. 

This was partially offset by:

(iv) an increase of Ch$ 17 billion in other payments for operating activities, due to higher VAT payments from EGP del Sur for new wind plants in operation since the second half of 2018;

(v) a decrease of Ch$ 22 billion in other collections from operating activities, due to the non-recurrence of a VAT refund in 2018, relating to the construction of the Cerro Pabellón project; and

(vi) an increase of Ch$ 40 billion in payments by Enel X Chile for electric buses to lease to third parties, and by Enel Distribution for the construction of public lighting to lease to local municipalities.  

For further information regarding our operating results in 2019 and 2018, please see “— A. Operating Results. — 2. Analysis of Results of Operations for the Years Ended December 31, 2019, and 2018.”

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For the year ended December 31, 2018, net cash flow provided by operating activities increased 15.7% compared to the same period in 2017. The increase was in part the result of lower payments as detailed below:

(i)a decrease of Ch$ 147 billion in payments to suppliers of goods and services mainly due to:

a.a decrease of Ch$ 107 billion in our cost of energy purchases as a consequence of the elimination of related-party transactions (sales of energy by EGP Chile to Enel Generation and Enel Distribution) due to the inclusion of EGP Chile in our consolidated group; and

b.a decrease of Ch$ 37 billion in fuel costs to Enel Generation.

(ii)a decrease of Ch$ 49 billion in income tax payments during 2018 primarily due to Ch$ 45 billion in tax refunds for recognition of tax losses in Celta and higher monthly payments made by GasAtacama Chile in 2017; and

(iii)a decrease of Ch$ 9 billion in payments to and on behalf of employees from operating activities, mainly in Enel Distribution, which registered higher payments in 2017 associated with retirement plans and union agreements.

This was partially offset by a decrease of Ch$ 109 million in collections from the sale of goods and services, comprised mainly of:

(i)a decrease of Ch$ 95 billion in collections from Enel Generation, on a stand-alone basis and excluding intercompany transactions, due to a lower average sales price and lower sales to regulated customers;

(ii)a decrease of Ch$ 41 billion in collections from GasAtacama Chile, excluding intercompany transactions, due to lower physical sales mainly in the spot market;

(iii)a decrease of Ch$ 39 billion in collections from Enel Distribution, excluding intercompany transactions, due to a reduction in billings from transmission tolls; and

(iv)an increase of Ch$ 57 billion in collections from EGP Chile, excluding intercompany transactions, as a result of its acquisition and consolidation for the nine-month period ended December 31, 2018.

For further information regarding our operating results in 2018 and 2017, please see “— A. Operating Results. — 2. Analysis of Results of Operations for the Years Ended December 31, 2018 and 2017.”

For the year ended December 31, 2019, net cash flows used in investing activities decreased 83% compared to the same period of 2018. The lower investment in 2019 was mainly due to the non-recurrence of the 2018 Reorganization completed on April 2, 2018, when we invested Ch$ 1,624 million related to our tender offer for our additional equity interest in Enel Generation, which was offset by net cash inflows in 2018 in net collection from related companies of Ch$38.4 billion.

For the year ended December 31, 2018, net cash flows used in investing activities increased 1,185% compared to the same period of 2017. The increase was mainly due to the 2018 Reorganization completed on April 2, 2018, with Ch$ 1,624 million related to the tender offer for Enel Generation and a decrease of Ch$ 116 billion in other collections from the sale of equity or debt instruments belonging to other entities related to the sale of Electrogas.

For further information regarding the 2018 Reorganization and the acquisition of fixed assets in 2017, please see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital Expenditures and Divestitures.”

For the year ended December 31, 2019, net cash flows used in financing activities amounted to Ch$440 billion compared to the cash flows provided by financing activities of Ch$967 in 2018, mainly to finance the 2018 Reorganization.

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The aggregate cash payments associated with financing activities in 2019 were primarily due to:

(i) Ch$ 315 billion in payments of loans and bonds (including Ch$ 214 billion by Enel Chile on a stand-alone basis related to the 2018 Reorganization, and Ch$ 70 billion by EGP Chile);

(ii) Ch$ 236 billion in dividend payments, of which Ch$ 134 billion was paid to Enel, our controlling shareholder; and

(iii) Ch$ 134 billion in interest payments (Ch$ 51 billion paid by Enel Generation, Ch$ 38 billion paid by EGP Chile and Ch$ 45 billion paid by Enel Chile).

These payments were partially offset by aggregate cash inflows from financing activities in 2019 primarily from a loan of Ch$ 284 billion provided to Enel Chile by Enel Finance International, a related company.

For the year ended December 31, 2018, net cash flows provided by financing activities increased 404% to Ch$ 967 billion in 2018 compared to net cash flows used in financing activities of Ch$ 318 billion in 2017, mainly to finance the 2018 Reorganization.

The aggregate cash inflows from financing activities in 2018 were primarily due to:

(i)Ch$ 625 billion in Yankee bonds issued by us;

(ii)Ch$ 940 billion in bank loans granted to us; and

(iii)Ch$ 666 billion in proceeds from the issuance of shares in connection with the tender offer and related capital increase made as part of the 2018 Reorganization.

The aggregate cash outflows from financing activities in 2018 were primarily due to:

(i)Ch$ 820 billion in payments of loans and bonds (including Ch$ 749 billion by Enel Chile on a stand-alone basis, related to the 2018 Reorganization and Ch$ 65 billion by EGP Chile);

(ii)Ch$ 231 billion in dividend payments, of which Ch$ 118 billion was paid to Enel, our controlling shareholder;

(iii)Ch$ 116 billion in interest expense (Ch$ 47 billion paid by Enel Generation, Ch$ 41 billion paid by EGP Chile and Ch$ 28 billion paid by Enel Chile); and

(iv)Ch$ 72 billion in payments to acquire treasury shares.

For a description of liquidity risks resulting from the inability of our subsidiaries to transfer funds, please see “Item 3. Key Information — D. Risk Factors — We depend on payments from our subsidiaries to meet our payment obligations.”

We coordinate the overall financing strategy of our subsidiaries. Our subsidiaries typically develop their capital expenditure plans and customarily finance their capital expansion programs through internally generated funds, intercompany financings or direct financings. In recent years, we have adopted a preference to incur debt at the parent company level in Enel Chile and to finance most of the obligations of our subsidiaries through intercompany loans.  Among the advantages to this new financing strategy is the mitigation of structural subordination risk arising from subsidiary debt, with its favorable consequences for us from the perspective of rating agency credit ratings.  Furthermore, we as a holding company can frequently access liquidity from several sources on better terms and conditions than some of our subsidiaries.  However, we have no legal obligations or other commitments to support such subsidiaries financially in all cases. For information regarding our commitments for capital expenditures, see “Item 4. Information on the Company — A. History and Development of the Company — Capital Investments, Capital

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Expenditures and Divestitures” and our contractual obligations table set forth below under “Item 5. Operating and Financial Review and Prospects — F. Tabular Disclosure of Contractual Obligations.”

As of December 31, 2019, our consolidated interest-bearing debt totaled Ch$ 2,661 billion (including Ch$ 782 billion in debt that EGP Chile and Enel Chile incurred with Enel Finance International N.V.) and had the following maturity profile:

Maturity profile of our consolidated interest-bearing debt
2020	2021-2022	2023-2024	After 2024
(in billions of Ch$)
164	506	490	1,501

We have American Depositary Shares listed and traded on the NYSE since April 26, 2016, and we may in the future access the international equity capital markets (including SEC-registered ADS offerings). Our subsidiary Enel Generation accessed the international equity capital markets, with an SEC-registered ADS offering on August 3, 1994, and we have also issued bonds in the United States (“Yankee Bonds”) in 2018 and may issue Yankee Bonds in the future depending on liquidity needs.

The following table lists the Yankee Bonds issued by us and the aggregate principal amount outstanding as of December 31, 2019

				Aggregate Principal Amount
Issuer	Term	Maturity	Coupon	Issued	Outstanding
				(in millions of US$)
Enel Chile	10 years	June 2028	4.875%	1,000	1,000

The following table lists the Yankee Bonds issued by our subsidiary, Enel Generation, and the aggregate principal amount outstanding as of December 31, 2019.  

					Aggregate Principal Amount
Issuer	Term	Maturity	Coupon		Issued	Outstanding
					(in millions of US$)
Enel Generation	10 years	April 2024	4.250%		400	400
Enel Generation (1)	30 years	February 2027	7.875%		230	206
Enel Generation (2)	40 years	February 2037	7.325%		220	71
Enel Generation (1)	100 years	February 2097	8.125%		200	40
Total			5.813%	(3)	1,050	717

(1)Enel Generation repurchased some of these bonds in 2001.

(2)Holders of the Enel Generation 7.325% Yankee Bonds due 2037 exercised a put option on February 1, 2009, for a total amount of US$ 149.2 million. The remaining US$ 70.8 million principal amount of the Yankee Bonds mature in February 2037.

(3)Weighted-average coupon by outstanding amount.

We also have access to the Chilean domestic capital markets. Our subsidiary, Enel Generation, has issued debt instruments that have been primarily sold to Chilean pension funds, life insurance companies, and other institutional investors.

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The following table lists UF-denominated Chilean bonds issued by Enel Generation that are outstanding as of December 31, 2019.

			Coupon (inflation		Aggregate Principal Amount
Issuer	Term	Maturity	adjusted rate)		Issued	Outstanding
					(in millions of UF)	(in millions of UF)	(in billions of Ch$)
Enel Generation Series H	25 years	October 2028	6.20%		4.00	1.92	54.36
Enel Generation Series M	21 years	December 2029	4.75%		10.00	9.09	257.36
Total			5.00%	(1)	14.00	11.01	311.72

(1) Weighted-average coupon by outstanding amount.

For a full description of local bonds issued by Enel Generation, see “Unsecured liabilities detailed by currency and maturity” in Note 21.2 of the Notes to our consolidated financial statements.

We may also participate in the international and local commercial bank markets through syndicated or bilateral senior unsecured loans, including both fixed term and revolving credit facilities. The amounts outstanding or available under our syndicated revolving loan as of December 31, 2019, are set forth in the table below.

Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(in millions of US$)	(in millions of US$)
Enel Chile	Syndicated Senior Unsecured Revolving Credit Agreement	June 2024	100	—
Enel Chile	Bilateral revolving loan	June 2024	50	—
Total			150	—

The revolving credit facilities are governed by the laws of the State of New York. The disbursement is not subject to the compliance of conditions precedent regarding the non-occurrence of a “Material Adverse Effect” (or MAE, as defined contractually), thus allowing us full flexibility to draw down, under any circumstances including situations involving a MAE, for up to US$ 150 million as of December 31, 2019, and as of the date of this Report remained undrawn.

We may also borrow from banks in Chile under fully committed facilities, under which a potential MAE would not be an impediment to this source of liquidity. In 2019, Enel Chile entered into a 5-year bilateral revolving loan for an aggregate amount of Ch$ 34,000 million as set forth in the table below.

Borrower	Type	Maturity	Facility Amount	Amount Drawn
			(in millions of Ch$)	(in millions of Ch$)
Enel Chile	Syndicated Senior Unsecured Revolving Credit Agreement	June 2024	34,000	—

As a result of the foregoing, we have access to fully committed undrawn revolving loans, both international and domestic, for up to Ch$ 146 billion in the aggregate as of December 31, 2019, and as of the date of this Report.

We and our subsidiaries also borrow routinely from uncommitted Chilean bank facilities with approved lines of credit for approximately Ch$ 53 billion in the aggregate, none of which are currently drawn. Unlike the committed lines described above, which are not subject to a no MAE condition precedent to disbursements, these facilities are subject to a greater risk of not being disbursed in the event of a MAE, and therefore could limit our liquidity under such circumstances.

On December 21, 2018, we entered into a 4-year revolving credit line with Enel Finance International N.V. for up to US$ 400 million. This loan was completely drawn down in June 2019 and became a bilateral term loan with maturity in December 2022. Additionally, on January 3, 2020, Enel Chile incurred debt with Enel Finance International N.V.

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through a US dollar-denominated loan for a total of US$ 200 million, with a maturity in July 2023. On March 11, 2020, we incurred debt with Enel Finance International N.V. through a US dollar-denominated loan of US$ 400 million, with a maturity in March 2030.

EGP Chile has also accessed the Chilean bank market through bilateral loan agreements, which as of December 31, 2019, totaled US$300 million, with a final maturity in December 2021. Also, EGP Chile entered into debt agreement with Enel Finance International N.V. through a US dollar-denominated loan, which as of December 31, 2019, had US$ 644 million outstanding, with a maturity in December 2027. EGP Chile entered into a subsidized financing with Interamerican Development Bank, through a US dollar-denominated loan, which as of December 31, 2019, had US$ 30 million outstanding, with a maturity in November 2022.

In addition, in March 2018, we registered a 30-year local bond program with the CMF for UF 15 million (Ch$ 425 billion as of December 31, 2019). As of December 31, 2019, and as of the date of this Report, there have been no issuances of bonds under this program.

Only Enel Generation’s outstanding debt facilities, with the exception of their Yankee Bonds, include financial covenants. The types of financial covenants, and their respective limits, vary from one type of debt to another. As of December 31, 2019, the most restrictive financial covenant affecting Enel Generation was the financial expenses coverage ratio in connection with the UF-denominated Chilean bonds. As of December 31, 2019, and as of the date of this Report, we are in compliance with the financial covenants contained in our debt instruments.

As is customary for certain credit and capital market debt facilities, a significant portion of our financial indebtedness is subject to cross default provisions. Each of the UF-denominated Chilean bonds described above, as well as Yankee Bonds issued by us and Enel Generation, have cross default provisions with different definitions, criteria, materiality thresholds and applicability as to the subsidiaries that could give rise to a cross default.

The cross-default provision of our Yankee Bonds may be triggered by our subsidiaries’ debt. A matured default of Enel Generation or any of its subsidiaries could result in a cross default to the Yankee Bonds issued by us and by Enel Generation if such matured default, on an individual basis, has a principal exceeding certain materiality thresholds. Enel Generation’s subsidiaries do not currently have any financial obligations. In the case of a matured default above the materiality threshold, holders of Yankee Bonds would have the option to accelerate if either the trustee or bondholders representing at least 25% of the aggregate debt of a particular series then outstanding chose to do so. Enel Generation’s local bonds do not have cross default provisions arising from its subsidiaries.

The UF-denominated Chilean bonds provide that the cross default can be triggered only by default of the issuer itself, in cases where the amount in default exceeds US$ 50 million in individual debt, or its equivalent in other currencies. However, the acceleration must be demanded in a meeting of bondholders by at least 50% of the bondholders of the affected series.

The payment of dividends and distributions by our subsidiaries and affiliates represent an important source of funds for us. The payment of dividends and distributions by certain subsidiaries and affiliates are potentially subject to legal restrictions, such as legal reserve requirements, capital and retained earnings criteria and other contractual restrictions. We are currently in compliance with the legal restrictions and therefore, they currently do not affect the payment of dividends or distributions to us. Certain credit facilities and investment agreements of our subsidiaries may restrict the payment of dividends or distributions in certain special circumstances. For instance, one of Enel Generation’s UF-denominated Chilean bonds restricts the amount of intercompany loans that Enel Generation and its subsidiaries are allowed to lend to related parties. The threshold for such aggregate restriction of intercompany loans is currently US$ 500 million. For a description of liquidity risks resulting from our company status, see “Item 3. Key Information — D. Risk Factors— We depend on payments from our subsidiaries to meet our payment obligations.”

Our estimated capital expenditures for 2020 through 2022 are expected to amount to Ch$ 1,585 billion, which includes maintenance capital expenditures, investment in expansion projects under execution, as well as water rights and expansion projects that are still under evaluation, in which case we would undertake them only if deemed profitable.

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We do not currently anticipate liquidity shortfalls affecting our ability to satisfy the material obligations described in this Report. We expect to be able to refinance our consolidated indebtedness as it becomes due, fund our purchase obligations with internally generated cash and fund capital expenditures with a mixture of internally generated cash and borrowings.

LIBOR Transition

The U.K. Financial Conduct Authority found that the London Interbank Offered Rate (“LIBOR”) had inconsistencies in its calculations and recommended that it be based on real transactions. As a result, the authority agreed to stop requiring banks to comply with the submission of interbank rates to calculate LIBOR as of December 31, 2021. LIBOR will be discontinued, and alternative benchmark rates are expected to replace it. Currently, there is no clear opinion about the benchmark rate that will replace LIBOR, but market participants expect that a risk-free rate, such as the Secured Overnight Financing Rate (“SOFR”), a broad measure of the cost of borrowing overnight collateralized by U.S. Treasury securities, to replace it, in the context of operations involving U.S. banks.

This reform may affect us in the following ways:

(i) Interest payments on loans and derivatives: Financial risks arising from using a new benchmark rate, where interest payments previously based on LIBOR may either increase or decrease. There is also a risk concerning data availability relating to the timely disclosure of market information, which may also affect the effectiveness of hedges .

(ii) Financial systems: Operational risk arising from the necessity to modify and adapt our financial systems to report, evaluate, or calculate payments under the new required benchmark rates.

(iii) Fair value measurement: Financial risks arising from how changes to benchmark rates in our debt obligations could adversely affect fair value measurements.

(iv) Contracts: Legal and financial risk relating to the renegotiation of ISDA and local derivative contracts

As of March 31, 2020, our total debt exposure to LIBOR was US$ 700 million. Although we have debt obligations that refer to LIBOR that expire after 2021, all of them include provisions to transition from LIBOR to an alternative benchmark rate. However, at this time, we cannot determine the extent these changes will affect us.

Enel Chile has intercompany debt obligations that stipulate that if LIBOR is not available, a replacement rate quoted by reference banks chosen by lenders that are leaders in the European interbank market for deposits in U.S. dollars and a period comparable to the corresponding interest period, may be used. Under a line of credit, intragroup operations must be promptly determined at market conditions. The proposed new reference rates will probably differ from LIBOR.

In 2019 we executed a Senior Unsecured Revolving Credit Agreement (“SURCA”) and a Revolving Credit Facility Agreement (“RFA”) that includes specific language regarding the replacement of LIBOR for an alternative rate of interest that accounts for the prevailing market convention for determining a rate of interest for syndicated loans in the United States at that later time. The SURCA and RFA are for up to US$ 100 million and US$ 50 million, respectively As of the date of this Report, both agreements were undrawn. Additionally, we have a term loan for US$ 400 million from Enel Finance International N.V. The loan agreement stipulates a replacement rate for LIBOR quoted by reference banks chosen by lenders that are leaders in the European interbank market.

Our subsidiary EGP Chile has two bank loans for an aggregate amount of US$300 million with specific clauses that stipulate that an alternative specified rate replace LIBOR as a result of the reforms under discussion in the United Kingdom as of the date of the contract. Both loans are due before December 31, 2021.

C.Research and Development, Patents and Licenses, etc.

None.

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D.Trend Information.

Our subsidiaries are engaged in the generation and distribution of electricity in Chile, sectors where changes are expected, including more restrictive government regulations, the introduction of new technologies and business models, and more competition. Our businesses are subject to a wide range of conditions that may result in significant variability in our earnings and cash flows from year to year. We seek to establish a conservative and well-balanced commercial policy, which aims at controlling relevant variables, reducing risks, and providing stability to our results of operations.

Generation

Our operating income is affected by several factors, including contracted electricity prices, prevailing hydrological conditions, the price of fuels used to generate thermal electricity, contracted obligations, generation mix, and the electricity prices prevailing in the spot market, among others. With the consolidation of EGP Chile as of April 2018, we added 1,189 MW of installed capacity. We expect that NCRE will boost the growth of our generation business.

Sales prices and energy costs are among the main drivers of our results of operations of our electricity generation business. The quantity of electricity sold has been generally stable over time, with increases reflecting economic and demographic growth. Our profits from contracted sales rely on our ability to generate or buy electricity at a cost lower than contracted prices. However, the applicable price for electricity sales and purchases in the spot market is much harder to predict because the spot generation price is influenced by several factors, including hydrology and fuel prices. Abundant hydrological conditions generally lower spot prices, while dry conditions increase them, although this effect on prices may be partly mitigated with NCRE generation.

Our operating income might not be adversely impacted even when we are required to buy electricity at high prices in the spot market if our commercial policy is appropriately managed. Our goal is to have a conservative and well-balanced commercial policy that controls relevant variables, provides stability to our profits, and mitigates our exposure to the volatility of the spot market.  We do so by contracting a significant portion of our expected electricity generation through long-term electricity supply contracts. The optimal level of electricity supply commitments protects us against low marginal cost conditions, such as those existing during a rainy season, while still taking advantage of high marginal cost conditions, such as higher spot market prices during dry years. To determine the optimal mix of long-term contracts and sales in the spot market, we project our aggregate generation taking into consideration our diversified generation mix and the incorporation of new projects under construction under dry hydrology. We then create demand estimates using standard economic theory and forecast the system’s marginal cost using proprietary stochastic models. We also participate in the energy forward derivatives market, which allows us to negotiate volumes and future prices to ensure demand and avoid buying in the spot market, which has high volatility and risk.

Our sales contracts to customers not subject to regulated prices are not standardized, and the contractual terms and conditions are individually negotiated. When negotiating these contracts, we try to set the price at a premium over future expected spot prices to mitigate the risk of increases in future spot prices. However, the premium can vary substantially depending on several conditions such as node values, load profile, and the term of the contract. Our contracted sales with regulated customers represent, on average more than 56%  of our sales in 2019, allowing us to maintain steady prices for more extended periods, typically 10 to 15 years, which, combined with our balanced commercial policy, generally provides for a stable profit.

We expect the Los Cóndores hydro plant to be completed during 2021, adding an average of 600 GWh of annual generation to our consolidated generation capacity. In 2022 and 2024, we expect significant price decreases, mainly due to the start of operations of projects tendered in 2016 and 2017, respectively, including our Campos del Sol, Cerro Pabellón extension, and Renaico II projects.

In 2022, distribution company contracts awarded to Enel Generation in the auction of August 2016 will come into effect. Therefore, we expect the tariffs of our regulated agreements are going to decrease as a consequence of the lower prices offered by NCRE providers. In 2024, contracts awarded in the November 2017 auction will come into effect with an average price of the total allocated energy of US$ 32.5 per MWh, 32% lower than the average price of the previous tender process. The total amount of energy tendered was based on NCRE offers, representing a milestone in the

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industry. We were awarded 54% of the total tender of 2,200 GWh per annum, corresponding to 1,180 GWh per annum at an average price of US$ 34.7 per MWh with a mix of wind, solar and geothermal generation, which will be provided through NCRE projects backed up by conventional energy.

We regularly 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 projected new capacity and allow us to stabilize our income. Some of the latest long-term power purchase agreements awarded are with the mining companies BHP Billiton (for 3TWh per annum), Collahuasi (1TWh per annum), and Anglo American (3TWh per annum). Considering the results of the last two tenders for regulated customers, we expect to continue increasing the NCRE market competitiveness. As a result, offered prices will probably continue to decrease, but at a lower rate compared to previous years.

During the last few years, NCRE generation has grown much faster than expected, mainly as a consequence of the technological improvement in wind and solar technologies and the associated declining amount of capital required to deploy them. The government also established a regulated tender framework that allows the energy market to access this price reduction in the medium and long term. Currently, NCRE (solar, wind, and geothermal) generation installed capacity represents 22% of the total market share, according to the monthly CEN report for December 2019. EGP Chile has a competitive pipeline of projects with short time-to-market, which is possible because of commercial opportunities through PPA contracts.

For the period 2020-2022, we expect Ch$1,585 billion in investments related to the development of new renewable plants, maintenance projects of distribution networks, and existing generation power plants. By 2022, renewable projects under development are expected to increase the current installed capacity by 2GW.

With respect to the development of new projects to increase our installed capacity, our strategy is to focus on creating synergies with plants in operation and obtaining economies of scale by combining existing plants with new NCRE projects to achieve greater competitiveness. We expect to continue competing in the future through PPA contracts, in part associated with the migration of regulated customers from the distribution business, mainly mining and large industries, who are demanding NCRE sources to reduce their energy costs and to clean their carbon footprint. The continuous addition of NCRE power plants to the grid will require further transmission network reinforcement and market flexibility and focus on operational efficiency to combine the different technologies while maintaining the security and the system’s supply reliability. Wind and solar sources, the NCRE sources most widely used, have higher intermittency than other non-NCRE facilities since they can only generate electricity when the wind blows, or the sun shines. Battery energy solutions will likely play a vital role in the next decade, providing a crucial solution for frequency control and grid stability in the context of significant wind and solar penetration.

Distribution

Distribution customers who can choose between regulated and unregulated tariffs are switching to unregulated tariffs, thereby becoming direct generation company customers and paying tolls to distribution companies.  These customers are tendering their energy needs, either directly or in association with other customers, because unregulated tariffs are currently lower than regulated tariffs that are based on contracts tendered in the past at higher prices.  We expect this trend may continue in the future until lower-cost agreements are recognized in the regulated tariffs. Based on the latest tender processes, it may last until 2024 with the recognition of the 2017 tendered prices in the regulated tariff.

We expect organic growth expansion in the distribution business, mainly coming from the digitalization of the network. We plan to invest in new technologies that will automate our systems to achieve better operational and economic efficiency. New technology includes smart meters, which allow bi-directional communication, digitized and interconnected networks, and enable our consumers to improve their energy efficiency. We will continue investing in this technology since it will enable us to reduce costs in meter reading without an on-site inspection, to remotely manage the disconnection and reconnection processes, and to address extreme weather emergencies better by significantly reducing failure recognition time. These instruments will also facilitate efficient maintenance as well as provide a necessary technical tool through which residential customers may inject their future excess energy into the electrical system.

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Adverse impact of the COVID-19 pandemic

In March 2020, due to the COVID 19 pandemic, Chilean President Sebastián Piñera decreed a state of emergency for 90 days, and such emergency measure may be subsequently extended beyond June 2020. Under such executive authority, President Piñera has instituted nighttime military curfews, selective mandatory quarantines in affected areas, control of entrance, exit and traffic within specified zones, the prohibition of mass gatherings, the closing of public schools, among other measures. The private sector has voluntarily taken further measures, such as adopting telecommuting wherever possible and the closing of commercial offices. Many businesses, such as restaurants and retail stores, have temporarily closed, either voluntarily or by executive decree, and companies associated with travel, transportation, and tourism have been severely affected and many may go bankrupt.

The cumulative effect of measures of this kind will likely lead to a recession, high unemployment levels, and perhaps a decline in electricity demand. If the COVID-19 pandemic is not adequately contained in 2020, the ability of our businesses to generate income and maintain liquidity levels to allow for normal operations may diminish. We may also experience increased difficulties in receiving payments from our distribution customers, especially those residential customers accustomed to making their monthly electricity bill payments in our commercial offices, some of which have closed. These customers may not have easy access to payment online or may have greater difficulties in settling their electricity bills. 

In April 2020, the Ministry of Energy reported that it decided to postpone application of the rates that are generally charged for energy consumption at peak hours (from 6 to 10 p.m.) during the months of April to September of each year (autumn and winter periods), months when demand of electricity is the highest and the reservoirs have less water. The decision is due to the effect on lower energy demand as a result of restrictions on mobility and the temporary closure of companies as a result of COVID-19. Therefore, these rates will take effect from June 2020.

We are not presently able to quantify the expected adverse effects of COVID‑19 on our results. The electricity industry provides an essential and strategic service and we expect that our businesses will continue to operate and supply electricity and will be better positioned to withstand the impacts of the COVID-19 pandemic; however, we expect the negative effects of the COVID-19 pandemic on our 2020 results will be adverse, especially in the distribution business.

Tariffs Stabilization Mechanism: Deferral of electricity distribution tariffs

Due to the social crisis in October 2019, the Chilean government began to implement measures to address social concerns raised by protesters. One of these measures established a mechanism for stabilizing electricity prices for regulated customers, the “Tariff Stabilization Mechanism.” It is related to Law No. 21,185 of the Ministry of Energy. The new law provides that regulated customer tariffs between July 1, 2019 and December 31, 2020 will remain at the levels prevailing as of June 30, 2019, and will not benefit from any indexation until December 31, 2020. This stabilized tariff is known as “Regulated Customer Stabilized Price” (“PEC” in its Spanish acronym).

From January 1, 2021 until the end of the Tariff Stabilization Mechanism, the tariffs will be those defined in the semi-annual decrees referred to in Article 158 of the Electricity Law, but may not be higher than the PEC adjusted according to the consumer price index (the “adjusted PEC”).

The difference between PEC or adjusted PEC and the rate that should have been charged under the applicable PPAs will create accounts receivable in favor of the generation companies.  The maximum accounts receivable for the Tariff Stabilization Mechanism will be US$ 1,350 million and the balance will be paid beginning July 1, 2023 through tariffs set above the PPA rates and must be collected no later than December 31, 2027. The regulator will issue semi-annual decrees that will identify the price of the contractual conditions of the PPAs, and the differences not collected under the PPAs, in their equivalent in U.S. dollars. These differences, in the form of accounts receivable, will not accrue interest, except that the balances not collected as of January 1, 2026, will accrue interest at the rate of six-month LIBOR, or the equivalent rate that replaces it, plus a spread corresponding to the country risk at the date of application.

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The tariff deferral directly affects electricity generation companies by decreasing revenues, affecting their cash flows, and increasing the need to finance their operations.

Reduction of the profitability of distribution companies

The Ministry of Energy’s Law No. 21,194, published on December 21, 2019, is expected to lower distribution company profitability by (i) lowering the rate of return allowed on investment costs, from a 10% annual rate in real terms to a rate in the range of 6‑8% per annum; and (ii) forcing the after-tax rate of return of distribution companies not to differ by more than two full percentage points above and three points below the rate defined by the CNE.

The devaluation of the Chilean peso against the U.S. dollar

As of the date of this Report, with a recent Observed Exchange Rate of Ch$ 856.76 per U.S. dollar as of April 27, 2020, the Chilean peso continues to devalue against the U.S. dollar and may have a direct effect on:

· Revenues: Sales of energy to regulated and unregulated customers through PPAs and spot prices are indexed to the U.S. dollar.

· Costs: International prices of fuel commodities such as fuel oil, coal, and LNG, directly affect our thermal generation costs, since Chile does not produce those fuels in any significant quantities. Also, some administrative expenses, such as insurance premiums and some maintenance costs, are denominated in U.S. dollars.

E.Off-balance Sheet Arrangements.

We are not a party to any off-balance sheet arrangements.

F.Tabular Disclosure of Contractual Obligations.

The table below sets forth our cash payment obligations as of December 31, 2019:

	Payments due by Period
Ch$ billion	Total	2020	2021-2022	2023-2024	After 2024
Purchase obligations(1)	12,075	4,697	3,966	2,509	903
Interest expense	1,125	149	277	226	472
Yankee bonds	1,286	—	—	299	986
Local bonds(2)	317	32	64	67	154
Lease obligations	70	8	12	11	39
Pension and post-retirement obligations(3)	66	8	9	8	41
Bank debt(2)	1,029	112	434	121	362
Total contractual obligations	15,967	5,007	4,762	3,242	2,956

(1)Includes generation and distribution business purchase obligations, which are comprised mainly of energy purchases, operating and maintenance contracts, and other services. Of the total contractual obligations of Ch$ 12,075 billion, 63% corresponds to energy purchased for distribution, 21% corresponds primarily to fuel supply, maintenance of medium and low voltage lines, supplies of cable and utility poles, and energy purchased for generation, and the remaining 16% corresponds to miscellaneous services, such as LNG regasification, fuel transportation and coal handling.

(2)Represents net value, including the value of derivatives.

(3)Our pension and post-retirement benefit plans are unfunded. Cash flow estimates in the table are based on such annual contractual commitments including certain estimable variable factors such as interest. Cash flow estimates in the table relating to our unfunded plans are based on future discounted payments necessary to meet all of our pension and post-retirement obligations.

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G.Safe Harbor.

The information contained in Items 5.E and 5.F contains statements that may constitute forward-looking statements. See “Forward-Looking Statements” in the “Introduction” of this Report, for safe harbor provisions.

Item 6.      Directors, Senior Management and Employees

A.Directors and Senior Management.

Directors

Our Board of Directors consists of seven members who are elected for a three-year term at the General Shareholders’ Meeting (“GSM”). Following the end of their term, they may be re-elected or replaced. If a vacancy occurs in the interim, the Board of Directors will elect a temporary director to fill the vacancy until the next GSM, at which time the entire Board of Directors will be elected to a new three-year term. Our Executive Officers are appointed and hold office at the discretion of the Board of Directors.

The members of our Board of Directors as of December 31, 2019, were as follows:

Directors	Position	Age (1)	Current Position Held Since
Herman Chadwick P.	Chairman	75	2016
Salvatore Bernabei	Director	46	2016
Pablo Cabrera G.	Director	72	2016
Daniele Caprini	Director	46	2018
Giulio Fazio	Director	49	2016
Fernán Gazmuri P.	Director	75	2016
Juan Gerardo Jofré M.	Director	70	2016

(1) As of April 30, 2020.

The Board of Directors was elected at the GSM held on April 25, 2018, for three-year terms that end in April 2021. During the Board of Directors’ meeting, Mr. Chadwick was appointed Chairman and Messrs. Gazmuri, Cabrera, and Jofré as members of the Directors’ Committee. Mr. Gazmuri was also appointed Financial Expert of the Directors’ Committee.

Set forth below are brief biographical descriptions of the members of our Board of Directors, three of whom reside outside Chile and four of whom live in Chile, as of December 31, 2019:

Herman Chadwick P.

Mr. Chadwick is a law partner at Chadwick & Cía. and a director of several companies unrelated to us, including Inversiones Aguas Metropolitanas, a Chilean holding company which owns a water utility company, Viña Santa Carolina, a Chilean winery, Centro de Estudios Públicos, a public policy think tank, and Carola, a mining company. Mr. Chadwick is chairman of the Board and arbitrator at Centro de Arbitraje y Mediación de la Cámara de Comercio de Santiago, an association that provides arbitration services. He is also Vice-Chairman of IntervialChile, a highway concession company. Mr. Chadwick holds a law degree from Pontificia Universidad Católica de Chile.

Salvatore Bernabei

Mr. Bernabei is the Head of Global Procurement of Enel since May 2017. He was Head of Renewable Energy Latin America of Enel Green Power (2016-2017) and Country Manager for Chile and the Andean Countries (2013-

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2016). He joined Enel in 1999 and has held several positions in the field of engineering, construction, operation & maintenance, safety environment and quality of life. Mr. Bernabei holds a degree in industrial engineering from Università degli Studi di Roma“Tor Vergata” and an MBA from Politecnico di Milano.

Pablo Cabrera G.

Mr. Cabrera is a member of the Sociedad Chilena de Derecho Internacional.  Mr. Cabrera was director of Academia DiplomáticaAndrés Bello (2010-2014), and served concurrently as ambassador to the Holy See, the Sovereign Military Order of Malta and Albania (2006-2010), the People’s Republic of China (2004-2006) Russia and Ukraine (2000-2004), as well as the United Kingdom and Ireland (1999-2000). He also headed the Subsecretaría de Marina de Chile (1995-1999). Mr. Cabrera holds a law degree from Pontificia Universidad Católica de Chile and is a certified career diplomat from Academia DiplomáticaAndrés Bello.

Daniele Caprini

Mr. Caprini has been the Head of Enel’s Group Planning and Reporting since 2018. He was the CFO of Enel Colombia (2016-2017). He headed Enel’s Financial Valuation and Investment Control (2013-2015), and Strategic Planning M&A and Financial Valuation (2009-2013) of Enel Green Power S.A. Mr. Caprini holds a degree in economics from the Università degli Studi di Siena and an MBA from Roma Università LUISS.

Giulio Fazio

Mr. Fazio is the Head of Enel’s Legal and Corporate Affairs since January 2016. Previously he held a similar position at Enel Green Power S.p.A. (2008-2014). Since 2004, he has worked in finance and antitrust operations in Enel’s Legal Department. Mr. Fazio first joined an Enel affiliate in 1996. He holds a degree in law and a Ph.D. from Università degli Studi di Palermo.

Fernán Gazmuri P.

Mr. Gazmuri has served on the boards of companies unrelated to us. He is currently Vice Chairman of Invexans S.A., a holding company that owns NEXANS, a French telecom and maritime cable company, and Chairman of Citroën Chile S.A.C. He has been Chairman of the Asociación Chilena de Seguridad, and Vice Chairman of the Sociedad de Fomento Fabril. In 2013-2016, he was director of Empresa Nacional del Petróleo, the Chilean state-owned oil company. He was Vice-Chairman of the International Chamber of Commerce of Chile in 2005‑2009. In 2016, Mr. Gazmuri was awarded the Jorge Alessandri Rodríguez distinction by the Asociación de Industriales Metalúrgicos y Metalmecánicos, due to his outstanding professional and business career. In 2014, Mr. Gazmuri was awarded the Ordre national du Mérite by the Republic of France. He holds a degree in business administration from Pontificia Universidad Católica de Chile.

Juan Gerardo Jofré M.

Mr. Jofré is a director of CAP S.A., a mining and steel company, and a member of the self-regulatory council of the Asociación de Aseguradores de Chile, the insurance companies association. In 2010-2014 he was Chairman of the Board of Codelco, the Chilean state-owned copper mining company. He has been a director of Enel Generation as well as several companies unrelated to us, including Latam Airlines S.A., D&S S.A., Viña San Pedro S.A., Sociedad Química y Minera de Chile, S.A. (SQM), Banco Santander Chile, among others, and has held several managerial positions, primarily with Santander Chile Group. He holds a degree in business administration from Pontificia Universidad Católica de Chile.

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Executive Officers

Set forth below are our Executive Officers as of December 31, 2019.

Executive Officers	Position	Age(1)	Joined Enel or Affiliate in	Current Position Held Since
Paolo Pallotti	Chief Executive Officer	57	1990	2018
Giuseppe Turchiarelli (2)	Chief Financial Officer	49	1998	2019
Raffaele Cutrignelli (3)	Internal Audit Officer	38	2005	2016
Liliana Schnaidt H.	Human Resources Officer	40	2009	2018
Domingo Valdés P.	General Counsel	56	1993	2016

(1) As of April 30, 2020.

(2) Assumed this role as of November 15, 2019.

(3) As of March 1, 2020 Raffaele Cutrignelli was replaced by Eugenio Belinchon.

Set forth below are brief biographical descriptions of our Executive Officers, all of whom reside in Chile.

Paolo Pallotti: Mr. Pallotti was the CFO of Enel Américas until 2018. He played a crucial role in various Enel corporate reorganization processes. He served as CFO of Enel’s Italian businesses (2014-2018), Financial Director of Enel’s Infrastructure & Networks division (2012), and director of Enel Energia S.p.A. (2015-2018) and Enel Italia S.r.L (2017-2018). He holds a degree in electronic engineering from Università degli Studi di Ancona.

Giuseppe Turchiarelli: Mr. Turchiarelli has held prominent financial positions in Enel since 1998, among which he served as CFO of Enel Latin America BV (2009-2011), CFO for renewable generation in Italy and Europe (2001‑2012), Head of Planning and Control of the Enel Green Power Group (2012-2013), CFO for Iberia and Latin America (2013-2015), Head of Planning and Control in Italy (2015‑2017), and CFO for Europe and North Africa (2017-2019). He holds a degree in business administration from Università degli Studi di Cagliari and an Executive MBA from LUISS Business School.

Raffaele Cutrignelli: Mr. Cutrignelli was the Audit Officer for Enel affiliates in Colombia (2015-2016) and the Head of Latin American Audit for Enel Green Power in Brazil (2013-2015). Mr. Cutrignelli holds a degree in international business from Nottingham Trent University, and a Master’s Degree in Audit and Internal Controls from Università di Pisa.

Liliana Schnaidt H.: Ms. Schnaidt held positions in Enel Green Power business development, with a focus on solar energy (2009-2018). Ms. Schnaidt holds a degree in civil engineering from Pontificia Universidad Católica de Chile.

Domingo Valdés P.: Mr. Valdés is the General Counsel of  Legal and Corporate Affairs of Enel Chile and Enel Américas and is Secretary of the Boards of Directors of both corporations. He is also a Tenured Professor of Economic and Antitrust Law at Universidad de Chile. Mr. Valdés holds a summa cum laude law degree from Universidad de Chile, and a Masters of Law degree from the University of Chicago.

B.Compensation.

At the GSM held on April 29, 2020, our shareholders approved the compensation policy for our Board of Directors. Director compensation consists of a monthly fixed compensation of UF 216 per month and an additional fee of UF 79.2 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings, within the respective fiscal year. The Chairman of the Board is entitled to double the compensation of other directors.

The members of our Directors’ Committee are paid a monthly fixed compensation of UF 72 per month and an additional fee of UF 26.4 per meeting, up to a maximum of 16 sessions in total, including ordinary and extraordinary meetings. The monthly payments (fixed and variable) are considered as advances on the annual variable fee.

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If a director serves on one or more Boards of Directors of the subsidiaries or associate companies or serves as director of other companies or corporations in which the group holds an interest directly or indirectly, the director can only receive compensation from one of these Boards of Directors.

Executive Officers of our Company and our subsidiaries or affiliates will not receive compensation in the case that they serve as director of any other affiliate. However, compensation may be received by the officer to the extent that it is expressly and previously authorized as an advance payment of the variable portion of the wage to be paid by the affiliate with which the officer signed a contract.

In 2019, the total compensation paid to each of our directors, including fees for attending Directors’ Committee meetings was as follows:

Director	Fixed Compensation	Ordinary and Extraordinary Session	Directors’ Committee (Fixed Compensation)	Ordinary and Extraordinary Session (Directors' Committee)	Variable Compensation	Total
	(in ThCh$)
Herman Chadwick P.	144,512	61,839	—	—	—	206,350
Salvatore Bernabei (1)	—	—	—	—	—	—
Pablo Cabrera G.	72,256	30,919	24,085	9,562	—	136,823
Daniele Caprini (1)	—	—	—	—	—	—
Giulio Fazio (1)	—	—	—	—	—	—
Fernán Gazmuri P.	72,256	30,919	24,085	9,562	—	136,823
Juan Gerardo Jofré M.	72,256	30,919	24,085	9,562	—	136,823
Total	361,279	154,597	72,256	28,687	—	616,819

(1) Messrs. Bernabei, Caprini and Fazio waived their compensation for their current position as Director of the Company due to their jobs as employees of other companies in the Enel Group.

We do not disclose, to our shareholders or otherwise, any information about an individual Executive Officer’s compensation. Executive Officers are eligible for variable compensation under a bonus plan. The annual bonus plan is paid to our Executive Officers for achieving company-wide objectives and for their contribution to our results and goals. The yearly bonus plan provides for a range of bonus amounts according to seniority level and consists of a certain multiple of gross monthly salaries. For the year ended December 31, 2019, the aggregate gross compensation, paid or accrued, for all of our Executive Officers, attributable to fiscal year 2019, was Ch$ 1,636 million in total compensation and Ch$ 209 million in variable compensation and benefits, already included in total compensation.

We entered into severance indemnity agreements with all of our Executive Officers, pursuant to which we will pay a severance indemnity in the event of voluntary resignation or termination by mutual understanding among the parties. The severance indemnity does not apply if the termination is due to willful misconduct, prohibited negotiations, unjustified absences or abandonment of duties, among other causes, as defined in Article 160 of the Chilean Labor Code. All of our employees are entitled to a severance indemnity if terminated due to our needs, as described in Article 161 of the Chilean Labor Code.

We did not pay severance indemnity to our Executive Officers in 2019. There are no other amounts set aside or accrued to provide for pension, retirement, or similar benefits for our Executive Officers.

C. Board Practices.

Our current Board of Directors was elected at the GSM held on April 25, 2018, for a three-year term. For information about each of the directors and the year that they began their service on the Board of Directors, see “Item 6. Directors, Senior Management and Employees — A. Directors and Senior Management” above. Members of the Board of Directors do not have service contracts with us nor with any of our subsidiaries that provide them benefits upon termination of their service.

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Corporate Governance

We are managed by a Board of Directors, in accordance with our bylaws, consisting of seven directors who are elected by our shareholders at the GSM, each of whom serves for a three-year term. Following the end of their term, they may be re-elected indefinitely or replaced. Staggered terms are not permitted under Chilean law. If a vacancy occurs on the Board of Directors during the three-year term, the Board of Directors may appoint a temporary director to fill the vacancy. A vacancy triggers an election for every seat on the Board of Directors at the next GSM.

Chilean corporate law provides that a company’s Board of Directors is responsible for the management and representation of a company in all matters concerning its corporate purpose, subject to the provisions of the company’s bylaws, and the shareholders’ resolutions. In addition to the bylaws, our Board of Directors has adopted regulations and policies that guide our corporate governance principles.

Our corporate governance policies are mainly included in the following policies or procedures: the Manual for the Management of Information of Interest to the Market (the “Manual”), the Human Rights Policy (Política de Derechos Humanos), the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Penal Risk Prevention Model, the Enel Global Compliance Program on Corporate Criminal Liability (the “Enel Global Compliance Program”), and procedures issued in compliance with General Regulation 385 issued by the CMF.

To ensure compliance with Securities Market Law 18,045 and CMF regulations, our Board of Directors approved the Manual at its meeting held on February 29, 2016, and ratified such decision at its meeting held on March 23, 2016. This document addresses applicable standards regarding the information in connection with transactions of our securities and those of our affiliates, entered into by directors, management, principal executives, employees, and other related parties, the existence of blackout periods for such transactions undertaken by directors, principal executives and other related parties, the presence of mechanisms for the continuous disclosure of information that is of interest to the market and mechanisms that protect confidential information. The Manual is posted on our website at www.enelchile.cl. The provisions of this Manual apply to the members of our Board, as well as our executives and employees who have access to confidential information, and especially those who work in areas related to the securities markets.

Our Board of Directors approved a procedure for relationships between Politically Exposed People (Procedimiento Personas Políticamente Expuestas y Conexas) and our Company, which established a specific regulation for their commercial and contractual relationships. The Human Rights Policy incorporates and adapts the United Nations’ general principles related to human rights into corporate reality.

To supplement the aforementioned corporate governance regulations, our Board of Directors also approved the Code of Ethics and the ZTAC Plan. The Code of Ethics is based on general principles such as impartiality, honesty, integrity, and other ethical standards of similar importance, all of which are expected from our employees. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with particular emphasis on avoiding corruption in the form of bribes, preferential treatment and other similar matters.

Furthermore, our Board of Directors approved the Penal Risk Prevention Model and the Enel Global Compliance Program. The Penal Risk Prevention Model satisfies the standards imposed by Chilean Law 20,393, which imposes criminal responsibility on legal entities for certain crimes, including money laundering, financing of terrorism, and bribing of public officials. The law encourages companies to adopt this model, whose implementation involves compliance with managerial and supervision duties. The adoption of the Penal Risk Prevention Model mitigates, and in some cases relieves, the effects of criminal responsibility even when a crime is committed. In turn, the Enel Global Compliance Program is designed as a tool to reinforce the group’s commitment to the highest ethical, legal and professional standards for enhancing and preserving the group’s reputation. It sets several preventive measures for corporate criminal liability.

In 2015, the CMF issued General Rule No. 385 to enhance transparency standards and introduce corporate social responsibility practices by promoting, among other things, management diversity. All publicly held limited liability corporations are required to provide the CMF, on an annual basis, with answers to a survey that relate to the board’s

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functions and composition; relationships between the company, shareholders and public in general; third-party assessments; and internal control and risk management. The Appendix of General Rule No. 385 is divided into the following four sections with respect to which companies must report the corporate practices that have been adopted: (i) the functioning and composition of the board, (ii) relations between the company, shareholders and the general public, (iii) risk management and control, and (iv) assessment by a third party. Publicly held limited liability corporations should send the information concerning corporate governance practices to the CMF, no later than March 31 of each year, using the contents of the Appendix to this regulation as criteria. If none of them is adopted, the company must explain its reasons to the CMF. The information should refer to December 31 of the calendar year before its dispatch. At the same time, such information should also be at the public’s disposal on the company’s website, and must be sent to the stock exchanges.

In 2018, the Board of Directors approved a policy dealing with environmental and biodiversity issues. Environmental, sustainability, and governance (“ESG”) considerations are fully integrated into the company’s business model. In compliance with CMF General Rule No. 385, the Board periodically receives reports by management that enable identification and assessment of all risks associated with ESG and climate change issues, including compliance with Board policies.

Compliance with the New York Stock Exchange Listing Standards on Corporate Governance

The following is a summary of the significant differences between our corporate governance practices and those applicable to U.S. domestic issuers under the corporate governance rules of the NYSE.

Independence and Functions of the Directors’ Committee (Audit Committee)

Chilean law requires that at least two thirds of the Directors’ Committee be independent directors. According to Article 50 bis of Law No.18,046, a member would not be considered independent if, at any time, within the last 18 months he: (i) maintained any relationship of a relevant nature and amount with the company, with other companies of the same group, with its controlling shareholder or with the principal officers of any of them or has been a director, manager, administrator or officer of any of them; (ii) maintained a family relationship with any of the members described in (i) above; (iii) has been a director, manager, administrator or principal officer of a non-profit organization that has received contributions from (i) above; (iv) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of an entity that has provided consulting or legal services for a relevant consideration or external audit services to the persons listed in (i) above; and (v) has been a partner or a shareholder that has controlled, directly or indirectly, 10% or more of the capital stock or has been a director, manager, administrator or principal officer of the principal competitors, suppliers or customers. In case there are not sufficient independent directors on the Board to serve on the Directors’ Committee, Chilean law determines that the independent director nominates the rest of the members of the Directors’ Committee among the remaining Board members that do not meet the Chilean law independence requirements. Chilean law also requires that all publicly held limited liability stock corporations that have a market capitalization of at least UF 1.5 million (Ch$ 42.5 billion as of December 31, 2019) and at least 12.5% of its voting shares are held by shareholders that individually control or own less than 10% of such shares, must have at least one independent director and a Directors’ Committee.

Under the NYSE corporate governance rules, all members of the Audit Committee must be independent. The Audit Committee of a U.S. company must perform the functions detailed in, and otherwise comply with the requirements of NYSE Listed Company Manual Rules 303A.06 and 303A.07. As of July 31, 2005, non-U.S. companies have been required to comply with Rule 303A.06, but not with Rule 303A.07. Since our incorporation on March 1, 2016, we have complied with the independence and the functional requirement of Rule 303A.06.

Pursuant to our bylaws, all members of the Directors’ Committee must satisfy the requirements of independence, as stipulated by the NYSE. The Directors’ Committee is composed of three members of the Board and complies with Article 50 bis of Law No.18,046, as well as with the criteria and requirements of independence prescribed by the Sarbanes-Oxley Act (“SOX”), the SEC and the NYSE. As of the date of this Report, the Directors’ Committee complies with the conditions of the Audit Committee as required by the SOX, the SEC and the NYSE corporate governance rules.

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As a result, we have a single Committee, the Directors’ Committee, which includes among its functions the duties performed by an Audit Committee.

Our Directors’ Committee performs the following functions:

review of financial statements and the reports of the external auditors before their submission for shareholders’ approval;

present proposals to the Board of Directors, which will make its proposals to shareholders’ meetings, for the selection of external auditors and private rating agencies;

review of information related to our transactions with related parties and reports the opinion of the Directors’ Committee to the Board of Directors;

the examination of the compensation framework and plans for managers, executive officers and employees;

the preparation of an Annual Management Report, including its main recommendations to shareholders;

provide information to the Board of Directors about the convenience of recruiting external auditors to provide non-auditing services, when such services are not prohibited by law, depending on whether such services might affect the external auditors’ independence;

oversee the work of external auditors;

review and approval of the annual auditing plan by the external auditors;

evaluate the qualifications, independence and quality of the auditing services;

elaborate on policies regarding the employment of former members of the external auditing firm;

review and discuss problems or disagreements between management and external auditors regarding the auditing process;

establish procedures for receiving and dealing with complaints regarding accounting, internal control, and auditing matters;

any other function mandated to the Committee by the bylaws, our Board of Directors or our shareholders.

Corporate Governance Guidelines

The NYSE’s corporate governance rules require U.S.-listed companies to adopt and disclose corporate governance guidelines. Chilean law provides for this practice through the disclosure of the procedures related to General Rule No. 385 and the Manual. We have also adopted the Code of Ethics, and our bylaws include provisions that govern the creation, composition, attributions, functions and compensation of the Directors’ Committee described above, which includes among its functions the duties performed by an Audit Committee.

D. Employees.

The following table sets forth the total number of our personnel, permanent, and temporary employees in Enel Chile and our subsidiaries as of December 31, 2019, 2018, and 2017:

Company	2019	2018	2017
Enel Distribution (1)	743	681	669
Enel Generation (2)	708	678	753
Enel Chile	475	451	431
EGP Chile (3)	214	163	—
GasAtacama (2)	—	87	93
Enel X	6	—	—
Pehuenche	2	2	2
Total Personnel (4)	2,148	2,062	1,948

(1) Includes Luz Andes S.A. and Empresa Eléctrica de Colina S.A.

(2) GasAtacama S.A. and GasAtacama merged into Enel Generation in October 2019.

(3) We have consolidated EGP Chile and its subsidiaries since April 2, 2018.

(4) The total number of temporary employees was not significant.

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All employees in Chile who are dismissed for reasons other than misconduct are entitled under the Chilean Labor Code to a severance indemnity payment. In most cases, contracted employees are entitled to a legal minimum severance indemnity payment of one month’s salary for each year (and every fraction thereof beyond six months) worked, subject to a maximum of 11 months’ salary. 

Our employment contracts typically provide severance indemnity payments higher than those required by the Chilean Labor Code.  In the majority of cases, we respect seniority in accordance with the time that the employee first joined us or an affiliate. Therefore, employees hired by one of our Chilean affiliates or predecessor companies maintain their seniority in the company and are treated contractually as if they had been hired by us. In accordance with such employment contracts, severance indemnity payments for the majority of our employees consist of one month’s salary for each full year worked (and every fraction thereof beyond six months), subject to a maximum of 25 months. Under our collective bargaining agreements and other employment contracts not covered by such agreements, we are typically obligated to make severance indemnity payments to all covered employees in cases of voluntary resignation or death in specified amounts that increase according to seniority and often exceed the amounts required under Chilean law.

We have the following collective bargaining agreements:

	In Force
Company	From	To
Enel Chile - Collective Bargaining Agreement 1	July 2019	July 2022
Enel Chile - Collective Bargaining Agreement 2	January 2020	December 2022
Enel Chile - Collective Bargaining Agreement 3 (1)	January 2020	December 2022
Enel Generation - Collective Bargaining Agreement 1	January 2018	June 2020
Enel Generation - Collective Bargaining Agreement 2	January 2018	June 2020
Enel Generation - Collective Bargaining Agreement 3	January 2018	December 2020
Enel Generation - Collective Bargaining Agreement 4	July 2019	June 2022
Enel Generation - Collective Bargaining Agreement 5	July 2016	June 2020
Enel Distribution - Collective Bargaining Agreement 1	January 2017	December 2020
Enel Distribution - Collective Bargaining Agreement 2	January 2017	December 2020
Enel Distribution - Collective Bargaining Agreement 3	January 2017	December 2020
Enel Green Power - Collective Bargaining Agreement 1	October 2017	September 2020
Empresa Eléctrica de Colina	November 2019	October 2022
Empresa Eléctrica Panguipulli S.A.	January 2018	December 2020
GasAtacama Chile	January 2018	December 2020

(1) This collective bargaining agreement was transferred from ICT Servicios Informáticos Ltda., a former subsidiary that merged into us.

E.Share Ownership.

To the best of our knowledge, none of our directors or officers owns more than 0.1% of our shares or owns any stock options. It is not possible to confirm whether any of our directors or officers has a beneficial, rather than direct, interest in our shares. To the best of our knowledge, any share ownership by all of our directors and officers, in the aggregate, amounts to significantly less than 10% of our outstanding shares.

Item 7.      Major Shareholders and Related Party Transactions

A.Major Shareholders.

We have only one class of capital stock and Enel, our ultimate controlling shareholder, has the same voting rights as our other shareholders. As of March 31, 2020, 6,164 shareholders of record held our 69,166,557,220 shares of our common stock outstanding. Enel owned 42,832,058,392 shares of our total common stock, representing a 61.9% direct ownership interest in us. There were five record holders of our ADSs, as of such date.

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In December 2019, Enel declared an intention to increase its ownership interest in us from its then current 61.9% ownership interest to up to 64.9% by the end of 2020 through share swap transactions involving our shares of common stock and ADSs entered into with a financial institution. Upon the termination and settlement of a swap transaction with respect to our ADSs, which is expected to occur on May 13, 2020, Enel’s beneficial ownership in us is expected to increase to 62.4%.  Enel may continue to acquire additional shares under the swap transactions during 2020 to increase its ownership interest in us up to 64.9% by the end of 2020.

It is not practicable for us to determine the number of our ADSs or our common shares beneficially owned in the United States as the depositary for our ADSs only registers the record holders, including the Depositary Trust Company and its nominees. As a result, we are not able to ascertain the domicile of the ultimate beneficial holders represented by the five ADS record holders in the United States, nor are we able to determine the domicile of any of our foreign shareholders who hold our common stock, either directly or indirectly.

As of March 31, 2020, Chilean private pension funds (“AFPs”), owned 15.8% of our shares in the aggregate. Chilean stockbrokers, mutual funds, insurance companies, foreign equity funds, and other Chilean institutional investors collectively held 17.1% of our shares, ADS holders owned 3.8% of our shares and the remaining 1.4% of our shares were held by 6,019 minority shareholders.

The following table sets forth certain information concerning ownership of the common stock as of April 30, 2020, with respect to each stockholder known by us to own more than 5% of the outstanding shares of common stock:

	Number of Shares (1) Owned	Percentage of Shares Outstanding
Enel S.p.A. (Italy)	42,832,058,392	61.9%

(1) Upon the termination and settlement of a swap transaction entered into by Enel with respect to our ADSs, which is expected to occur on May 13, 2020, Enel’s beneficial ownership interest in us is expected to increase to 43,143,307,892 shares of common stock, or 62.4%.

Enel, our ultimate controlling shareholder, is an Italian energy company with multinational operations in the power and gas markets, with a focus on Europe and Latin America. Enel operates in 33 countries across five continents, produces energy through a managed installed capacity of approximately 89 GW, which includes 46 GW of renewable sources, and distributes electricity and gas through a network covering 2.2 million kilometers. With approximately 73 million users worldwide, Enel has the largest customer base among European competitors and figures among Europe’s leading power companies in terms of installed capacity. Enel shares trade on the Milan Stock Exchange.

B.Related Party Transactions.

Article 146 of Law No. 18,046 (the “Chilean Corporations Law”) defines related-party transactions as all transactions involving a company and any entity belonging to the corporate group, its parent companies, controlling companies, subsidiaries or related companies, board members, managers, administrators, senior officers or company liquidators, including their spouses, some of their relatives, and all entities controlled by them, in addition to individuals who may appoint at least one member of the company’s board of directors or who control 10% or more of voting capital, or companies in which a board member, manager, administrator, senior officer or company liquidator has been serving in the same position within the last 18 months. 

Article 147 of the Chilean Corporation Law requires that related-party transactions must comply with taking into account the corporate interest, as well as the prices, terms, and conditions prevailing in the market at the time of their approval. Article 147 of the Chilean Corporation Law provides that board members, managers, administrators, senior officers, or company liquidators having a personal interest or acting on negotiations of a related-party transaction must immediately inform the Board of Directors. Such a transaction shall only be approved if an absolute majority of the directors (excluding interested directors) consider the operation to be beneficial for the corporate interest. Chilean law requires an interested director to abstain from voting on such a transaction. If an absolute majority of the directors are

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obliged to abstain from voting on any particular transaction, it shall only be approved if authorized unanimously by the independent directors or during an ESM. Board resolutions approving related-party transactions must be reported to the company’s shareholders at the next shareholders’ meeting.

The law described above, which also applies to our affiliates, provides for some exceptions. In some instances, the Board’s approval would suffice for related-party transactions, under certain transaction thresholds when the transactions are conducted with another entity in which we hold 95% or more of their capital, or when such transactions are conducted in compliance with the related-party policies defined by the company’s board. At its meeting held on July 30, 2019, our Board of Directors updated our related-party transaction policy  (Política General de Habitualidad). This policy is available on our website at www.enelchile.cl.

If a transaction is not in compliance with Article 147 of the Chilean Corporations Law, this will not affect the transaction’s validity, but our shareholders or we may demand compensation for damages from the individual associated with the infringement as provided by law.

Our internal procedure contemplates that all our subsidiaries’ cash inflows and outflows are managed through a centralized cash management mechanism. It is common practice in Chile to transfer surplus funds from one company to another affiliate that has a cash deficit. These transfers are executed through either short-term transactions or structured inter-company loans. Under Chilean laws and regulations, such transactions must be conducted on an arm’s-length basis. All of these transactions are subject to the supervision of our Directors’ Committee. As of March 31, 2020, the peso-denominated transactions were priced at TAB 1m (a Chilean interbank interest rate published daily) plus 1.10% when lending to affiliates and TAB 1m plus 0.30% when accepting deposits of cash surpluses from affiliates. The US$-denominated transactions were priced at LIBOR 1m plus 1.50% when lending to affiliates and LIBOR 1m plus 0.47% when accepting deposits of cash surpluses from affiliates.

On January 3, 2020, we entered into and drew down a US$-denominated term loan with Enel Finance International N.V. for US$ 200 million. As of March 31, 2020, the outstanding balance of the loan amounted to US$ 200 million, at a fixed annual interest rate of 2.60%.

On March 11, 2020, we signed a US$-denominated term loan with Enel Finance International N.V. for US$ 400 million. As of March 31, 2020, the outstanding balance of the loan amounted to US$ 400 million, at a fixed annual interest rate of 3.30%.

On December 21, 2018, we signed a US$-denominated term loan with Enel Finance International N.V. The committed amount of the loan was up to US$ 400 million. As of March 31, 2020, the outstanding balance of the loan amounted to US$ 400 million, at a variable interest rate of LIBOR 6m plus 1.00%.

On December 31, 2015, our subsidiary Enel Green Power del Sur SpA signed a US$-denominated term loan with Enel Finance International N.V. The committed amount of the loan was up to US$ 650 million. As of March 31, 2020, the outstanding balance of the loan amounted to US$ 644 million, at a fixed annual interest rate of 2.82%

On November 15, 2019, our subsidiary Enel Distribution received a Chilean peso-denominated structured loan from us. As of March 31, 2020, the outstanding balance of the loan amounted to Ch$ 135,514 million, at a fixed annual interest rate of 3.20%.

During 2019, we granted short-term intercompany loans to our subsidiaries Enel Distribution, Sociedad Agrícola De Cameros Ltda, Enel X Chile SpA, Empresa Eléctrica De Colina Ltda, Empresa Eléctrica Panguipulli S.A., Almeyda Solar SpA and Parque Eólico Taltal S.A..  As of March 31, 2020, the total outstanding balance of the loans amounted to Ch$ 241,232 million.

In the context of our cash management contracts, Enel Generation, Empresa Eléctrica Pehuenche S.A., Empresa de Transmisión Chena S.A., Parque Talinay Oriente S.A., and Enel Green Power del Sur SpA. all transferred cash surpluses to us. As of March 31, 2020, the total outstanding balance of their transfers amounted to Ch$ 535,422 million.

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Our subsidiary EGP Chile invested its cash surpluses in its subsidiary Geotermica Del Norte S.A. As of March 31, 2020, the total outstanding balance of the investment amounted to Ch$ 4,242 million.

All these aforementioned intercompany cash flows help meet the working capital needs of our subsidiaries.

There are various contractual relationships between Enel Américas, Enel Generation, Enel Distribution, Enel X Chile SpA, EGP Chile, and us to provide-intercompany services. We entered into intercompany agreements under which we provide services directly and indirectly to Enel Generation and its subsidiaries, Enel Distribution and its subsidiaries, and our other subsidiaries. The services to be rendered by us include certain legal, finance, treasury, insurance, capital markets, financial and documentary compliance, accounting, human resources, communications, security, relations with contractors, purchases, IT, tax, corporate affairs, and other corporate support and administrative services. The services rendered vary depending on the company receiving the service. These services are provided and charged at market prices if there is a comparable reference service. If there are no similar services in the market, they will be provided at cost plus a specified percentage. The intercompany services contracts are valid for five years, with renewable terms as of January 1, 2017.

The 2018 Reorganization consolidated Enel’s conventional and non-conventional renewable energy businesses in Chile. Under Chilean law, the 2018 Reorganization was deemed a related-party transaction, subject to the statutory requirements and protections of the Title XVI of the Chilean Corporations Law. For additional information on the 2018 Reorganization, see “Item 4. Information on the Company — A. History and Development of the Company — The 2018 Reorganization.”

As of the date of this Report, the aforementioned transactions have not experienced material changes. As of December 31, 2019, there were some commercial transactions with related parties.  For more information regarding transactions with related parties, refer to Note 12 of the Notes to our consolidated financial statements.

C.Interests of Experts and Counsel.

Not applicable.

Item  8.      Financial Information

A.Consolidated Statements and Other Financial Information.

See “Item 18. Financial Statements.”

Legal Proceedings

We are parties to legal proceedings arising in the ordinary course of business. We believe it is unlikely that any loss associated with pending lawsuits will significantly affect the normal development of our business.

For detailed information as of December 31, 2019, on the status of the material pending lawsuits filed against us, please refer to Note 36.3 of the Notes to our consolidated financial statements. Please note that since March 1, 2016, we appear as the defendant instead of Enel Américas for current legal proceedings or those that may arise from our former Chilean businesses.

In relation to the legal proceedings reported in the Notes to our consolidated financial statements, we use the criterion of disclosing lawsuits above a minimum threshold of US$ 10 million of potential impact to us, and, in some cases, qualitative criteria according to the materiality of the plausible effect on the conduct of our business. The lawsuit status includes a general description, the process status and the estimate of the amount involved in each lawsuit.

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Dividend Policy

Our Board of Directors presents an annual proposal for approval to the GSM for a  final dividend payable each year. The dividend is accrued in the prior year and cannot be less than the legal minimum of 30% of annual net income. The proposal also states the dividend policy for the current fiscal year. Additionally, our Board of Directors generally establishes an interim dividend for the current fiscal year, payable in January of the following year and deducted from the final dividend payable in May of the next year. The Board of Directors establishes the interim dividend, which is not subject to restrictions under Chilean law.

For dividends accrued in fiscal year 2018, on November 26, 2018, the Board of Directors agreed to distribute an interim dividend of Ch$ 0.452360 per share of common stock on January 25, 2019, or 15% of consolidated net income as of September 30, 2018. At the GSM held on April 29, 2019, our shareholders approved a final dividend equivalent to Ch$ 3.13773 per share of common stock for fiscal year 2018, of which Ch$ 2.68537 per share was distributed on May 17, 2019, after deducting the interim dividend paid in January 2019. The final dividend amounts to a payout ratio of 60% of annual consolidated net income for fiscal year 2018.

For dividends accrued in fiscal year 2019, on November 26, 2019, the Board of Directors agreed to distribute an interim dividend of Ch$ 0.447231 per share of common stock on January 31, 2020, or 15% of consolidated net income as of September 30, 2019. At the GSM held on April 29, 2020, our shareholders approved a final dividend equivalent to Ch$ 2.569047 per share of common stock for fiscal year 2019, of which Ch$ 2.121816 per share of common stock will be distributed on May 27, 2020, after deducting the interim dividend paid in January 2020. The final dividend amounted to a payout ratio of 60% of annual consolidated net income for fiscal year 2019.  In addition to the final dividend for fiscal year 2019, at the GSM held on April 29, 2020, our shareholders approved an additional dividend equivalent to Ch$  1.660963 per share of common stock, which will be distributed simultaneously with the final dividend for fiscal year 2019 and will be paid against retained consolidated earnings from prior fiscal years.

For dividends relating to fiscal year 2020, our Board of Directors presented to the GSM held on April 29, 2020 the following proposed dividend policy:

An interim dividend, accrued in fiscal year 2020 and amounting to 15% of consolidated net income as of September 30, 2020, to be paid in January 2021.

A  final dividend payout equal to 60% of annual net income for fiscal year 2020, to be paid in May 2021 from which the interim dividend paid in January 2021 will be deducted.

This dividend policy is conditional on generating net profits in each period, as well as to expectations of future profit levels and other conditions that may exist at the time of such dividend declaration. The proposed dividend policy is subject to our Board of Director’s right to change the amount and timing of the dividends under prevailing circumstances at the time of the payment.

Dividend payments are potentially subject to legal restrictions, such as the requirement to pay dividends from either net income or retained earnings of the fiscal year. There may also be other contractual restrictions, such as non-default on credit agreements. However, these potential legal and contractual restrictions do not currently affect our ability or any of our subsidiaries’ ability to pay dividends. For additional information, see “Item 5. Operating and Financial Review and Prospects — B. Liquidity and Capital Resources”.

Shareholders of each subsidiary and affiliate agree on the final dividend payments. Dividends are paid to shareholders of record as of midnight of the fifth business day before the payment date. Holders of ADSs on the applicable record dates will be entitled to receive dividend payments.

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Dividends

The table below sets forth, for each of the years indicated, the dividends distributed by us in Chilean pesos per common share and U.S. dollars per ADS. For additional information, see “Item 10. Additional Information — D. Exchange Controls.”

	Dividendsdistributed(1)
Year	Ch$ per Share	US$per ADS(2)
2019	3.14	0.21
2018	2.99	0.22
2017	3.23	0.26
2016	2.09	0.17

(1) This table shows dividends paid rather than dividends accrued within any given year. These amounts do not reflect a reduction for Chilean withholding taxes, if applicable. Figures have been rounded.

(2) The U.S. dollar per ADS amount was calculated by applying the exchange rate as of December 31 of each year. One ADS = 50 shares of common stock.

For a discussion of Chilean withholding taxes and access to the formal currency market in Chile in connection with the payment of dividends and sales of ADSs and the underlying common stock, see “Item 10. Additional Information — E. Taxation” and “Item 10. Additional Information — D. Exchange Controls”.

B.Significant Changes

None.

Item 9.The Offer and Listing

A.Offer and Listing Details.

Our shares of common stock are listed and traded on the Chilean Stock Exchanges under the trading symbol “ENELCHILE,” and our ADSs are listed and traded on the NYSE under the trading symbol “ENIC.”

B.Plan of Distribution.

Not applicable.

C.Markets.

In Chile, our common stock is traded on the following stock exchanges: the Bolsa de Santiago (Santiago Stock Exchange or “SSE”) and the Bolsa Electrónica de Chile (Electronic Stock Exchange or “ESE”). As of December 31, 2019, more than 200 companies had shares listed on the SSE. As of December 31, 2019, the SSE accounted for 91.9 % of our total equity traded in Chile and amounted to 14,739,170,784 shares. Also, 8.1% of our equity trading was conducted on the ESE, an electronic trading market that was created by banks and non-member brokerage houses.  

Equities, closed-end funds, fixed-income securities, short-term and money market securities, gold, U.S. dollars, and futures contracts for stock indices and U.S. dollars trade on the SSE. It operates on business days from 9:30 a.m. to 4:00 p.m. from March to October, and from 9:30 a.m. to 5:00 p.m. from November to February, which may differ from New York City time by up to two hours, depending on the season.

In August 2016, the SSE and the S&P Dow Jones Indices (“S&P DJI”) signed an Operating Agreement and Index Licensing. The alliance between the SSE and the S&P DJI, the leading global provider of concepts, data, and research on indices, includes the implementation of international methodological standards and the integration of operational processes and business strategies that enhance the visibility, governance, and transparency of the existing indices. The

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agreement also enables the development, granting of licenses, distribution, and administration of current and future indices, which are developed as innovative and practical tools at the service of local and international investors. The SSE indices will use the shared brand “S&P/CLX” and may be used as underlying liquid financial products, thereby contributing to the expansion and depth of the Chilean capital markets. Under this agreement, S&P DJI assumed the tasks of calculation, production, maintenance, licensing, and distribution of the indices on August 6, 2018. Since that date, the IGPA and the IPSA, the former general and selective stock indices, are referred to as the SPCLXIGPA and the SPCLXIPSA, respectively.

The SPCLXIGPA is calculated considering, among other things, the prices of the shares traded during at least 25% of the days of the year, with a total of annual transactions exceeding UF 10,000 (approximately US$ 378,000 as of December 31, 2019) and a free float of at least 5%. The SPCLXIGPA index is rebalanced annually, after the close of the third Friday in March, and the number of shares per component of the index is updated quarterly after the close of the third Friday in June, September, and December. On December 31, 2019, the SPCLXIGPA index closed at 23,393.53 points.

Our common stock trades in the United States in the form of ADSs on the NYSE by way of “when-issued” trading since April 21, 2016, under the trading symbol “ENIC WI” and regular-way trading since April 27, 2016, under the trading symbol “ENIC.” Each ADS represents 50 shares of common stock, with the ADSs in turn evidenced by American Depositary Receipts (“ADRs”). The ADRs were issued under a Deposit Agreement dated April 26, 2016, between us, Citibank, N.A. acting as Depositary (the “Depositary”), and the holders and beneficial owners from time to time of ADRs issued thereunder, which was amended on February 14, 2018 (the “Deposit Agreement”). The Depositary treats only persons in whose names ADRs are registered on the books of the Depositary as owners of ADRs.

As of March 31, 2020, ADRs evidencing 52,656,738 ADSs (equivalent to 2,632,836,923 shares of common stock) were outstanding, representing 3.81% of the total number of outstanding shares. It is not practicable for us to determine the proportion of ADSs beneficially owned by U.S. final beneficial holders. The trading volume of our shares on the NYSE and other exchanges during 2019 amounted to 88 million ADSs, equivalent to US$ 403 million.

The NYSE is open for trading Monday through Friday from 9:30 am to 4:00 pm, except for holidays declared in advance by the NYSE. On the trading floor, the NYSE trades in a continuous auction format, where traders can execute stock transactions on behalf of investors. Specialist brokers act as auctioneers in an open outcry auction market to bring buyers and sellers together and to manage the actual auction. Customers can also send orders for immediate electronic execution or route orders to the floor for trade in the auction market. The NYSE works with U.S. regulators, such as the SEC and the Commodity Futures Trading Commission, to coordinate risk management measures in the electronic trading environment through the implementation of mechanisms such as circuit breakers and liquidity replenishment points.

The following table contains information regarding the amount of total traded shares of common stock and the corresponding percentage traded per market during 2019:

	Numberof common shares traded	Percentage of Shares Traded
Market
Chile (1)	16,021,968,164	78%
United States (One ADS = 50 shares of common stock) (2)	4,405,247,400	22%
Total	20,427,215,564	100%

(1)Includes SSE and ESE

(2)Includes the NYSE and over-the-counter trading.

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D.Selling Shareholders.

Not applicable.

E.Dilution.

Not applicable.

F.Expenses of the Issue.

Not applicable.

Item 10.Additional Information

A.Share Capital.

Not applicable.

B.Memorandum and Articles of Association.

Description of Share Capital

Set forth below is certain information concerning our share capital and a brief summary of certain significant provisions of Chilean law and our bylaws.

General

Shareholders’ rights in Chilean companies are governed by the company’s bylaws (estatutos), which have the same purpose as the articles or the certificate of incorporation and the bylaws of a company incorporated in the United States and by the Chilean Corporations Law. In addition, D.L. 3500, or the Pension Fund System Law, which permits the investment by Chilean pension funds in stock of qualified companies, indirectly affects corporate governance and prescribes certain rights of shareholders. In accordance with the Chilean Corporations Law, legal actions by shareholders to enforce their rights as shareholders of the company must be brought in Chile in arbitration proceedings or, at the option of the plaintiff, before Chilean courts. Members of the Board of Directors, managers, officers and principal executives of the company, or shareholders that individually own shares with a book value or stock value higher that UF 5,000 (Ch$ 142 million as of December 31, 2019) do not have the option to bring the procedure to the courts.

The Chilean securities markets are principally regulated by the CMF under the Securities Market Law (Law No. 18,045) and the Chilean Corporations Law. These two laws state the disclosure requirements, restrictions on insider trading and price manipulation, and provide protection to minority shareholders. The Securities Market Law sets forth requirements for public offerings, stock exchanges and brokers, and outlines disclosure requirements for companies that issue publicly offered securities. The Chilean Corporations Law and the Securities Market Law, both as amended, state rules regarding takeovers, tender offers, transactions with related parties, qualified majorities, share repurchases, directors’ committees, independent directors, stock options and derivative actions.

Public Register

We are a publicly held stock corporation incorporated under the laws of Chile. We were incorporated by public deed issued on January 8, 2016 by the Santiago Notary Public, Mr. Iván Torrealba A., and registered on January 19, 2016, in the Commercial Register (Registro de Comercio del Conservador de Bienes Raíces y Comercio de Santiago) on pages 4288 No. 2570. Our registry in the Securities Registry of the CMF was approved by the CMF on April 13, 2016, under the entry number 1139. We are also registered with the United States Securities and Exchange Commission under the commission file number 001‑37723 on March 31, 2016.

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Reporting Requirements Regarding Acquisition or Sale of Shares

Under Article 12 of the Securities Market Law and General Rule No. 269 of the CMF, certain information regarding transactions in shares of a publicly held stock corporation or in contracts or securities whose price or financial results depend on, or are conditioned in whole or in a significant part on the price of such shares, must be reported to the CMF and the Chilean Stock Exchanges. Since ADSs are deemed to represent the shares of common stock underlying the ADRs, transactions in ADRs will be subject to these reporting requirements and those established in Circular No. 1375 of the CMF. Shareholders of publicly held stock corporations are required to report to the CMF and the Chilean Stock Exchanges:

· any direct or indirect acquisition or sale of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

· any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a holder who owns, directly or indirectly, at least 10% of a publicly held stock corporation’s subscribed capital;

· any direct or indirect acquisition of shares made by a holder who, due to an acquisition of shares of such publicly held stock company, results in the holder acquiring, directly or indirectly, at least 10% of a publicly held stock company’s subscribed capital;

· any direct or indirect acquisition or sale of shares in any amount, made by a director, receiver, principal executive, general manager or manager of a publicly held stock corporation; and

· any direct or indirect acquisition or sale of contracts or securities whose price or financial results depend on or are conditioned in whole or in a significant part on the price of shares made by a director, receiver, principal executive, general manager or manager of a publicly held stock corporation.

In addition, majority shareholders of a publicly held stock corporation must inform the CMF and the Chilean stock exchanges if such acquisitions are entered into with the intention of acquiring control of the company or if they are making a passive financial investment instead.

Under Article 54 of the Securities Market Law and General Rule No.104 enacted by the CMF, unless the tender offer regulation applies, any person who directly or indirectly intends to take control of a publicly held stock corporation must disclose this intent to the market at least ten business days in advance of the proposed change of control and, in any event, as soon as the negotiations for the change of control have taken place or reserved information of the publicly held stock corporation has been provided.

Corporate Objectives and Purposes

Article 4 of our bylaws states that our corporate objectives and purposes are, among other things, to conduct the exploration, development, operation, generation, distribution, transformation, or sale of energy in Chile in any form, directly or through other companies, as well as to provide engineering-consulting services related to these objectives and to make loans to related companies, subsidiaries and affiliates.

Board of Directors

Our Board of Directors consists of seven members who are appointed by shareholders at a GSM and are elected for a three-year term, at the end of which they will be re-elected or replaced. The seven directors elected at the GSM are the seven individual nominees who receive the highest majority of the votes, provided one of those individuals must be an independent director.  Each shareholder may vote his shares in favor of one nominee or may apportion his shares among any number of nominees.  The effect of these voting provisions is to ensure that a shareholder owning more than 12.5% of our shares is guaranteed to be able to elect a member of the Board. Depending on the distribution of the rest of the votes at the GSM, a director may in some cases be elected with the votes of less than 12.5% of our shares. This

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number is derived from the reciprocal of the number of directors plus one. In our case, there are seven directors, and the reciprocal of eight is equal to 12.5%.

The compensation of the directors is established annually at the GSM. See “Item 6. Directors, Senior Management and Employees — B. Compensation”.

Agreements entered into by us with related parties can only be executed when such agreements serve our interest, and their price, terms and conditions are consistent with prevailing market conditions at the time of their approval and comply with all the requirements and procedures indicated in Article 147 of the Chilean Corporations Law.

Certain Powers of the Board of Directors

Our bylaws provide that every agreement or contract that we enter into with our controlling shareholder, our directors or executives, or their related parties, must be previously approved by two thirds of the Board of Directors and be included in the Board meetings, and must comply with the provisions of the Chilean Corporations Law.

Our bylaws do not contain provisions relating to:

· the directors’ power, in the absence of an independent quorum, to vote on compensation for themselves or any members of their body;

· borrowing powers exercisable by the directors and how such borrowing powers can be changed;

· retirement or non-retirement of directors under an age limit requirement; or

· number of shares, if any, required for directors’ qualification.

Certain Provisions Regarding Shareholder Rights

As of the date of this Report, our capital is comprised of only one class of shares, all of which are common shares and have the same rights.

Our bylaws do not contain any provisions relating to:

· redemption provisions;

· sinking funds; or

· liability for capital reductions by us.

Under Chilean law, the rights of our shareholders may only be modified by an amendment to the bylaws that complies with the requirements explained below under “Item 10. Additional Information — B. Memorandum and Articles of Association. — Shareholders’ Meetings and Voting Rights”.

Capitalization

Under Chilean law, only the shareholders of a company acting at an ESM have the power to authorize a capital increase. When an investor subscribes shares, these are officially issued and registered under his name, and the subscriber is treated as a shareholder for all purposes, except receipt of dividends and for return of capital in the event that the shares have been subscribed but not paid for. The subscriber becomes eligible to receive dividends only for the shares that he has actually paid for or, if the subscriber has paid for only a portion of such shares, the pro rata portion of the dividends declared with respect to such shares unless the company’s bylaws provide otherwise. If a subscriber does not fully pay for shares for which the subscriber has subscribed on or prior to the date agreed upon for payment, notwithstanding the actions intended by the company to collect payment, the company is entitled to auction on the stock

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exchange where such shares are traded, for the account and risk of the debtor, the number of shares held by the debtor necessary for the company to pay the outstanding balances and disposal expenses. However, until such shares are sold at auction, the subscriber continues to hold all the rights of a shareholder, except the right to receive dividends and return of capital. The Chief Executive Officer, or the person replacing him, will reduce the number of shares in the name of the debtor shareholder in the shareholders’ register to the number of shares that remain, deducting the shares sold by the company and settling the debt in the amount necessary to cover the result of such disposal after expenses.

When there are authorized and issued shares for which full payment has not been made within the period fixed by shareholders at the same ESM at which the subscription was authorized (which may not exceed three years from the date of such meeting, unless a stock option plan is approved, in which case the period to pay for the shares under such plan may be up to five years), these shall be reduced in the non-subscribed amount until that date. With respect to the shares subscribed and not paid following the term mentioned above, the Board must proceed to collect payment, unless the shareholders’ meeting authorizes the Board not to do so (by two thirds of the voting shares), in which case the capital shall be reduced by force of law to the amount effectively paid. Once collection actions have been exhausted, the Board should propose to the shareholders’ meeting the approval by simple majority of the write-off of the outstanding balance and the reduction of capital to the amount effectively collected.

As of December 31, 2019, our subscribed and fully paid capital totaled Ch$ 3,882 billion and consisted of 69,166,557,220 shares.

Preemptive Rights and Increases of Share Capital

With the exception of capital increases needed to carry out a merger, Chilean law requires Chilean publicly held stock corporations to grant shareholders preemptive rights to purchase a sufficient number of shares, or any other securities convertible into shares or that confer future rights over shares, to maintain their existing ownership percentage of such company whenever such company issues new shares, or any other securities convertible into shares or that confer future rights over shares.

Under Chilean law, preemptive rights are exercisable or freely transferable by shareholders during a 30‑day period. The options to subscribe for shares in capital increases of the company or of any other securities convertible into shares or that confer future rights over these shares should be offered at least once to the shareholders pro rata based on the number of shares held registered in their name at midnight on the fifth business day prior to the date of the start of the preemptive rights period. The preemptive rights offering and the start of the 30‑day period for exercising them shall be communicated through the publication of a prominent notice, at least once, in the newspaper used for notifications of shareholders’ meetings. During such 30‑day period, and for an additional period of at least 30 days immediately following the initial 30‑day period, if any, publicly held stock corporations are not permitted to offer any unsubscribed shares to third parties on terms that are more favorable than those offered to their shareholders. At the end of the second 30‑day period, a Chilean publicly held stock corporation is authorized to sell unsubscribed shares to third parties under any terms, provided they are sold on one of the Chilean Stock Exchanges.

Shareholders’ Meetings and Voting Rights

A GSM must be held within the first four months following the end of our fiscal year. Our last GSM was held on April 29, 2020. An ESM may be summoned by the Board of Directors when deemed appropriate, and an ESM or a GSM, as the case may be, must be summoned when requested by shareholders representing at least 10% of the issued shares with voting rights, or by the CMF. To convene a GSM or an ESM, notice must be given three times in a newspaper located in our corporate domicile. The newspaper designated by our shareholders is El Mercurio de Santiago. The first notice must be published not less than 15 days and no more than 20 days in advance of the scheduled meeting. Notice must also be mailed to each shareholder, the CMF, the Chilean Stock Exchanges and the Depositary for our ADRs.

The GSM shall be held on the day stated in the notice and should remain in session until having exhausted all the matters stated in the notice.  However, once constituted, upon the proposal of the chairman or shareholders representing at least 10% of the shares with voting rights, the majority of the shareholders present may agree to suspend it and to

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continue it within the same day and place, with no new constitution of the meeting or qualification of powers being necessary, recorded in one set of minutes. Only those shareholders who were present or represented may attend the recommencement of the meeting with voting rights.

Under Chilean law, a quorum for a shareholders’ meeting is established by the presence, in person or by proxy, of shareholders representing at least a majority of the issued shares with voting rights of a company.  If a quorum is not present at the first meeting, a reconvened meeting can take place at which the shareholders present are deemed to constitute a quorum regardless of the percentage of the shares represented.  This second meeting must take place within 45 days following the scheduled date for the first meeting. Shareholders’ meetings adopt resolutions by the affirmative vote of a majority of those shares present or represented at the meeting, unless a higher majority is required, as described below.  

Regardless of the quorum present, the vote required to adopt any of the following actions is at least two-thirds of the outstanding shares with voting rights at an ESM called to approve these matters:

a transformation of the company into a form other than a publicly held stock corporation under the Chilean Corporations Law, a merger or split-up of the company;

an amendment to the term of duration or early dissolution of the company;

a change in the company’s domicile;

a decrease of corporate capital;

an approval of capital contributions in kind and non-monetary assessments;

a modification of the authority reserved to shareholders or limitations on the Board of Directors;

a reduction in the number of members of the Board of Directors;

a disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater that such percentage;

the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the corporation, as well as any disposition of its shares that results in the parent company losing its position as controlling shareholder;

the form of distributing corporate benefits;

issue of guarantees for third-party liabilities which exceed 50% of the assets, except when the third party is a subsidiary of the company, in which case approval of the Board of Directors is deemed sufficient;

the purchase of the company’s own shares;

other actions established by the bylaws or the laws;

certain remedies for the nullification of the company’s bylaws;

inclusion in the bylaws of the right to purchase shares from minority shareholders, when the controlling shareholders reaches 95% of the company’s shares by means of a tender offer for all of the company’s shares, where at least 15% of the shares have been acquired from unrelated shareholders; and

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approval or ratification of acts or contracts with related parties.

In addition, certain amendments to our bylaws require the affirmative vote of 75% of the outstanding shares with voting rights.

Bylaw amendments for the creation of a new class of shares, or an amendment to or an elimination of those classes of shares that already exist, must be approved by at least two-thirds of the outstanding shares of the affected series.

Chilean law does not require a publicly held stock corporation to provide its shareholders the same level and type of information required by the U.S. securities laws regarding the solicitation of proxies.  However, shareholders are entitled to examine the financial statements and corporate books of a publicly held stock corporation and its subsidiaries within the 15-day period before its scheduled shareholders’ meetings.  Under Chilean law, a notice of a shareholders meeting listing matters to be addressed at the meeting must be mailed at least 15 days prior to the date of such meeting, indicating how to complete copies of the documents that support the matters submitted for voting can be obtained, which must also be made available to shareholders on our website.  In the case of a GSM, our annual report of activities, which includes audited financial statements, must also be made available to shareholders and published on our website at: www.enelchile.cl.

The Chilean Corporations Law provides that, upon the request by the Directors’ Committee or by shareholders representing at least 10% of the issued shares with voting rights, a Chilean company’s annual report must include, in addition to the materials provided by the Board of Directors to shareholders, such shareholders’ comments and proposals in relation to the company’s affairs.  In accordance with Article 136 of the Chilean Corporations Regulation (Reglamento de Sociedades Anónimas), the shareholder(s) holding or representing at least 10% of the shares issued with voting rights, may:

make comments and proposals relating to the progress of the corporate businesses in the corresponding year, no shareholder being able to make individually or jointly more than one presentation.  These observations should be presented in writing to the company concisely, responsibly and respectfully, and the respective shareholder(s) should state their willingness for these to be included as an appendix to the annual report.  The Board shall include in an appendix to the annual report of the year a faithful summary of the pertinent comments and proposals the interested parties had made, provided they are presented during the year or within 30-days after its ending; or

make comments and proposals on matters that the Board submits for the knowledge or voting of the shareholders.  The Board shall include a faithful summary of those comments and proposals in all information it sends to shareholders, provided the shareholders’ proposal is received at the offices of the company at least 10-days prior to the date of dispatch of the information by the company. 

The shareholders should present their comments and proposals to the company, expressing their willingness for these to be included in the appendix to the respective annual report or in information sent to shareholders, as the case may be.  The observations referred to in Article 136 may be made separately by each shareholder holding at least 10% of the shares issued with voting rights or shareholders who together hold that percentage, who should act as one.

Similarly, the Chilean Corporations Law provides that whenever the Board of Directors of a publicly held stock corporation convenes a GSM or ESM and solicits proxies for the meeting, or circulates information supporting its decisions or other similar material, it is obligated to include the pertinent comments and proposals that may have been made by the Directors’ Committee or by shareholders owning at least 10%  of the shares with voting rights who request that such comments and proposals be so included.

Only shareholders registered as such with us as of midnight on the fifth business day prior to the date of a meeting are entitled to attend and vote their shares.  A shareholder may appoint another individual, who does not need to be a shareholder, as his proxy to attend the meeting and vote on his behalf.  Proxies for such representation shall be given for all the shares held by the owner.  The proxy may contain specific instructions to approve, reject, or abstain with respect

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to any of the matters submitted for voting at the meeting and which were included in the notice.  Every shareholder entitled to attend and vote at a shareholders’ meeting shall have one vote for every share subscribed.

There are no limitations imposed by Chilean law or our bylaws on the right of nonresidents or foreigners to hold or vote shares of common stock. However, the registered holder of the shares of common stock represented by ADSs, and evidenced by outstanding ADSs, is the custodian of the Depositary, currently Banco Santander-Chile, or any successor thereto. Accordingly, holders of ADSs are not entitled to receive notice of meetings of shareholders directly or to vote the underlying shares of common stock represented by ADS directly. The Deposit Agreement contains provisions pursuant to which the Depositary has agreed to request instructions from registered holders of ADSs as to the exercise of the voting rights pertaining to the shares of common stock represented by the ADSs. Subject to compliance with the requirements of the Deposit Agreement and receipt of such instructions, the Depositary has agreed to endeavor, insofar as practicable and permitted under Chilean law and the provisions of the bylaws, to vote or cause to be voted (or grant a discretionary proxy to the Chairman of the Board of Directors or to a person designated by the Chairman of the Board of Directors to vote) the shares of common stock represented by the ADSs in accordance with any such instruction.  The Depositary shall not itself exercise any voting discretion over any shares of common stock underlying ADSs. If no voting instructions are received by the Depositary from a holder of ADSs with respect to the shares of common stock represented by the ADSs, on or before the date established by the Depositary for such purpose, the shares of common stock represented by the ADS may, in some situations, be voted in the manner directed by the Chairman of the Board, or by a person designated by the Chairman of the Board, subject to limitations set forth in the Deposit Agreement.

Dividends and Liquidation Rights

According to the Chilean Corporations Law, unless otherwise decided by unanimous vote of its issued shares eligible to vote, all publicly held stock corporations must distribute a cash dividend in an amount equal to at least 30% of their consolidated net income, unless and except to the extent we have carried forward losses. The law provides that the Board of Directors must agree to the dividend policy and inform such policy to the shareholders at the GSM.

For any dividend in excess of 30% of net income, a publicly held stock corporation may grant an option to its shareholders to receive those dividends, in cash, or in shares issued by such publicly held stock corporation, or in shares of publicly held corporations owned by such company. Shareholders who do not expressly elect to receive a dividend other than in cash are legally presumed to have decided to receive the dividend in cash.

Dividends that are declared but not paid within the appropriate time period set forth in the Chilean Corporations Law (30 days after declaration for minimum dividends, and the date set for payment at the time of declaration for additional dividends) are adjusted to reflect the change in the value of the UF from the date set for payment to the date such dividends are actually paid. Such dividends also accrue interest at the then-prevailing rate for UF-denominated deposits during such period. The right to receive a dividend lapses if it is not claimed within five years from the date such dividend is payable. Payments not collected in such period are transferred to the volunteer fire department.

In the event of our liquidation, the shareholders would participate in the assets available in proportion to the number of paid-in shares held by them, after payment to all creditors.

Approval of Financial Statements

The Board of Directors is required to submit our consolidated financial statements to the shareholders annually for their approval. If the shareholders at the shareholders’ meeting reject the financial statements by a vote of a majority of shares present (in person or by proxy), the Board of Directors must submit new financial statements no later than 60 days from the date of such meeting. If the shareholders reject the new financial statements, the entire Board of Directors is deemed removed from office and a new board is elected at the same meeting. Directors who individually approved such financial statements are disqualified for reelection for the following period. Our shareholders have never rejected the financial statements presented by the Board of Directors.

Change of Control

The Capital Markets Law establishes a comprehensive regulation related to tender offers. The law defines a tender offer as the offer to purchase shares of companies that publicly offer their shares or convertible securities and which

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offer is made to shareholders to purchase their shares under conditions that allow the bidder to reach a certain percentage of ownership of the company within a fixed period. These provisions apply to both voluntary and hostile tender offers.

Acquisition of Shares

No provision in our bylaws discriminates against any existing or prospective holder of shares as a result of such shareholder owning a substantial number of shares. However, no person may directly or indirectly own more than 65% of the outstanding shares of our stock. The foregoing restriction does not apply to the depositary as record owner of shares represented by ADRs, but it does apply to each beneficial ADS holder. Additionally, our bylaws prohibit any shareholder from exercising voting power with respect to more than 65% of the common stock owned by such shareholder or on behalf of others representing more than 65% of the outstanding issued shares with voting rights.

Right of Dissenting Shareholders to Tender Their Shares

The Chilean Corporations Law provides that upon the adoption of any of the resolutions enumerated below at a meeting of shareholders, dissenting shareholders acquire the right to withdraw from the company and to compel the company to repurchase their shares, subject to the fulfillment of certain terms and conditions. In order to exercise such withdrawal rights, holders of ADRs must first withdraw the shares represented by their ADRs pursuant to the terms of the Deposit Agreement. In case of a bankruptcy proceeding, the withdrawal right arising from an adopted resolution is suspended until the existing debt has been paid.

“Dissenting” shareholders are defined as those who at a shareholders’ meeting vote against a resolution that results in the withdrawal right, or who if absent from such meeting, state in writing their opposition to the respective resolution, within the 30 days following the shareholders’ meeting. Shareholders present or represented at the meeting and who abstain in exercising their voting rights shall not be considered as dissenting. The right to withdraw should be exercised for all the shares that the dissenting shareholder had registered in their name on the date on which the right is determined to participate in the meeting at which the resolution is adopted that motivates the withdrawal and which remains on the date on which their intention to withdraw is communicated to the company.

The price paid to a dissenting shareholder of a publicly held stock corporation whose shares are quoted and actively traded on one of the Chilean stock exchanges is the weighted average of the sales prices for the shares as reported on the Chilean stock exchanges on which the shares are quoted for the 60-trading-day period between the ninetieth and the thirtieth trading day before the shareholders’ meeting giving rise to the withdrawal right. If the CMF determines that the shares are not actively traded on a stock exchange, the price paid to the dissenting shareholder shall be the book value. Book value for this purpose is equal to the company’s equity attributable to the parent company, divided by the total number of subscribed shares, whether entirely or partially paid. For the purpose of making this calculation, the last consolidated statement of financial position is used, as adjusted to reflect inflation up to the date of the shareholders’ meeting which gave rise to the withdrawal right.

Article 126 of the Chilean Corporations Regulation establishes that in cases where the right to withdraw arises, the company shall be obliged to inform the shareholders of this situation, the value per share that will be paid to shareholders exercising their right to withdraw and the term for exercising it. Such information should be given to shareholders at the same meeting at which the resolutions are adopted giving rise to the right of withdrawal, prior to its voting. A special communication should be given to the shareholders with rights, within two days following the date on which the rights to withdraw arise. In the case of publicly held companies, such information shall be communicated by a prominent notice in a newspaper with a wide national circulation and on its website, plus a written communication addressed to the shareholders with rights at the address they have registered with the company. The notice of the shareholders’ meeting that to vote on a matter that could give rise to withdrawal rights should mention this circumstance.

The resolutions that result in a shareholder’s right to withdraw include, among others, the following:

· the transformation of the company into an entity which is not a publicly held stock corporation governed by Chilean Corporations Law;

· the merger of the company with another company;

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· disposition of 50% or more of the assets of the company, whether it includes disposition of liabilities or not, as well as the approval or the amendment of the business plan which contemplates the disposition of assets in an amount greater than such percentage;

· the disposition of 50% or more of the assets of a subsidiary, as long as such subsidiary represents at least 20% of the assets of the company, as well as any disposition of its shares that results in the parent company losing its position of controlling shareholder;

· issue of guarantees for third parties’ liabilities that exceed 50% of the assets (if the third party is a subsidiary of the company, the approval of the Board of Directors is sufficient and will not give rise to the right to withdraw);

· the creation of preferential rights for a class of shares or an amendment to the existing ones. In this case the right to withdraw only accrues to the dissenting shareholders of the class or classes of shares adversely affected;

· certain remedies for the nullification of the corporate bylaws; and

· such other causes as may be established by the law or by the company’s bylaws.

Investments by AFPs

The Pension Fund System Law permits AFPs to invest their funds in companies that are subject to Title XII of such law, and these companies are subject to greater restrictions than other companies. The determination of which stocks may be purchased by AFPs is made by the Risk Classification Committee. The Risk Classification Committee establishes investment guidelines and is empowered to approve or disapprove those companies that are eligible for AFP investments. We are and have been subject to Title XII provisions and are approved by the Risk Classification Committee.

Companies subject to Title XII provisions are required to have bylaws that:

· limit the ownership of any shareholder to a specified maximum percentage, currently 65%;

· require that certain actions be taken only at a meeting of the shareholders; and

· give the shareholders the right to approve certain investment and financing policies.

Registrations and Transfers

Shares issued by us are registered with an administrative agent, which is DCV Registros S.A. This entity is also responsible for our shareholders registry. In case of jointly-owned shares, an attorney-in-fact must be appointed to represent the joint owners in dealing with us.

C.Material Contracts.

None.

D.Exchange Controls.

The Central Bank of Chile is responsible for, among other things, monetary policies and exchange controls in Chile. Currently applicable foreign exchange regulations are set forth in the Compendium of Foreign Exchange Regulations (the “Compendium”) approved by the Central Bank of Chile.

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a)Chapter XIV

The following is a summary of certain provisions of Chapter XIV of the Compendium that are applicable to all existing shareholders (and ADS holders). This summary does not intend to be complete and is qualified in its entirety by reference to Chapter XIV. Chapter XIV regulates the following type of investments: credits, deposits, investments and equity contributions. A Chapter XIV investor may at any time repatriate an investment made in us upon sale of our shares, and the profits derived therefrom, with no monetary ceiling, subject to the then effective regulations, which must be reported to the Central Bank of Chile.

Except for compliance with tax regulations and some reporting requirements, currently there are no rules in Chile affecting repatriation rights, except that the remittance of foreign currency must be made through a Formal Exchange Market entity. However, the Central Bank of Chile has the authority to change such rules and impose exchange controls.

b)The Compendium and International Bond Issuances

Chilean issuers may offer bonds internationally, subject to the reporting requirements set forth in Chapter XIV of the Compendium.

E. Taxation.

Chilean Tax Considerations

The following discussion summarizes material Chilean income and withholding tax consequences to foreign holders arising from the ownership and disposition of shares and ADSs. The summary that follows does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a decision to purchase, own or dispose of shares or ADSs, if any, and does not purport to deal with the tax consequences applicable to all categories of investors, some of which may be subject to special rules. Holders of shares and ADSs are advised to consult their own tax advisors concerning the Chilean and other tax consequences of the ownership of shares or ADSs.

The summary that follows is based on Chilean law, in effect on the date hereof, and is subject to any changes in these or other laws occurring after such date, possibly with retroactive effect. Under Chilean law, provisions contained in statutes such as tax rates applicable to foreign investors, the computation of taxable income for Chilean purposes and the manner in which Chilean taxes are imposed and collected may be amended only by another law. In addition, the Chilean tax authorities enact rulings and regulations of either general or specific application and interpret the provisions of the Chilean Income Tax Law. Chilean tax may not be assessed retroactively against taxpayers who act in good faith relying on such rulings, regulations and interpretations, but Chilean tax authorities may change their rulings, regulations and interpretations in the future. The discussion that follows is also based, in part, on representations of the depositary, and assumes that each obligation in the Deposit Agreement and any related agreements will be performed in accordance with its terms. As of this date, there is currently no applicable income tax treaty in effect between the United States and Chile. However, in 2010 the United States and Chile signed an income tax treaty that will enter into force once the treaty is ratified by both countries, which has not happened as of the date of this Report. There can be no assurance that the treaty will be ratified by either country. The following summary assumes that there is no applicable income tax treaty in effect between the United States and Chile.

As used in this Report, the term “foreign holder” means either:

· In the case of an individual holder, a person who is not a resident of Chile. For purposes of Chilean taxation, (a) an individual is a Chilean resident if he has resided in Chile for more than six months in one calendar year, or a total of more than six months in two consecutive fiscal years; or (b) an individual is domiciled in Chile if he resides in Chile and has the intention of remaining in Chile (such intention to be evidenced by circumstances such as the acceptance of employment in Chile or the relocation of the individual’s family to Chile), or

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· in the case of a legal entity holder, an entity that is not organized under the laws of Chile, unless the shares or ADSs are assigned to a branch, agent, representative or permanent establishment of such entity in Chile.

Taxation of Shares and ADSs

Taxation of Cash Dividends and Property Distributions

Cash dividends paid with respect to the shares or ADSs held by a foreign holder will be subject to Chilean withholding tax, which is withheld and paid by the company. The amount of the Chilean withholding tax is determined by applying a 35% rate to a “grossed-up” distribution amount (such amount equal to the sum of the actual distribution amount and the correlative Chilean corporate income tax (“CIT”), paid by the issuer), and then subtracting as a credit 65% of such Chilean CIT paid by the issuer, in case the residence country of the holder of shares or ADSs does not have a tax treaty with Chile. If there is a tax treaty between both countries (in force or signed prior to January 1, 2019) the Foreign Holder can apply 100% of the CIT as a credit. For 2019, the Chilean CIT applicable to us is a rate of 27%, and depending on the circumstances mentioned above, the Foreign Holder may apply 100% or 65% of the CIT as a credit.

There are two alternative mechanisms of shareholder-level income taxation in effect since January 1, 2017: a) accrued income basis (known as attributed-income system in Chile) shareholder taxation and b) cash basis (known as partially-integrated system in Chile) shareholder taxation.

Under the current Chilean Income Tax Law, publicly held limited liability stock companies, such as us, are subject to the latter regime.

Under the cash basis regime (or partially-integrated regime), a company pays CIT on its annual income tax result. Foreign and local individual shareholders will only pay in Chile the relevant tax on effective profit distributions and will be allowed to use the CIT paid by the distributing company as credit, with certain limitations. Only 65% of the CIT is creditable against the 35% shareholder-level tax (as opposed to 100% under the accrued income basis regime). However, in those cases where tax treaties between Chile and the jurisdiction of the shareholder’s residence are signed prior to January 1, 2019 (even if not yet in effect), the CIT is fully creditable against the 35% withholding tax. This is the case with the tax treaty signed between Chile and the United States, which was signed prior to this date, but which is not in effect as of the date of this Report. In the case of treaties signed prior to January 1, 2019, but not ratified as of December 31, 2021, the shareholder may apply 100% of the CIT as a credit if a dividend distribution is made before December 31, 2021, on a transitional basis. Under the Chilean Tax Law in force at the date of this Report, the transitional treatment of applying the full 100% of the CIT as a credit against withholding tax of the U.S. Holders in case of dividend distributions will terminate on December 31, 2021, if the tax treaty between the United States and Chile is not ratified by that date. In that particular case, effective as of January 1, 2022, only 65% of the CIT will be creditable against the 35% U.S. Holders’ tax. On the other hand, if a tax treaty with a foreign jurisdiction is ratified by December 31, 2021, shareholders from that particular jurisdiction can continue to apply 100% of the CIT as a credit beyond such date.

The example below illustrates the effective Chilean withholding tax burden on a cash dividend received by a Foreign Holder, assuming a Chilean withholding tax base rate of 35%, an effective Chilean CIT rate of 27% (the CIT

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rate for 2019 for companies that elected the cash basis regime) and a distribution of 50% of the net income of the company distributable after payment of the Chilean CIT:

Line	Conceptand calculation assumptions	AmountTax treaty resident	Amount Non-tax treaty resident
1	Company taxable income (based on Line 1 = 100)	100	100
2	Chilean corporate income tax: 27% x Line 1	27	27
3	Net distributable income: Line 1—Line 2	73	73
4	Dividend distributed (50% of net distributable income): 50% of Line 3	36.5	36.5
5	Withholding tax: (35% of (the sum of Line 4 and 50% of Line 2))	17.5	17.5
6	Credit for 50% of Chilean corporate income tax : 50% of Line 2	13.5	13.5
7	CIT partial restitution (Line 6 x 35%) (1)	—	4.7
8	Net withholding tax: Line 5 - Line 6 + Line 7	4	8.7
9	Net dividend received: Line 4 - Line 8	32.5	27.8
10	Effective dividend withholding rate: Line 8 / Line 4	11.0	23.9

(i) Only applicable to non-tax treaty jurisdiction resident. From a practical standpoint the foregoing means that the CIT is only partially creditable (65%) against the withholding tax (i.e., CIT of 8.7%).

However, for purposes of the foregoing, the tax authority has not clarified whether the taxpayer residence will be the ADS holder’s address or the depository’s address.

Taxation on sale or exchange of ADSs, outside of Chile

Gains obtained by a foreign holder from the sale or exchange of ADSs outside Chile are not be subject to Chilean taxation.

Taxation on sale or exchange of Shares

The Chilean Income Tax Law includes a tax exemption on capital gains arising from the sale of shares of listed companies traded in stock markets. Although there are certain restrictions, in general terms, the law provides that in order to qualify for the capital gain exemption: (i) the shares must be of a publicly held stock corporation with a “sufficient stock market liquidity” status in the Chilean Stock Exchanges; (ii) the sale must be conducted in a Chilean Stock Exchange authorized by the CMF, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law or as the consequence of a contribution to a fund as regulated in Section 109 of the Chilean Income Tax Law; (iii) the shares which are being sold must have been acquired on a Chilean Stock Exchange, or in a tender offer subject to Chapter XXV of the Chilean Securities Market Law, or in an initial public offering (due to the creation of a company or to a capital increase), or due to the exchange of convertible publicly offered securities, or due to the redemption of a fund’s quota as regulated in Section 109 of the Chilean Income Tax Law; and (iv) the shares must have been acquired after April 19, 2001. For purposes of considering the ADS’s as convertible publicly offered securities, they should be registered in the Chilean foreign securities registry (unless expressly excluded from such registry by the CMF).

Shares are considered to have a “high presence” in the Chilean Stock Exchanges when (i) they have been traded for a certain number of days at or beyond a volume threshold specified under Chilean law and regulations or (ii) in case the issuer has retained a market maker, in accordance with Chilean law and regulations. As of this date, our shares are considered to have a high presence in the Chilean Stock Exchanges and no market maker has been retained by us. Should our shares cease to have a “high presence” in the Chilean Stock Exchanges, a transfer of our shares may be subject to capital gains taxes from which holders of “high presence” securities are exempted, and which will apply at varying levels depending on the time of the transfer in relation to the date of loss of sufficient trading volume to qualify as a “high presence” security. If our shares regain a “high presence,” the tax exemptions will again be available to holders thereof.

If the shares do not qualify for the exemption, capital gains on their sale or exchange of shares (as distinguished from sales or exchanges of ADSs representing such shares of common stock) could be subject to the general tax regime, with a 27% Chilean CIT, the rate applicable during 2019, and a 35% Chilean withholding tax, the former being creditable against the latter.

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The date of acquisition of the ADSs is the date of acquisition of the shares for which the ADSs are exchanged.

Taxation of Share Rights and ADS Rights

For Chilean tax purposes and to the extent we issue any share rights or ADS rights, the receipt of share rights or ADS rights by a Foreign Holder of shares or ADSs pursuant to a rights offering is a nontaxable event. In addition, there are no Chilean income tax consequences to Foreign Holders upon the exercise or the expiration of the share rights or the ADS rights.

Any gain on the sale, exchange or transfer of any ADS rights by a Foreign Holder is not subject to taxes in Chile.

Any gain on the sale, exchange or transfer of the share rights by a Foreign Holder is subject to a 35% Chilean withholding tax.

Other Chilean Taxes

There is no gift, inheritance or succession tax applicable to the ownership, transfer or disposition of ADSs by foreign holders, but such taxes will generally apply to the transfer at death or by gift of the shares by a foreign holder. There is no Chilean stamp, issue, registration or similar taxes or duties payable by holders of shares or ADSs.

Material U.S. Federal Income Tax Considerations

This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions and final, temporary and proposed Treasury regulations, all as of the date of this Report. These authorities are subject to change, possibly with retroactive effect. This discussion assumes that the depositary’s activities are clearly and appropriately defined so as to ensure that the tax treatment of ADSs will be identical to the tax treatment of the underlying shares.

The following are the material U.S. federal income tax consequences to U.S. Holders (as defined herein) of receiving, owning, and disposing of shares or ADSs, but it does not purport to be a comprehensive description of all of the tax considerations that may be relevant to a particular person’s decision to hold such securities and is based on the assumption stated above under “― Chilean Tax Considerations” that there is no applicable income tax treaty in effect between the United States and Chile. The discussion applies only if the beneficial owner holds shares or ADSs as capital assets for U.S. federal income tax purposes and it does not describe all the tax consequences that may be relevant in light of the beneficial owner’s particular circumstances. For instance, it does not describe all the tax consequences that may be relevant to:

· certain financial institutions;

· insurance companies;

· dealers and traders in securities who use a mark-to-market method of tax accounting;

· persons holding shares or ADSs as part of a “straddle” integrated transaction or similar transaction;

· persons whose functional currency for U.S. federal income tax purposes is not the U.S. dollar;

· partnerships or other entities classified as partnerships for U.S. federal income tax purposes or partners in such partnerships;

· persons liable for the alternative minimum tax;

· tax-exempt organizations;

· persons holding shares or ADSs that own or are deemed to own ten percent or more of our stock; or

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· persons holding shares or ADSs in connection with a trade or business conducted outside of the United States.

Persons or entities described above, including partnerships holding shares or ADSs and partners in such partnerships, should consult their tax advisors as to the particular U.S. federal income tax consequences of holding and disposing of shares or ADSs.

You will be a “U.S. Holder” for purposes of this discussion if you become a beneficial owner of our shares or ADSs and if you are, for U.S. federal income tax purposes:

· a citizen or individual resident of the United States; or

· a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof; or

· an estate, the income of which is subject to U.S. federal income taxation regardless of its source; or

· a trust (i) that validly elects to be treated as a U.S. person for U.S. federal income tax purposes or (ii) if (A) a court within the United States can exercise primary supervision over the administration of the trust and (B) one or more U.S. persons have the authority to control all substantial decisions of the trust.

For U.S. federal income tax purposes, it is generally expected that a U.S. Holder of ADSs will be treated as the beneficial owner of the underlying shares represented by the ADSs. The remainder of this discussion assumes that a U.S. Holder of our ADSs will be treated in this manner for U.S. federal income tax purposes. Accordingly, deposits or withdrawals of shares for ADSs will generally not be subject to U.S. federal income tax.

The U.S. Treasury has expressed concerns that parties to whom ADSs are released before shares are delivered to the depositary (pre-release) or intermediaries in the chain of ownership between beneficial owners and the issuer of the security underlying the ADSs may be taking actions that are inconsistent with the claiming of foreign tax credits for beneficial owners of depositary shares. Such actions would also be inconsistent with the claiming of the reduced tax rate, described below, applicable to dividends received by certain non-corporate beneficial owners. Accordingly, the analysis of the creditability of Chilean taxes, and the availability of the reduced tax rate for dividends received by certain non-corporate holders, each described below, could be affected by actions taken by such parties or intermediaries.

This discussion assumes that we will not be a passive foreign investment company, as described below. The discussion below does not address the effect of any U.S. state, local, estate or gift tax law or non-U.S. tax law or tax considerations that arise from rules of general application to all taxpayers on a U.S. Holder of the shares or ADSs or of any future administrative guidance interpreting provisions thereof.

U.S. Holders should consult their tax advisors with respect to their particular tax consequences of owning or disposing of shares or ADSs, including the applicability and effect of state, local, non-U.S. and other tax laws and the possibility of changes in tax laws, including the effects of any future administrative guidance interpreting provisions thereof.

Taxation of Distributions

The following discussion of cash dividends and other distributions is subject to the discussion below under “Passive Foreign Investment Company Rules.” Distributions received by a U.S. Holder on shares or ADSs, including the amount of any Chilean taxes withheld, other than certain pro rata distributions of shares to all shareholders, will constitute foreign-source income to the extent paid out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions generally will be reported to U.S. Holders as dividends. The amount of dividend income paid in Chilean pesos that a U.S. Holder will be required to include in income will equal the U.S. dollar value of the distributed Chilean peso, calculated by reference to the exchange rate in effect on the date the payment is received, regardless of whether the payment is converted into U.S. dollars on the date of receipt. If the dividend is converted into U.S. dollars on the date of receipt, a U.S. Holder will generally not be required to recognize

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foreign currency gain or loss in respect of the dividend income. A U.S. Holder may have foreign currency gain or loss if the dividend is converted into U.S. dollars after the date of its receipt, which would be ordinary income or loss and would be treated as income from U.S. sources for foreign tax credit purposes. Dividends will be included in a U.S. Holder’s income on the date of the U.S. Holder’s, or in the case of ADSs, the depositary’s, receipt of the dividend.

Subject to certain exceptions for short-term and hedged positions, the discussion above regarding concerns expressed by the U.S. Treasury and the discussion below regarding rules intended to be promulgated by the U.S. Treasury, the U.S. dollar amount of dividends received by a noncorporate U.S. Holder in respect of shares or ADSs generally will be subject to taxation at preferential rates if the dividends are “qualified dividends.” Dividends paid on the ADSs generally will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States (ii) we were not, in the year prior to the year in which the dividend was paid, and is not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”) and (iii) the holder thereof has satisfied certain holding period requirements. The ADSs are listed on the New York Stock Exchange and generally will qualify as readily tradable on an established securities market in the United States so long as they are so listed. We do not expect that we will be treated as having been a PFIC for U.S. federal income tax purposes with respect to our 2019 taxable year. In addition, based on our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our 2020 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior or future taxable year.

Based on existing guidance, it is not entirely clear whether dividends received with respect to shares will be treated as qualified dividends, because the shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to establish that dividends are treated as qualified dividends. Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them. A U.S. Holder should consult its tax advisors to determine whether the favorable rate will apply to dividends it receives and whether it is subject to any special rules that limit its ability to be taxed at this favorable rate.

The amount of a dividend generally will be treated as foreign-source dividend income to a U.S. Holder for foreign tax credit purposes. As discussed in more detail below under “—Foreign Tax Credits,” it is not free from doubt whether Chilean withholding taxes imposed on distributions on shares or ADSs will be treated as income taxes eligible for a foreign tax credit for U.S. federal income tax purposes. If a Chilean withholding tax is treated as an eligible foreign income tax, subject to generally applicable limitations, you may claim a credit against your U.S. federal income tax liability for the eligible Chilean taxes withheld from distributions on shares or ADSs. If the dividends are taxed as qualified dividend income (as discussed above), special rules will apply in determining the amount of the dividend taken into account for purposes of calculating the foreign tax credit limitation. The rules relating to foreign tax credits are complex. U.S. Holders are urged to consult their own tax advisors regarding the treatment of Chilean withholding taxes imposed on distributions on shares or ADSs.

Sale or Other Disposition of Shares or ADSs

If a beneficial owner is a U.S. Holder, for U.S. federal income tax purposes, the gain or loss a beneficial owner realizes on the sale or other disposition of shares or ADSs will be a capital gain or loss, and will be a long term capital gain or loss if the beneficial holder has held the shares or ADSs for more than one year. The amount of a beneficial owner’s gain or loss will equal the difference between the beneficial owner’s tax basis in the shares or ADSs disposed of and the amount realized on the disposition, in each case as determined in U.S. dollars. Such gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. In addition, certain limitations exist on the deductibility of capital losses by both corporate and individual taxpayers.

In certain circumstances, Chilean taxes may be imposed upon the sale of shares (but not ADSs). See “Item 10. Additional Information — E. Taxation — Chilean Tax Considerations — Taxation of Shares and ADSs.”  If a Chilean tax is imposed on the sale or disposition of shares, a beneficial owner that is a U.S. Holder may be eligible to claim a

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credit against its U.S. federal income tax liability for the eligible Chilean taxes withheld pursuant to a sale or disposition of shares or ADSs as discussed in “— Foreign Tax Credits” below.

Foreign Tax Credits

Subject to applicable limitations that may vary depending upon a U.S. Holder’s circumstances and subject to the discussion above regarding concerns expressed by the U.S. Treasury, you may be eligible to claim a credit against your U.S. tax liability for Chilean income taxes (or taxes imposed in lieu of an income tax) imposed in connection with distributions on and proceeds from the sale or other disposition of our shares or ADSs. Chilean dividend withholding taxes generally are expected to be income taxes eligible for the foreign tax credit. The Chilean capital gains tax is likely to be treated as an income tax (or a tax paid in lieu of an income tax) and thus eligible for the foreign tax credit; however, you generally may claim a foreign tax credit only after taking into account any available opportunity to reduce the Chilean capital gains tax, such as the reduction for the credit for Chilean corporate income tax that is taken into account when calculating Chilean withholding tax. If a Chilean tax is imposed on the sale or disposition of our shares or ADSs, and a U.S. Holder does not receive significant foreign source income from other sources, such U.S. Holder may not be able to credit such Chilean tax against its U.S. federal income tax liability. If a Chilean tax is not treated as an income tax (or a tax paid in lieu of an income tax) for U.S. federal income tax purposes, a U.S. Holder would be unable to claim a foreign tax credit for any such Chilean tax withheld; however, a U.S. Holder may be able to deduct such tax in computing its U.S. federal income tax liability, subject to applicable limitations. In addition, instead of claiming a credit, a U.S. Holder may, at the U.S. Holder’s election, deduct such Chilean taxes in computing the U.S. Holder’s taxable income, subject to generally applicable limitations under U.S. law. An election to deduct foreign taxes instead of claiming foreign tax credits applies to all taxes paid or accrued in the taxable year to foreign countries and possessions of the U.S. The calculation of foreign tax credits and, in the case of a U.S. Holder that elects to deduct foreign income taxes, the availability of deductions, involves the application of complex rules that depend on such U.S. Holder’s particular circumstances. U.S. Holders are urged to consult their tax advisors regarding the availability of foreign tax credits in their particular circumstances.

Passive Foreign Investment Company Rules

We were not a “passive foreign investment company” or PFIC for U.S. federal income tax purposes for our 2019 taxable year and we do not anticipate being a PFIC for our 2020 taxable year. However, because PFIC status depends upon the composition of a company’s income and assets and the market value of its assets from time to time, and because it is unclear whether certain types of our income constitute passive income for PFIC purposes, there can be no assurance that we will not be considered a PFIC for any current, prior or future taxable year. If we were to become a PFIC for any taxable year during which a beneficial owner held shares or ADSs, certain adverse consequences could apply to the U.S. Holder, including the imposition of higher amounts of tax than would otherwise apply, and additional filing requirements. In addition, if we were treated as a PFIC in a taxable year in which we pay a dividend or in the prior taxable year, the favorable dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply (see “— Taxation of Distributions” above). U.S. Holders should consult their tax advisors regarding the consequences to them if we were to become a PFIC, as well as the availability and advisability of making any election that might mitigate the adverse consequences of PFIC status.

Required Disclosure with Respect to Foreign Financial Assets

Certain U.S. Holders are required to report information relating to an interest in our shares or ADSs, subject to certain exceptions (including an exception for our shares or ADSs held in accounts maintained by certain financial institutions), by attaching a completed IRS Form 8938, Statement of Specified Foreign Financial Assets, with their tax return for each year in which they hold an interest in our shares or ADSs. U.S. Holders are urged to consult their own U.S. tax advisors regarding information reporting requirements relating to their ownership of our shares or ADSs.

Information Reporting and Backup Withholding

Payments of dividends and sales proceeds that are made within the United States or through certain U.S.- related financial intermediaries generally are subject to information reporting and to backup withholding unless: (i) the U.S.

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Holder is an exempt recipient or (ii) in the case of backup withholding, the beneficial owner provides a correct taxpayer identification number and certifies that the U.S. Holder is not subject to backup withholding.

The amount of any backup withholding from a payment to a beneficial owner will be allowed as a credit against the beneficial owner’s U.S. federal income tax liability and may entitle the U.S. Holder to a refund, provided that the required information is furnished in a timely fashion to the U.S. Internal Revenue Service.

Medicare Contribution Tax

A U.S. Holder that is an individual or estate, or a trust that does not meet certain requirements for an exemption, is subject to a tax of 3.8% on its “net investment income.” Among other items, net investment income generally includes gross income from dividends and net gain attributable to the disposition of certain property, like the shares or ADSs, less certain deductions. A U.S. Holder should consult the holder’s own tax advisor regarding the applicability of the “net investment income” tax in respect of such beneficial owner’s particular circumstances.

U.S. Holders should consult their tax advisors with respect to the particular consequences to them of owning or disposing of shares or ADSs.

F.Dividends and Paying Agents.

Not applicable.

G.Statement by Experts.

Not applicable.

H.Documents on Display.

We are subject to the information requirements of the Exchange Act, except that as a foreign issuer, we are not subject to SEC proxy rules (other than general anti-fraud rules) or the short-swing profit disclosure rules of the Exchange Act. In accordance with these statutory requirements, we file or furnish reports and other information with the SEC. Reports, information statements and other information we file with or furnish to the SEC are available electronically on the SEC’s website, which can be accessed at http://www.sec.gov and on our website www.enelchile.cl. Copies of such material may also be inspected at the offices of the New York Stock Exchange, at 11 Wall Street, New York, New York 10005, on which our ADS are listed.

I.Subsidiary Information.

For information on our principal subsidiaries, see “Item 4. Information on the Company — C. Organizational Structure — Principal Subsidiaries and Affiliates”.

Item 11.      Quantitative and Qualitative Disclosures About Market Risk

We are exposed to risks arising from volatility in commodity prices, interest rates and foreign exchange rates that affect the generation and distribution businesses in Chile.

Commodity Price Risk

In our electricity generation business segment, we are exposed to market risks arising from the price volatility of electricity, natural gas, diesel oil, and coal. We seek to ensure our fuel supply by securing long-term contracts with our suppliers for periods that are expected to match the lifetime of our generation assets. These contracts generally have provisions that allow us to purchase natural gas with a pricing formula that combines Henry Hub natural gas and Brent diesel oil at market prices prevailing at the time of purchase.

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In order to reduce risk under extreme drought conditions, Enel Generation has designed a commercial policy that aligns sale commitment levels with the capacity of its generating facilities during a dry year by including risk mitigation clauses with unregulated clients in some contracts. In the case of regulated clients subject to long-term tender processes, indexed polynomials are determined to reduce commodity exposure.

Considering the operating conditions faced in  the electricity generation market in Chile, drought, and the volatility of commodity prices in international markets, we are constantly evaluating whether it would be in our best interests to engage in hedging to mitigate the impact of price changes on profits.

As of December 31, 2019, we held the following swaps: 1,412 kTon of Coal API2 to be settled in 2020; 1,059 kBbl of Brent oil to be settled in 2020; and 4.79 TBtu of Henry Hub gas to be settled in 2020.

As of December 31, 2018, we held swaps for 432 kTon of Coal API2 to be settled in 2019, 994 kBbl of Brent oil to be settled in 2019, 225 kTon of BCI7 to be settled in 2019, and 0.2 TBtu of Henry Hub gas to be settled in 2019.

Depending on the operating conditions that are constantly updated, these hedging measures may be modified or included in other commodities.

We are continually analyzing strategies to hedge commodity price risk, including transferring commodity price variations to customers’ contract prices, and permanently adjusting commodity indexed price formulas for new PPAs according to our exposure, or analyzing ways to mitigate risk through hydrological insurance in dry years. In the future, we may consider using price-sensitive instruments.

Interest Rate and Foreign Currency Risk

As of December 31, 2019, the carrying values according to maturity and the corresponding fair value of our interest-bearing debt are detailed below. Values do not include derivatives. The rates in the table below are the result of the

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weighted average of the effective interest rates of each obligation, including expenses associated with financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

	Expectedmaturity date
Forthe year ended  December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value(2)
	(in billions of Ch$)(1)
Fixed Rate
Ch$/UF	1,950	1,728	1,410	1,399	1,399	21,653	29,539	29,539
Weighted average interest rate	2.7%	2.7%	3.1%	3.1%	3.1%	3.2%	3.1%	n.a
US$	2,718	2,806	25,440	5,470	420,270	1,349,576	1,806,280	2,033,341
Weighted average interest rate	6.5%	6.5%	2.1%	6.5%	4.8%	5.8%	5.5%	n.a
Other currencies	333	579	579	579	579	4,540	7,189	7,189
Weighted average interest rate	3.8%	3.8%	3.8%	3.8%	3.8%	3.8%	3.8%	n.a
Total fixed rate	5,001	5,112	27,429	7,448	422,249	1,375,769	1,843,008	2,070,069
Weighted average interest rate	4.8%	4.9%	2.2%	5.6%	4.8%	5.8%	5.5%	n.a
Variable Rate
Ch$/UF	31,625	31,625	31,625	31,625	31,625	153,594	311,718	421,668
Weighted average interest rate	7.9%	7.9%	7.9%	7.9%	7.9%	7.8%	7.8%	n.a
US$	112,311	112,311	299,496	—	—	—	524,118	524,118
Weighted average interest rate	4.3%	4.5%	3.3%	—	—	—	3.8%	n.a
Total variable rate	143,936	143,936	331,121	31,625	31,625	153,594	835,836	945,786
Weighted average interest rate	5.0%	5.2%	3.8%	7.9%	7.9%	7.8%	5.3%	n.a
Total	148,937	149,048	358,549	39,073	453,873	1,529,364	2,678,844	3,015,854

(1)Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2)As of December 31, 2019, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2018, the carrying values according to maturity and the corresponding fair value of our interest-bearing debt are detailed below. Values do not include derivatives. The rates in the table below are the result of the

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weighted average of the effective interest rates of each obligation, including expenses associated with financing and withholding taxes on interest payments related to financing obtained outside the country of domicile of each company.

	Expectedmaturity date
Forthe year ended  December 31,	2019	2020	2021	2022	2023	Thereafter	Total	Fair Value (2)
	(in billions of Ch$) (1)
Fixed Rate
Ch$/UF	—	—	—	—	—	—	—	n.a
Weighted average interest rate	—	—	—	—	—	—	—	n.a
US$	2,166	2,307	2,457	23,460	4,929	1,192,974	1,228,293	1,316,361
Weighted average interest rate	6.5%	6.5%	6.5%	2.1%	6.5%	5.4%	5.4%	-
Total fixed rate	2,166	2,307	2,457	23,460	4,929	1,192,974	1,228,293	1,316,361
Weighted average interest rate	6.5%	6.5%	6.5%	2.1%	6.5%	5.4%	5.4%	n.a
Variable Rate
Ch$/UF	244,553	30,793	30,793	30,793	30,793	180,350	548,077	618,940
Weighted average interest rate	3.9%	7.9%	7.9%	7.9%	7.9%	7.9%	6.1%	n.a
US$	69,477	104,216	168,171	63,956	63,956	255,823	725,598	725,598
Weighted average interest rate	1.6%	4.4%	3.8%	6.9%	6.9%	6.9%	5.3%	n.a
Total variable rate	314,030	135,009	198,965	94,749	94,749	436,173	1,273,675	1,344,538
Weighted average interest rate	3.4%	5.2%	4.4%	7.2%	7.2%	7.3%	5.7%	n.a
Total	316,196	137,316	201,422	118,209	99,678	1,629,147	2,501,968	2,660,899

(1)Calculated based on the Observed Exchange Rate as of December 31, 2018, which was Ch$ 694.77 per US$ 1.00.

(2)Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Interest Rate Risk

Our policy aims to minimize the average cost of debt and reduce the volatility of our financial results. Depending on our estimates and the debt structure, we sometimes manage interest rate risk by using interest rate derivatives.

As of December 31, 2019, and 2018, 98% and 71%, respectively, of our total outstanding debt had fixed interest rates and 2% and 29%, respectively, was subject to variable interest rates. Because of the exposure to variable interest rate risks, we engage in derivative hedging instruments.

As of December 31, 2019, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest bearing debt were as follows:

	Expected Maturity Date
For the year ended December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value(2)
	(in billions of Ch$) (1)
Variable to fixed rates	112,311	112,311	299,496	—	—	—	524,118	(7,411)
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	112,311	112,311	299,496	—	—	—	524,118	(7,411)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

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As of December 31, 2018, the carrying values for financial reporting purposes and the corresponding fair value of the instruments that hedge the interest rate risk of our interest-bearing debt were as follows.

	Expected Maturity Date
For the year ended December 31,	2019	2020	2021	2022	2023	Thereafter	Total	Fair Value (2)
	(in billions of Ch$) (1)
Variable to fixed rates	69,477	104,216	104,216	—	—	—	277,908	5,049
Fixed to variable rates	—	—	—	—	—	—	—	—
Total	69,477	104,216	104,216	—	—	—	277,908	5,049

(1)Calculated based on the Observed Exchange Rate as of December 31, 2018, which was Ch$ 694.77 per US$ 1.00.

(2)As of December 31, 2018, fair value was calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

Foreign Currency Risk

Our policy seeks to maintain a balance between the currency in which cash flows are indexed and the currency of the debt of each company. Most of our subsidiaries have access to funding in the same currency as their revenues, therefore reducing the exchange rate volatility impact. In some cases, we cannot fully benefit from this, and therefore, we try to manage the exposure with financial derivatives such as cross currency swaps or currency forwards, among others. However, this may not always be possible under reasonable terms due to market conditions.

As of December 31, 2019, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest-bearing debt were as follows:

	ExpectedMaturity Date
Forthe year ended December 31,	2020	2021	2022	2023	2024	Thereafter	Total	Fair Value (2)
	(in billions of Ch$) (1)
UF to US$	—	—	—	—	517,638	—	517,638	(9,530)
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	—	—	—	—	517,638	—	517,638	(9,530)

(1)Calculated based on the Observed Exchange Rate as of December 31, 2019, which was Ch$ 748.74 per US$ 1.00.

(2)Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

As of December 31, 2018, the carrying values for financial accounting purposes and the corresponding fair value of the instruments that hedge the foreign exchange risk of our interest bearing debt were as follows:

	ExpectedMaturity Date
Forthe year ended December 31,	2019	2020	2021	2022	2023	Thereafter	Total	Fair Value(2)
	(in billions of Ch$) (1)
UF to US$	534,547	—	—	—	—	—	534,547	(18,892)
US$ to Ch$/UF	—	—	—	—	—	—	—	—
Ch$ to US$	—	—	—	—	—	—	—	—
Total	534,547	—	—	—	—	—	534,547	(18,892)

(1) Calculated based on the Observed Exchange Rate as of December 31, 2018, which was Ch$ 694.77 per US$ 1.00.

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(2) Fair values were calculated based on the discounted value of future cash flows expected to be paid (or received), considering current discount rates that reflect the different risks involved.

For further detail, please refer to Note 22 of the Notes to our consolidated financial statements.

(d) Safe Harbor

The information in this “Item 11. Quantitative and Qualitative Disclosures About Market Risk,” contains information that may constitute forward-looking statements. See “Forward-Looking Statements” in the Introduction of this Report for safe harbor provisions.

Item 12.Description of Securities Other Than Equity Securities

A.Debt Securities.

Not applicable.

B.Warrants and Rights.

Not applicable.

C.Other Securities.

Not applicable.

D.American Depositary Shares.

Depositary Fees and Charges

Our ADS program’s depositary is Citibank, N.A. The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders. The Depositary may generally refuse to provide the requested services until its fees for those services are paid. Under the terms of the Deposit Agreement, an ADS holder may have to pay the following service fees to the Depositary:

Service Fees	Fees
(1) Issuance of ADS upon deposit of shares (excluding issuances as a result of distributions described in paragraph (4) below)	Up to US$5 per 100 ADSs (or fraction thereof) issued
(2) Delivery of deposited securities against surrender of ADS	Up to US$5 per 100 ADSs (or fraction thereof) surrendered
(3) Distribution of cash dividends or other cash distributions (i.e., sale of rights and other entitlements)	Up to US$5 per 100 ADSs (or fraction thereof) held
(4) Distribution of ADS pursuant to (i) stock dividends or other free stock distributions, or (ii) exercise of rights to purchase additional ADS	Up to US$5 per 100 ADSs (or fraction thereof) held
(5) Distribution of securities other than ADS or rights to purchase additional ADS (i.e., a spin-off of shares)	Up to US$5 per 100 ADSs (or fraction thereof) held
(6) Depositary services	Up to US$5 per 100 ADSs (or fraction thereof) held on the applicable record date(s) established by the Depositary

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The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for withdrawal or from intermediaries acting for them. The Depositary fees payable for cash distributions are deducted from the cash being distributed. In the case of distributions other than cash, the Depositary will invoice the applicable ADS record date holders and such fees may be deducted from distributions.

Depositary Payments for Fiscal Year 2019

The Depositary has agreed to reimburse certain expenses incurred by us in connection with our ADS program. In 2019, the Depositary reimbursed expenses related primarily to investor relations’ activities for a total amount of US$ 1.0 million (after the deduction of applicable U.S. taxes).

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PART II

Item 13.      Defaults, Dividend Arrearages and Delinquencies

None.

Item 14.      Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15.Controls and Procedures

(a) Disclosure Controls and Procedures

We conducted an evaluation under the supervision and with the participation of our senior management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) for the year ended December 31, 2019.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error, and the circumvention or overriding of the controls and procedures. Accordingly, our disclosure controls and procedures are designed to provide reasonable assurance of achieving their control objectives.

Based upon our evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective in providing reasonable assurance that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the applicable rules and forms, and that it is gathered and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives, and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

(b) Management’s Annual Report on Internal Control Over Financial Reporting

As required by Section 404 of the Sarbanes-Oxley Act of 2002, our management is responsible for establishing and maintaining “adequate internal control over financial reporting” (as defined in Rule13a-15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS, as issued by the IASB.

Because of its inherent limitations, internal control over financial reporting may not necessarily prevent or detect some misstatements. It can only provide reasonable assurance regarding financial statement preparation and presentation. Also, projections of any evaluation of effectiveness for future periods are subject to the risk that controls may become inadequate because of changes in conditions or because the degree of compliance with the policies or procedures may deteriorate over time.

Management assessed the effectiveness of its internal control over financial reporting for the year ended December 31, 2019. The assessment was based on criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO 2013 framework”). Based on the assessment, our management has concluded that as of December 31, 2019, our internal control over financial reporting was effective.

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(c) Attestation Report of the Public Accounting Firm

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2019. Their attestation report appears on page F-4.

(d) Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d) or 15d-15(d) under the Exchange Act that occurred during 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting model.

Item 16.      Reserved

Item 16A.Audit Committee Financial Expert

As of December 31, 2019, the Directors Committee performs the functions of the Audit Committee, and the committee’s financial expert was Mr. Fernán Gazmuri P., as determined by the Board of Directors. Mr. Gazmuri is an independent member of the Directors’ Committee pursuant to the requirement of both Chilean law and NYSE corporate governance rules.

Item 16B.Code of Ethics

Our standards of ethical conduct are governed by means of the following five corporate rulings or policies: the Code of Ethics, the Zero Tolerance Anti-Corruption Plan (the “ZTAC Plan”), the Human Rights Policy, the Manual for the Management of Information of Interest to the Market (the “Manual”) and the Diversity Policy.

The Manual, adopted by our Board of Directors, addresses the following issues: applicable standards and blackout periods regarding the information in connection with transactions of our securities or those of our affiliates, entered into by directors, management, principal executives, employees and other related parties; the existence of mechanisms for the continuous disclosure of information that is of interest to the market; and mechanisms that provide protection for confidential information.

In addition to the corporate governance rules described above, our Board adopted the Code of Ethics, the ZTAC Plan and the Human Rights Policy. The Code of Ethics is based on general principles such as impartiality, honesty, integrity and other values of similar importance, which are translated into detailed behavioral criteria. The ZTAC Plan reinforces the principles included in the Code of Ethics, but with a special emphasis on avoiding corruption in the form of bribes, preferential treatment, and other similar matters. The Human Rights Policy incorporates and adapts the general human rights principles championed by the United Nations into a corporate reality.

The Diversity Policy was approved by the Board of Directors on August 30, 2016. This policy defines the key principles required to spread a culture that focuses on diversity and is based on the respect and promotion of the principles of preventing arbitrary discrimination and encouraging equal opportunities and inclusion, which are fundamental values in the development of the Company’s activities. By means of this policy, the Company seeks to improve the work environment and the quality of life at work. The Company is committed to creating an inclusive work environment where workers can develop their potential and maximize their contribution.

A copy of these documents is available on our webpage at www.enelchile.cl as well as upon request, free of charge, by writing or calling us at:

Enel Chile S.A.

Investor Relations Department

Av. Santa Rosa 76, Piso 15 

Comuna de Santiago, Santiago, Chile

(56-2) 2353-4400

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During fiscal year 2019, there have been no amendments to any provisions of the documents described above. No waivers from any provisions of the Code of Ethics, the ZTAC Plan or the Manual, were expressly or implicitly granted to the Chief Executive Officer, the Chief Financial Officer or any other senior financial officers of the Company in fiscal year 2019.

Item 16C.Principal Accountant Fees and Services

The following table provides information on the aggregate fees for approved services billed by our independent registered accounting firm, as well as the other member firms and their respective affiliates, by type of services for the periods indicated.

Services Rendered	2019	2018
	(in millions of Ch$)
Audit fees	968	1,069
Audit-related fees	104	552
Tax fees	—	—
All other fees	—	—
Total	1,072	1,621

All the fees disclosed under audit-related fees and all other fees were pre-approved as required by the Directors’ Committee pre-approval policies and procedures.

The amounts included in the table above and the related footnotes have been classified under SEC guidance.

Directors’ Committee Pre-Approval Policies and Procedures

Our shareholders appoint our external auditors at the GSM. Similarly, the shareholders of our subsidiaries appoint their external auditors according to applicable law and regulation.

The Directors’ Committee (which performs the functions of the Audit Committee), reviews engagement letters with external auditors, ensures quality control in respect of the services provided, reviews and controls independence issues, and other related matters.

The Directors’ Committee has a pre-approval policy regarding the contracting of our external auditor, or any affiliate of the external auditor, for professional services. The professional services covered by such policy include audit and non-audit services provided to us.

Fees payable in connection with recurring audit services are pre-approved as part of our annual budget. Fees payable in connection with non-recurring audit services, once the CFO has examined them, are submitted to the Directors’ Committee for its final consideration.

The pre-approval policy established by the Directors’ Committee for non-audit services and audit-related fees is as follows:

· The business unit that has requested the service and the audit firm expected to perform the service must request that the CFO review the nature of the service to be provided.

· The CFO then analyzes the request and requires the selected audit firm to issue a certificate signed by the partner responsible for the audit of our consolidated financial statements confirming such an audit firm’s independence.

· Finally, the proposal is submitted to the Directors’ Committee for approval or denial.

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The Directors’ Committee has designed, approved, and implemented the necessary procedures to fulfill the SEC requirements regarding Audit Committee pre-approval of certain tax services.

Item 16D.      Exemptions from the Listing Standards for Audit Committees

Not applicable.

Item  16E.      Purchases of Equity Securities by the Issuer and Affiliated Purchasers

On December 5, 2019, our ultimate parent company Enel declared an intention to acquire an additional 3% economic interest in us through swap agreements involving our common stock and ADSs. Pursuant to the swap transactions, Enel may acquire, on dates that are expected to occur no later than the fourth quarter of 2020, up to 1,763,747,209 additional shares of our common stock and up to 6,224,990 additional ADSs. The number of shares of our common stock and ADSs actually acquired by Enel pursuant to the swap transactions will depend on the ability of such financial institution to establish its hedge positions with respect to the swap transactions.

On March 19, 2020, Enel reported to the SEC that on or about May 13, 2020, it would acquire beneficial ownership of 6,224,990 ADSs, representing 311,249,500  shares of common stock, or 0.45% of our shares, under a share swap transaction with respect to our ADSs. In addition, Enel reported to the SEC that it (i) amended the swap transaction related to our common stock to decrease the number of our shares that it may acquire pursuant to such swap transaction to up to 1,502,106,759 shares and (ii) entered into an additional swap transaction related to our ADSs, under which it may acquire up to 5,232,809 additional ADSs.

As a result of the transactions described above, Enel is expected to increase its beneficial ownership in us from 61.9% as of December 31, 2019 and the date of this Report to 62.4% as of May 13, 2020 and may further increase its beneficial ownership in us up to 64.9% by the end of 2020.

Item 16F.Change in Registrant’s Certifying Accountant

On March 30, 2020, the Directors’ Committee recommended to the Board of Directors that the Board propose to the Company’s shareholders a change in the Company’s independent registered public accounting firm at the annual General Shareholders’ Meeting held on April 29, 2020. On April 29, 2020, the shareholders approved the Board’s proposal to appoint KPMG Auditores Consultores SpA (“KPMG”) as the new independent registered public accounting firm for the Company. EY Audit SpA (“EY”) had served as the independent registered public accounting firm for the Company for the 2011 through 2019 fiscal years, in each case pursuant to the terms of an annual engagement letter. On April 29, 2020, EY was notified by the Company that shareholders had approved appointment of another independent registered public accounting firm for the 2020 fiscal year and that EY was dismissed from its engagement by the Company effective immediately.

The audit reports of EY on the Company’s consolidated financial statements as of December 31, 2019 and 2018  and for the years ended December 31, 2019, 2018 and 2017 and the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles.

During the Company’s two most recent fiscal years ended December 31, 2019 and 2018, and the subsequent interim period through April 29, 2020, there were no disagreements with EY on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to EY’s satisfaction, would have caused EY to make reference to the subject matter of such disagreements in connection with its reports on the Company’s consolidated financial statements for such periods.

During the Company’s two most recent fiscal years ended December 31, 2019, and 2018 and the subsequent interim period through April 29, 2020, there were no reportable events (as defined in Item 16F(a)(1)(v) of Form 20-F).

The Company has provided EY with a copy of the disclosure in Item 16F of this Form 20-F prior to its filing with the SEC. The Company requested EY to furnish the Company with a letter addressed to the SEC stating whether or not it

132

agrees with the above statements, as required by Item 16F(a)(3) of Form 20-F. A copy of EY’s letter is filed as Exhibit 15.1 to this Form 20-F.

No later than June 30, 2020, the Company’s Board of Directors will engage KPMG as the Company’s new independent registered public accounting firm to audit the Company’s consolidated financial statements and internal control over financial reporting for the fiscal year ending December 31, 2020. As of the date of this Report, KPMG is in the process of its standard client evaluation procedures and has not accepted the engagement.

During the Company’s two most recent fiscal years and any subsequent interim period prior to the date of this Report, neither the Company nor anyone acting on its behalf has consulted KPMG on any of the matters or events set forth in Item 16F(a)(2)(i) or Item 16F(a)(2)(ii) of Form 20-F.

Item 16G.Corporate Governance

For a summary of the significant differences between our corporate governance practices and those applicable to domestic issuers under the corporate governance rules of the NYSE, see “Item 6. Directors, Senior Management and Employees — C. Board Practices.”

Item  16H.      Mine Safety Disclosure

Not applicable.

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PART III

Item  17.      Financial Statements

Not Applicable.

Item   18.      Financial Statements

Enel Chile

Index to the Audited Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:

Report of EY Audit S.p.A. – Enel Chile S.A. at December 31, 2019 and 2018	F‑1
Report of EY Audit S.p.A. – Enel Chile S.A. — Internal Control Over Financial Reporting 2019	F‑4
Consolidated Financial Statements:
Consolidated Statements of Financial Position at December 31, 2019 and 2018	F‑6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017	F‑8
Consolidated Statements of Changes in Equity for the years ended December 31, 2019, 2018 and 2017	F‑10
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	F‑12
Notes to the Consolidated Financial Statements	F‑13
Ch$          Chilean pesos
US$          U.S. dollars
UF            The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$      Thousands of Chilean pesos
ThUS$      Thousands of U.S. dollars

Item  19.    Exhibits

Exhibit	Description
1.1	By-laws (Estatutos) of Enel Chile S.A.
2.1	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934.
8.1	List of Principal Subsidiaries  as of December 31, 2019.
12.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
12.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
13.1	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.
15.1	Letter dated April 29, 2020, from EY Audit SpA as required by Item 16F of Form 20-F.
23.1	Consent of EY Audit S.p.A. an independent registered public accounting firm.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

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Exhibit	Description
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

We will furnish to the Securities and Exchange Commission, upon request, copies of any unfiled instruments that define the rights of stakeholders of Enel Chile.

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20‑F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	ENEL CHILE S.A.
	By:	/s/ Paolo Pallotti
	Name:	Paolo Pallotti
	Title:	Chief Executive Officer
Date: April 29, 2020

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Enel Chile S.A. and its Subsidiaries

Consolidated Financial Statements as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017

Index to the Audited Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firms:

Report of EY Audit S.p.A. – Enel Chile S.A. at December 31, 2019 and 2018	F‑1
Report of EY Audit S.p.A. – Enel Chile S.A. — Internal Control Over Financial Reporting 2019	F‑4
Consolidated Financial Statements:
Consolidated Statements of Financial Position at December 31, 2019 and 2018	F‑6
Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017	F‑8
Consolidated Statements of Changes in Equity for the years ended December 31, 2019, 2018 and 2017	F‑10
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	F‑12
Notes to the Consolidated Financial Statements	F‑13
Ch$          Chilean pesos
US$          U.S. dollars
UF            The UF is a Chilean inflation-indexed, peso-denominated monetary unit that is set daily in advance based on the previous month’s inflation rate.
ThCh$      Thousands of Chilean pesos
ThUS$      Thousands of U.S. dollars

EY Chile Avda. Presidente Riesco 5435, piso 4, Las Condes, Santiago Tel: +56 (2) 2676 1000 www.eychile.cl

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Enel Chile S.A.

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of Enel Chile S.A. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated April 29, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-1

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Goodwill Impairment Test

Description of the Matter

As of December 31, 2019, the Company’s consolidated financial statements present goodwill in the amount of Ch$917.35 billion. As discussed in Note 3 c) to the consolidated financial statements, goodwill is tested for impairment at least annually at the reporting unit level. The Company’s goodwill is initially assigned to its reporting units as of the acquisition date using a relative fair value allocation. The impairment tests require management to use significant assumptions to determine the fair value of the related reporting unit. Those assumptions are described in Note 3 e) to the Company´s consolidated financial statements, and  include market evolution, future price estimations, discount rates and the consideration of risks specific to the relevant cash generating unit.

Auditing the Company´s goodwill impairment test is complex due to the significant estimation uncertainties involved in determining the fair values of the reporting units. Those fair value estimates are sensitive to changes in significant assumptions such as discount rate and projected cash flows that are affected by future market or economic conditions.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the goodwill impairment test. For example, we tested controls over the significant assumptions, such as discount rate and projected cash flows, used in the valuation process.

To test the fair values of the reporting units, our audit procedures included, among others, evaluating the methodologies used by the Company with the assistance of our valuation specialists; testing the significant assumptions used to develop the prospective financial information; comparing those significant assumptions to historical results of the Company's business; benchmarking those assumptions against market participant data within the same industry and performing an independent calculation of the discount rate considering market information about the cost of capital from comparable energy companies.

We also evaluated the Company’s disclosure of this matter in Note 17 to the consolidated financial statements.

F-2

Effect of the 2019 Price Stabilization Law

Description of the Matter

As described in Notes 4 b) and 11 to the consolidated financial statements, the Company recognized revenues in the amount of Ch$182.07 billion and a corresponding payable to suppliers for energy purchases in the amount of Ch$53.94 billion, as a  result of a new law came into force corresponding to the price stabilization mechanism (PEC in Spanish), which caused delays in the billing process of the price adjustments and requires the use of significant assumptions and judgment by management to assess the financial and accounting effects.

Auditing the amounts related to the effects of the PEC is complex due to the significant effort to evaluate the effects of the tariff decrees and sales contracts as well as the judgment used to determine the present value of the unbilled revenue due to the entry into force of the PEC law.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the effects of the PEC. For example, we tested controls over the prices obtained from the sales contracts and tariff decrees related to the significant assumptions, such as discount rate and estimated recovery date used to calculate the unbilled revenue and supplier accrual associated with the PEC.

To test the amounts resulting from the effects of the PEC by recalculating the prices of sales contracts; comparing significant inputs used by management, such as the future price of coal, gas, oil, forward US Dollar exchange rates, as well as the Consumer Price Index (CPI) with the tariff decrees issued by the regulator; comparing the energy price used in the sales contracts with the price obtained from the regulator; recalculating the estimation of unbilled energy already provided to customers. and involving our  valuation specialist to assist in the evaluating the discount rate used by the Company to compute the present value of future price adjustments related to customers subject to the PEC.

We also evaluated the financial statements disclosures included in the Notes 4 b) and 11.

/s/ EY Audit SpA.

EY Audit SpA.

We have served as the Company’s auditor since 2011.

Santiago, Chile

April 29, 2020

F-3

EY Chile Avda. Presidente Riesco 5435, piso 4, Las Condes, Santiago Tel: +56 (2) 2676 1000 www.eychile.cl

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Enel Chile S.A.

Opinion on Internal Control over Financial Reporting

We have audited Enel Chile S.A. and subsidiaries’ internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Enel Chile S.A. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based onthe COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Companyas of December 31, 2019 and 2018, the related consolidated statements of comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and our report dated April 29, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities lawsand the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

F-4

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with international financial reporting standards. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with international financial reporting standards, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ EY Audit SpA.

EY Audit SpA.

Santiago, Chile

April 29, 2020

F-5

ENEL CHILE S.A.

Consolidated Statements of Financial Position

As of December 31, 2019 and 2018

(In thousands of Chilean pesos – ThCh$)

		12-31-2019	12-31-2018
	Note	ThCh$	ThCh$
ASSETS
CURRENT ASSETS
Cash and cash equivalents	8	235,684,500	245,171,924
Other current financial assets	9	1,310,595	40,303,173
Other current non-financial assets	10.a	34,634,563	22,406,088
Trade and other current receivables	11	511,455,330	478,170,067
Current accounts receivable from related parties	12	68,182,133	54,171,060
Inventories	13	39,672,250	56,961,643
Current tax assets	14	127,273,289	99,763,817
TOTAL CURRENT ASSETS		1,018,212,660	996,947,772
NON-CURRENT ASSETS
Other non-current financial assets	9	7,220,620	7,269,669
Other non-current non-financial assets	10.a	38,050,184	44,608,012
Trade and other non-current receivables	11	313,574,385	60,527,843
Non-current accounts receivable from related parties	12	34,407,142	—
Investments accounted for using the equity method	15	7,928,588	12,873,531
Intangible assets other than goodwill	16	132,278,593	115,372,393
Goodwill	17	917,352,974	915,044,725
Property, plant and equipment	18	5,360,319,624	5,308,647,633
Investment property	19	6,795,155	7,557,356
Deferred tax assets	20.b	21,848,239	19,171,230
TOTAL NON-CURRENT ASSETS		6,839,775,504	6,491,072,392
TOTAL ASSETS		7,857,988,164	7,488,020,164

The accompanying notes are an integral part of these consolidated financial statements.

F-6

ENEL CHILE S.A.

Consolidated Statements of Financial Position (continued)

As of December 31, 2019 and 2018

(In thousands of Chilean pesos – ThCh$)

		12-31-2019	12-31-2018
	Note	ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Other current financial liabilities	21	214,656,576	410,665,815
Trade and other current payables	24	599,263,208	554,286,324
Current accounts payable to related parties	12	159,809,887	157,936,325
Other current provisions	25	4,065,965	5,588,786
Current tax liabilities	14	17,995,833	17,677,920
Other current non-financial liabilities	10.b	45,508,383	71,308,982
TOTAL CURRENT LIABILITIES		1,041,299,852	1,217,464,152
NON-CURRENT LIABILITIES
Other non-current financial liabilities	21	1,740,169,919	1,705,833,503
Trade and other non-current payables	24	56,250,085	2,584,180
Non-Current accounts payable to related parties	12	784,373,484	447,193,802
Other long-term provisions	25	171,860,282	105,871,375
Deferred tax liabilities	20.b	249,284,641	278,080,054
Non-current provisions for employee benefits	26	66,163,490	56,602,664
Other non-current non-financial liabilities	10.b	1,302,759	226,653
TOTAL NON-CURRENT LIABILITIES		3,069,404,660	2,596,392,231
TOTAL LIABILITIES		4,110,704,512	3,813,856,383
EQUITY
Allocated capital	27.1	3,882,103,470	3,954,491,479
Retained earnings		2,008,103,651	1,914,797,613
Treasury shares	27.1	—	(72,388,009)
Other reserves	27.5	(2,405,509,135)	(2,375,672,564)
Equity attributable to Enel Chile		3,484,697,986	3,421,228,519
Non-controlling interests	27.6	262,585,666	252,935,262
TOTAL EQUITY		3,747,283,652	3,674,163,781
TOTAL LIABILITIES AND EQUITY		7,857,988,164	7,488,020,164

The accompanying notes are an integral part of these consolidated financial statements.

F-7

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature

For the years ended December 31, 2019, 2018 and 2017

(In thousands of Chilean pesos – ThCh$)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		2019	2018	2017
Profit (loss)	Note	ThCh$	ThCh$	ThCh$
Revenues	28	2,624,576,323	2,410,360,459	2,484,101,582
Other operating income	28	146,258,037	46,800,967	38,876,700
Revenues and other operating income		2,770,834,360	2,457,161,426	2,522,978,282
Raw materials and consumables used	29	(1,421,205,251)	(1,292,177,116)	(1,514,786,921)
Contribution Margin		1,349,629,109	1,164,984,310	1,008,191,361
Other work performed by the entity and capitalized	18.b.2	17,610,861	16,710,963	14,388,987
Employee benefits expense	30	(129,604,956)	(123,130,334)	(121,503,777)
Depreciation and amortization expense	31.a	(236,627,387)	(215,187,300)	(152,684,106)
Reversal of impairment losses (impairment losses) recognized on non-financial assets	31.b	(280,762,652)	(779,825)	—
Impairment gains and reversals of impairment losses (impairment losses) determinated in accordance with IFRS 9 on financial assets	31.b	(10,047,000)	(4,783,072)	(7,937,817)
Other expenses	32	(184,143,140)	(167,210,021)	(161,824,074)
Operating Income		526,054,835	670,604,721	578,630,574
Other gains	33	1,793,201	3,410,379	113,241,196
Financial income	34	27,399,275	19,934,468	21,662,688
Financial costs	34	(164,897,900)	(122,184,189)	(53,510,882)
Share of profit (loss) of associates and joint ventures accounted for using the equity method	15	366,089	3,190,240	(2,696,904)
Foreign currency exchange differences	34	(10,412,110)	(7,807,197)	8,516,874
Gains or loss from indexed assets and liabilities, net (*)	7 - 34	(2,982,268)	(818,146)	916,666
Income before taxes		377,321,122	566,330,276	666,760,212
Income tax expense	20.a	(61,227,904)	(153,482,519)	(143,342,301)
NET INCOME		316,093,218	412,847,757	523,417,911
Net income attributable to:
Equity owners of Enel Chile		296,153,605	361,709,937	349,382,642
Non-controlling interests	27.6	19,939,613	51,137,820	174,035,269
NET INCOME		316,093,218	412,847,757	523,417,911
Basic earnings per share
Basic earnings per share	Ch$/Share	4.28	5.66	7.12
Weighted average number of shares of common stock		69,166,557,220	63,913,359,484	49,092,772,762
Diluted earnings per share
Diluted earnings per share	Ch$/Share	4.28	5.66	7.12
Weighted average number of shares of common stock		69,166,557,220	63,913,359,484	49,092,772,762

(*) Includes Argentina’s hyperinflationary effect (see Note 7).

The accompanying notes are an integral part of these consolidated financial statements.

F-8

ENEL CHILE S.A.

Consolidated Statements of Comprehensive Income, by Nature (continued)

For the years ended December 31, 2019, 2018 and 2017

(In thousands of Chilean pesos – ThCh$)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME		2019	2018	2017
Other comprehensive income (loss)	Note	ThCh$	ThCh$	ThCh$
Net Income		316,093,218	412,847,757	523,417,911
Components of other comprehensive income that will not be reclassified subsequently to profit or loss, before taxes
Remeasurement losses from defined benefit plans	26.2.b	(7,777,204)	37,881	1,716,875
Other comprehensive loss that will not be reclassified subsequently to profit or loss		(7,777,204)	37,881	1,716,875
Components of other comprehensive income (loss) that will be reclassified subsequently to profit or loss, before taxes
Foreign currency translation gains		73,114,966	107,492,316	(3,686,549)
Gains (losses) from financial assets at fair value of other comprehensive income		(3,673)	(411)	1,840
Share of other comprehensive income (loss) from associates and joint ventures accounted for using the equity method	15.a	—	—	(1,490)
Gains (losses) from cash flow hedges		(160,828,497)	(244,271,689)	73,333,487
Adjustments from reclassification of cash flow hedges, transferred to profit or loss		21,654,376	22,364,834	24,225,474
Other comprehensive income (loss) that will be reclassified subsequently to profit or loss		(66,062,828)	(114,414,950)	93,872,762
Other comprehensive income (loss), before taxes		(73,840,032)	(114,377,069)	95,589,637
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss
Income tax related to defined benefit plans		2,099,845	(10,228)	(463,556)
Income tax related to components of other comprehensive income that will not be reclassified subsequently to profit or loss		2,099,845	(10,228)	(463,556)
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss
Income tax related to cash flow hedge		36,883,401	60,650,786	(25,701,599)
Income tax related to financial assets at fair value of other comprehensive income		992	111	(497)
Income tax related to components of other comprehensive income that will be reclassified subsequently to profit or loss		36,884,393	60,650,897	(25,702,096)
Total Other Comprehensive Income (Loss)		(34,855,794)	(53,736,400)	69,423,985
TOTAL COMPREHENSIVE INCOME		281,237,424	359,111,357	592,841,896
Comprehensive income attributable to:
Equity owners of Enel Chile		255,988,200	297,410,542	391,680,966
Non-controlling interests		25,249,224	61,700,815	201,160,930
TOTAL COMPREHENSIVE INCOME		281,237,424	359,111,357	592,841,896

The accompanying notes are an integral part of these consolidated financial statements.

F-9

ENEL CHILE S.A.

Consolidated Statements of Changes in Equity

For the years ended December 31, 2019, 2018 and 2017

(In thousands of Chilean pesos – ThCh$)

			Changes in Other Reserves
						Reserve for Gains	Amounts recognized
						and Losses on	in other comprehensive
						Remeasuring	income and
			Reserve for			Financial assets	accumulated in equity
			Exchange		Reserve for	at fair value	related to non-current
			Differences in		Gains and Losses	of other	assets or groups of assets	Other			Equity
	Allocated		Translation	Reserve for Cash	for Defined	comprehensive	for disposal classified as	Miscellaneous		Retained	Attributable to	Non-controlling
	Capital (1)	Treasury Shares	(2)	Flow Hedges	Benefit Plans	income	held for sale	Reserves	Other Reserves (3)	Earnings	Enel Chile	Interests (4)	Total Equity
Statements of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2019	3,954,491,479	(72,388,009)	101,654,836	(191,870,545)	—	—	11,041	(2,285,467,896)	(2,375,672,564)	1,914,797,613	3,421,228,519	252,935,262	3,674,163,781
Changes in equity						—	—	—	—	—	—	—	—
Comprehensive income	—	—	—	—	—	—	—	—	—	—	—	—	—
Profit (loss)	—	—	—	—	—	—	—	—	—	296,153,605	296,153,605	19,939,613	316,093,218
Other comprehensive income	—	—	64,461,733	(99,135,975)	(5,488,506)	—	(2,657)	—	(40,165,405)	—	(40,165,405)	5,309,611	(34,855,794)
Comprehensive income	—	—	—	—	—	—	—	—	—	—	255,988,200	25,249,224	281,237,424
Dividends	—	—	—	—	—	—	—	—	—	(197,359,062)	(197,359,062)	(16,578,349)	(213,937,411)
Increase (decrease) from other changes	(72,388,009)	72,388,009	—	—	5,488,506	—	—	4,840,328	10,328,834	(5,488,505)	4,840,329	979,529	5,819,858
Total changes in equity	(72,388,009)	72,388,009	64,461,733	(99,135,975)	—	—	(2,657)	4,840,328	(29,836,571)	93,306,038	63,469,467	9,650,404	73,119,871
Equity at end of period 12-31-2019	3,882,103,470	—	166,116,569	(291,006,520)	—	—	8,384	(2,280,627,568)	(2,405,509,135)	2,008,103,651	3,484,697,986	262,585,666	3,747,283,652

			Changes in Other Reserves
						Reserve for Gains	Amounts recognized
						and Losses on	in other comprehensive
						Remeasuring	income and
			Reserve for			Financial assets	accumulated in equity
			Exchange		Reserve for	at fair value	related to non-current
			Differences in		Gains and Losses	of other	assets or groups of assets	Other			Equity
	Allocated		Translation	Reserve for Cash	for Defined	comprehensive	for disposal classified as	Miscellaneous		Retained	Attributable to	Non-controlling
	Capital (1)	Treasury Shares	(2)	Flow Hedges	Benefit Plans	income	held for sale	Reserves	Other Reserves (3)	Earnings	Enel Chile	Interests (4)	Total Equity
Statements of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2018	2,229,108,975		6,976,383	(32,849,736)	—	11,284	—	(971,468,479)	(997,330,548)	1,751,605,583	2,983,384,010	803,577,647	3,786,961,657
Increase (decrease) through changes in accounting policies (5)	—	—	—	—	—	—	—	—	—	(2,702,470)	(2,702,470)	(44,691)	(2,747,161)
Equity at beginning of period 1-1-2018 as restated	2,229,108,975	—	6,976,383	(32,849,736)	—	11,284	—	(971,468,479)	(997,330,548)	1,748,903,113	2,980,681,540	803,532,956	3,784,214,496
Changes in equity
Comprehensive income
Profit (loss)	—	—	—	—	—	—	—	—	—	361,709,937	361,709,937	51,137,820	412,847,757
Other comprehensive income	—	—	94,678,453	(159,020,809)	43,204	(243)	—	—	(64,299,395)	—	(64,299,395)	10,562,995	(53,736,400)
Comprehensive income	—	—	—	—	—	—	—	—	—	—	297,410,542	61,700,815	359,111,357
Issuance of equity	1,725,382,504	—	—	—		—	—				1,725,382,504	—	1,725,382,504
Dividends	—	—	—	—	—	—	—		—	(195,858,641)	(195,858,641)	(19,603,211)	(215,461,852)
Increase (decrease) from other changes	—	—	—	—	(43,204)	—	—	(403,562,193)	(403,605,397)	43,204	(403,562,193)	92,644,186	(310,918,007)
Increase (decrease) due to portfolio transactions	—	(72,388,009)	—	—	—	—	—				(72,388,009)	—	(72,388,009)
Increase (decrease) due to changes in subsidiary interests that do not lead to loss of control	—	—	—	—	—	—	—	(910,437,224)	(910,437,224)	—	(910,437,224)	(685,339,484)	(1,595,776,708)
Total changes in equity	1,725,382,504	(72,388,009)	94,678,453	(159,020,809)	—	(243)	—	(1,313,999,417)	(1,378,342,016)	165,894,500	440,546,979	(550,597,694)	(110,050,715)
Equity at end of period 12-31-2018	3,954,491,479	(72,388,009)	101,654,836	(191,870,545)	—	11,041	—	(2,285,467,896)	(2,375,672,564)	1,914,797,613	3,421,228,519	252,935,262	3,674,163,781

F-10

			Changes in Other Reserves
					Reserve for Gains	Amounts recognized
					and Losses on	in other comprehensive
					Remeasuring	income and
		Reserve for			Financial assets	accumulated in equity
		Exchange		Reserve for	at fair value	related to non-current
		Differences in		Gains and Losses	of other	assets or groups of assets	Other			Equity
	Allocated	Translation	Reserve for Cash	for Defined	comprehensive	for disposal classified as	Miscellaneous		Retained	Attributable to	Non-controlling
	Capital  (1)	(2)	Flow Hedges	Benefit Plans	income	held for sale	Reserves	Other Reserves (3)	Earnings	Enel Chile	Interests (4)	Total Equity
Statements of Changes in Equity	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Equity at beginning of period 1-1-2017	2,229,108,975	9,222,933	(76,218,470)	—	9,955	1,632,724	(969,740,120)	(1,035,092,978)	1,569,375,291	2,763,391,288	699,602,354	3,462,993,642
Changes in equity
Comprehensive income	—	—	—	—	—	—	—	—	—	—	—	—
Profit (loss)	—	—	—	—	—	—	—	—	349,382,642	349,382,642	174,035,269	523,417,911
Other comprehensive income	—	(2,246,550)	43,368,734	1,174,811	1,329	—	—	42,298,324	—	42,298,324	27,125,661	69,423,985
Comprehensive income	—	—	—	—	—	—	—	—	—	391,680,966	201,160,930	592,841,896
Dividends	—	—	—	—	—	—		—	(168,327,161)	(168,327,161)	(94,944,701)	(263,271,862)
Increase (decrease) from other changes	—	—	—	(1,174,811)	—	(1,632,724)	(1,728,359)	(4,535,894)	1,174,811	(3,361,083)	(2,240,936)	(5,602,019)
Total changes in equity	—	(2,246,550)	43,368,734	—	1,329	(1,632,724)	(1,728,359)	37,762,430	182,230,292	219,992,722	103,975,293	323,968,015
Equity at end of period 12-31-2017	2,229,108,975	6,976,383	(32,849,736)	—	11,284	—	(971,468,479)	(997,330,548)	1,751,605,583	2,983,384,010	803,577,647	3,786,961,657

(1) See Note 27.1

(2) See Note 27.3

(3) See Note 27.5

(4) See Note 27.6

(5) Considers a charge in results for ThCh$3,411,631 due to application of IFRS 9 and a credit to retained earnings for ThCh$664,470 due to application of IAS 29, see notes 22.2 – Impairment – and 2.7.4, respectively.

The accompanying notes are an integral part of these consolidated financial statements

F-11

ENEL CHILE S.A.

Consolidated Statements of Cash Flows, Direct

For the years ended December 31, 2019, 2018 and 2017

		2019	2018	2017
Statements of Direct Cash Flows	Note	ThCh$	ThCh$	ThCh$
Cash flows from (used in) operating activities
Types of collection from operating activities
Collections from the sale of goods and services		3,053,366,631	3,037,830,501	3,147,019,752
Collections from premiums and services, annual payments, and other obligations from policies held		30,131,403	9,201,388	6,808,382
Collections derived from leasing and subsequent sale of these assets		7,938,954	—	—
Other collections from operating activities		929,839	23,353,592	15,216,737
Types of payment in cash from operating activities
Payments to suppliers for goods and services		(1,923,705,670)	(1,921,809,622)	(2,068,346,327)
Payments to and on behalf of employees		(130,102,939)	(119,944,410)	(128,787,065)
Payments on premiums and services, annual payments, and other obligations from policies held		(16,828,690)	(15,704,586)	(15,466,609)
Payments for manufacturing or acquiring assets held to lease to others and subsequently to sell		(39,625,028)	—	—
Other payments for operating activities		(154,500,049)	(137,352,099)	(130,403,003)
Cash flows from (used in) operating activities
Income taxes paid		(82,778,533)	(134,512,945)	(183,022,750)
Other outflows of cash, net		(1,114,199)	(5,536,297)	(7,405,397)
Net cash flows from operating activities		743,711,719	735,525,522	635,613,720
Cash flows from (used in) investing activities
Cash flows from the loss or gains of control of subsidiaries or other businesses, net	27.1.3	—	(1,624,326,739)	—
Other collections from the sale of equity or debt instruments belonging to other entities		—	—	115,582,806
Other payments to acquire equity or debt instruments of other entities		(130,639)	—	—
Other payments to acquire stakes in joint ventures			—	(1,943,100)
Loans to related companies		—	(37,940,159)	(161,363,897)
Proceeds from the sale of property, plant and equipment		872,988	4,640,835	4,428,995
Purchases of property, plant and equipment		(300,346,362)	(300,538,836)	(266,029,921)
Purchases of intangible assets		(20,732,156)	—	—
Payments for future, forward, option and swap contracts		(7,551,080)	(1,475,713)	(7,808,837)
Collections from future, forward, option and swap contracts		2,737,887	352,734	835,105
Collections from related companies		—	76,307,192	161,363,898
Dividends received		6,455,840	1,520,979	879,884
Interest received		6,034,028	6,653,972	7,589,290
Other inflows (outflows) of cash		1,127,683	(6,753,959)	—
Net cash flows used in investing activities		(311,531,811)	(1,881,559,694)	(146,465,777)
Cash flows from (used in) financing activities
Payments proceeds from share Issuance		—	665,829,207	—
Payments for acquiring treasury shares	27.1.2	—	(72,388,009)	—
Total Amounts from long-term loans		—	1,565,782,604	—
Proceeds from long-term loans	8.e	—	1,565,782,604	—
Loans from related companies	8.e	283,831,505	—	150,000,000
Payments of loans	8.e	(315,323,464)	(819,525,929)	(5,534,483)
Payments on borrowings and lease liabilities	8.e	(4,498,202)	(1,889,685)	(2,592,237)
Payment of loans to related companies	8.e	—	—	(150,000,000)
Dividends paid		(236,478,649)	(231,392,743)	(260,803,055)
Interest paid	8.e	(134,429,754)	(116,540,891)	(43,816,959)
Other outflows of cash, net	8.e	(33,537,124)	(23,297,678)	(4,848,787)
Net cash flows from (used in) financing activities		(440,435,688)	966,576,876	(317,595,521)
Net increase (decrease) in cash and cash equivalents before effect of exchange rate changes		(8,255,780)	(179,457,296)	171,552,422
Effect of exchange rate changes on cash and cash equivalents
Effect of exchange rate changes on cash and cash equivalents		(1,231,644)	5,173,194	1,904,412
Net increase (decrease) in cash and cash equivalents		(9,487,424)	(174,284,102)	173,456,834
Cash and cash equivalents at beginning of year	8	245,171,924	419,456,026	245,999,192
Cash and cash equivalents at end of year	8	235,684,500	245,171,924	419,456,026

The accompanying notes are an integral part of these consolidated financial statements

F-12

ENEL CHILE S.A

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contents	Page
1. BACKGROUND AND BUSINESS ACTIVITIES	F-16
2. BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS.	F-17
2.1 Basis of preparation	F-17
2.2 New accounting pronouncements	F-17
2.3 Responsibility for the information, judgments and estimates provided	F-22
2.4 Subsidiaries	F-24
2.4.1 Changes in the scope of consolidation	F-24
2.5 Investment in associates	F-25
2.6 Investment in joint arrangements	F-25
2.7 Basis of consolidation and business combinations	F-26
3. ACCOUNTING POLICIES APPLIED.	F-28
a) Property, plant and equipment	F-28
b) Investment property	F-29
c) Goodwill	F-29
d) Intangible assets other than goodwill	F-30
d.1) Research and development expenses	F-30
d.2) Other intangible assets	F-30
e) Impairment of non-financial assets	F-30
f) Leases	F-32
g) Financial instruments	F-33
g.1) Financial assets other than derivatives	F-33
g.2) Cash and cash equivalents	F-34
g.3) Impairment of financial assets	F-34
g.4) Financial liabilities other than derivatives	F-35
g.5) Derivative financial instruments and hedge accounting	F-36
g.6) Derecognition of financial assets and liabilities	F-37
g.7) Offsetting financial assets and liabilities.	F-37
g.8) Financial guarantee contracts	F-37
h) Measurement of fair value	F-38
i) Investments accounted for using the equity method	F-39
j) Inventories	F-39
k) Non-current assets (or disposal group of assets) held for sale or held for distribution to owners and discontinued operations	F-39
l)Treasury shares	F-40
m) Provisions	F-40
m.1) Provisions for post-employment benefits and similar obligations	F-41
n) Translation of foreign currency balances	F-41
o) Current/non-current classification	F-41
p) Income taxes	F-42
q) Revenue and expense recognition	F-42
r) Earnings per share	F-44
s) Dividends	F-44
t) Share issuance costs	F-44
u) Statement of cash flows	F-45
4. SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS.	F-45
a) Regulatory framework	F-45
a.1 Generation Segment	F-46
a.2. Transmission Segment	F-47
a.3 Distribution segment	F-47
b) Regulatory Developments in 2019	F-48
c) Tariff Revisions	F-50
c.1 Distribution Tariff Setting	F-50
c.2 Setting of Service Tariffs Associated with Distribution	F-51
c.3 Subtransmission Tariff Setting	F-51
c.4 Transmission Tariff Setting 2020‑2023	F-51

F-13

c.5 Energy Tenders	F-52
5. NON-CURRENT ASSETS OR DISPOSAL GROUPS HELD FOR SALE.	F-52
6. BUSINESS COMBINATION UNDER COMMON CONTROL.	F-53
7. ARGENTINA’S HYPERINFLATIONARY ECONOMY.	F-54
8. CASH AND CASH EQUIVALENTS.	F-55
9. OTHER FINANCIAL ASSETS.	F-57
10. OTHER NON-FINANCIAL ASSETS AND LIABILITIES.	F-57
11. TRADE AND OTHER RECEIVABLES.	F-58
12. BALANCES AND TRANSACTIONS WITH RELATED PARTIES.	F-61
12.1 Balances and transactions with related parties	F-61
12.2 Board of Directors and key management personnel	F-64
12.3 Compensation for key management personnel	F-66
12.4 Incentive plans for key management personnel	F-66
12.5 Compensation plans linked to share price	F-66
13. INVENTORIES.	F-67
14. CURRENT TAX ASSETS AND LIABILITIES.	F-67
15. INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD.	F-68
15.1. Investments accounted for using the equity method	F-68
15.2. Investments with significant influence	F-70
15.3. Joint ventures	F-70
16. INTANGIBLE ASSETS OTHER THAN GOODWILL.	F-71
17. GOODWILL.	F-72
18. PROPERTY, PLANT AND EQUIPMENT.	F-74
19. INVESTMENT PROPERTY.	F-80
20. INCOME TAX AND DEFERRED TAXES.	F-81
21. OTHER FINANCIAL LIABILITIES.	F-84
21.1 Interest-bearing borrowings	F-84
21.2 Unsecured liabilities	F-87
21.3 Secured liabilities	F-88
21.4 Detail of finance lease obligations	F-89
21.5 Hedged debt	F-90
21.6 Other information	F-90
21.7 Future undiscounted debt flow	F-90
22. RISK MANAGEMENT POLICY.	F-92
22.1 Interest rate risk	F-92
22.2 Exchange rate risk	F-92
22.3 Commodities risk	F-93
22.4 Liquidity risk	F-93
22.5 Credit risk	F-94
22.6 Risk measurement	F-94
23. FINANCIAL INSTRUMENTS.	F-95
23.1 Financial instruments, classified by type and category	F-95
23.2 Derivative instruments	F-96
23.3 Fair value hierarchy	F-98
24. TRADE AND OTHER CURRENT PAYABLES.	F-99
25. PROVISIONS.	F-99
26. EMPLOYEE BENEFIT OBLIGATIONS.	F-100
26.1 General information	F-100
26.2 Details, changes and presentation in financial statements	F-101
26.3 Other disclosures	F-102
27. EQUITY.	F-102
27.1 Equity attributable to the shareholders of Enel Chile	F-102
27.2 Dividends	F-104
27.3 Foreign currency translation reserves	F-104
27.4 Restrictions on consolidated subsidiaries transferring funds to the parent	F-104
27.5 Other reserves	F-105
27.6 Non-controlling Interests	F-106
28. REVENUE AND OTHER OPERATING INCOME.	F-107
29. RAW MATERIALS AND CONSUMABLES USED.	F-108

F-14

30. EMPLOYEE BENEFITS EXPENSE.	F-108
31. DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES.	F-109
32. OTHER EXPENSES.	F-109
33. OTHER GAINS (LOSSES).	F-110
34. FINANCIAL RESULTS.	F-110
35. INFORMATION BY SEGMENT.	F-111
35.1 Basis of segmentation	F-111
35.2 Generation, distribution and others	F-113
36. THIRD PARTY GUARANTEES, OTHER CONTINGENT ASSETS AND LIABILITIES, AND OTHER COMMITMENTS.	F-116
36.1 Direct guarantees	F-116
36.2 Indirect guarantees	F-116
36.3 Lawsuits and Arbitration Proceedings	F-116
36.4 Financial restrictions	F-119
37. PERSONNEL FIGURES.	F-122
38. SANCTIONS.	F-122
39. ENVIRONMENT.	F-124
40. SUMMARIZED FINANCIAL INFORMATION OF SUBSIDIARIES.	F-127
41. SUBSEQUENT EVENTS.	F-128
APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY	F-129
APPENDIX 2 ADDITIONAL INFORMATION OFICIO CIRCULAR (OFFICIAL BULLETIN) No. 715 OF FEBRUARY 3, 2012	F-131
APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES	F-133
APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY	F-135
APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS	F-136

F-15

ENEL CHILE S.A. AND ITS SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2019 AND 2018 AND FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(In thousands of Chilean pesos - ThCh)

1.BACKGROUND AND BUSINESS ACTIVITIES

Enel Chile S.A. (hereinafter the “Parent Company” or the “Company”) and its subsidiaries comprise the Enel Chile Group (hereinafter the “Group”).

The Company is a publicly traded corporation with registered address and head office located at Avenida Santa Rosa, No. 76, in Santiago, Chile. Since April 13, 2016, the Company is registered in the securities register of the Financial Market Commission of Chile (“Comisión para el Mercado Financiero” or “CMF”, formerly the Chilean Superintendence of Securities and Insurance, “Superintendencia de Valores y Seguros” or “SVS”) and since March 31, 2016 is registered with the Securities and Exchange Commission of the United States of America. On April 21, 2016, the Company’s shares began trading on the Santiago Stock Exchange and the Electronic Stock Exchange. In addition, the Company’s common stock began trading in the United States in the form of American Depositary Shares on the New York Stock Exchange by way of “when-issued” trading from April 21, 2016 to April 26, 2017 and “regular-way” trading since April 27, 2016.

Enel Chile is a subsidiary of Enel S.p.A., an entity that directly and indirectly owns a 61.93% equity interest.

The Company was initially incorporated by public deed dated January 22, 2016 and came into legal existence on March 1, 2016 under the name of Enersis Chile S.A. The Company changed its name to Enel Chile S.A. effective October 4, 2016, the date its by-laws were amended in connection with the corporate reorganization of the Group. For tax purposes, the Company operates under Chilean tax identification number 76.536.353‑5.

As of December 31, 2019, the Group had 2,148 employees. During the fiscal year ended December 31, 2019, the Group averaged a total of 2,142 employees (see Note 37).

Enel Chile’s corporate purpose consists of exploring, developing, operating, generating, distributing, transporting, transforming and/or sale of energy in any of its forms or nature, directly or through other entities within Chile. Additionally, it is also engaged in investing and managing its investments in its subsidiaries and associates, whose activities include the generation, transmission, distribution or selling of electrical energy, or whose corporate purpose includes any of the following:

i) Energy of any kind or form,

ii) Supplying public services, or services whose main component is energy,

iii) Telecommunications and information technology services, and

iv) Internet-based intermediation business.

F-16

2.BASIS OF PRESENTATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

2.1 Basis of preparation

The accompanying consolidated financial statements as of December 31, 2019 of Enel Chile approved by the Company’s Board of Directors at its meeting held on April 29, 2020, have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

These consolidated financial statements reflect faithfully the financial position of Enel Chile and its subsidiaries at December 31, 2019 and 2018, and the results of their operations, changes in their equity and their cash flows for the year ended December 31, 2019, 2018 and 2017 and corresponding notes.

These consolidated financial statements have been prepared under going concern assumptions on a historical cost basis except when, in accordance with IFRS, those assets and liabilities that are measured at a fair value.

These consolidated financial statements are presented in thousands of Chilean pesos (unless expressly stated otherwise) s the Chilean peso is the functional currency of the Company and the presentation currency of the Group.

2.2   New accounting pronouncements

a)    The following accounting pronouncements have been adopted by the Group effective as of January 1, 2019:

i. New Standards and Interpretations

New Standards and Interpretations	Mandatory Effective Date:
IFRS 16: Leases	Annual periods beginning on or after January 1, 2019
IFRIC 23: Uncertainty over Income Tax Treatments	Annual periods beginning on or after January 1, 2019

· IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 which establishes recognition, measurement, presentation and disclosure principles for lease agreements. IFRS 16 supersedes IAS 17 Leases and its interpretations: IFRIC 4 Determining whether an Arrangement contains a Lease, SIC-15 Operating Leases—Incentives and SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a Lease. The standard became effective on  January 1, 2019.

IFRS 16 is based on the concept of control in determining whether a contract is, or contains, a lease. In relation to the accounting treatment for a lessee and a lessor, the new standard states the following:

i) Lessee accounting: IFRS 16 requires lessees to account for all leases under a single model, similar to accounting for finance leases under IAS 17. As a result, at the date of commencement of a lease, the lessee recognizes on the statement of financial position a right  of use asset and a lease liability for the future lease payments. Subsequent to initial recognition it will recognize in the statement of profit or loss the depreciation expense of the asset separately from the interest related to the liability for leases. The standard provides two voluntary recognition exceptions for low-value asset leases and short-term leases (equal to or less than 12 months).

ii) Lessor accounting: does not change substantially from the model  established for IAS 17. The lessor must classify leases as operating or financial leases under the same principles of the previous standard.

F-17

The implementation of IFRS 16 by the Group required the application of judgment and assumptions, which are summarized as  follows:

- Analysis of the lease contracts within the scope of the standard. This analysis included not only the contracts in which the Group’s companies act as a lessee, but also the contracts for the rendering of services and the contracts in which the Group companies act as a lessor.

- Estimate of the lease terms. This is based on the non-cancellable period and the periods covered by the renewal options, the exercise of which is in the power of Enel Chile and is considered reasonably certain.

- Estimate of the discount rate to calculate the present value of the lease payments. This is equal to the lessee’s incremental borrowing rate when the interest rate implicit in the lease cannot be easily determined. For the transition, in the calculation of the effects as of January 1, 2019, the Group used the lessee’s incremental borrowing rate, defined as the interest rate that the Group would have to pay to borrow over a similar term, and with a similar security, the funds necessary to obtain an asset of a value similar to the right-of-use asset in a similar economic environment.

The Group decided to use certain exemptions from application of the standard, relating to lease contracts with a maturity of less than 12 months or that have underlying assets of low individual value, such as the lease of certain office equipment (personal computers, printers and photocopiers). See Notes 3.f and 18.d.

For the transition of the new standard, the Group applied the following practical expedients:

- Not to re-evaluate if a contract is, or contains, a lease. Instead, the Group applied the standard to contracts that were previously identified as leases by applying IAS 17 and IFRIC 4. Therefore, the Group did not apply the standard to contracts that were not previously identified as containing a lease.

- Apply the standard retrospectively with the cumulative effect of the initial application. This means not restating comparative periods and presenting the cumulative effect of the initial application of the standard as an adjustment to the opening balance of retained earnings as of January 1, 2019.

- Recognize right-of-use assets on the initial date of application for an amount equal to the lease liabilities, adjusted by the amount of any advance or accumulated lease payments recognized in the statement of financial position immediately before the initial date of application.

The new standard has an impact on all Group entities that have lease contracts. The main issues that arise are those related to the lease of land, buildings and automobiles. As a result of the change in the accounting model for lessees, the Group recorded an increase in current and non-current liabilities for a total of ThCh$28,814,142 as of January 1, 2019, for the recognition of lease liabilities, and an increase in non-current assets for the same amount, as a result of the recognition of the right of use assets in such contracts. It should be noted that the application of the Standard did not result in any effect being recognized in the opening balance of retained earnings as of January 1, 2019. For further information see Notes 18.c and 21.

The weighted average of the incremental borrowing rate used to record lease liabilities as of January 1, 2019, was 5.5%.

The reconciliation between the total amount of the minimum future payments under operating lease agreements according to IAS 17 and the finance lease liability recorded as of January 1, 2019, is as follows:

	ThCh$
Minimum future payments of operating leases as of 12-31-2018	47,415,134
Effect of the discount at the incremental borrowing rate	(18,027,491)
Minimum payments for short-term leases, at the transition date	(573,501)
Lease liabilities	28,814,142

F-18

During the year ended December 31, 2019, the Group recognized an increase of ThCh$1,191,645 in financial expenses associated with the new lease liabilities and an increase of ThCh$2,347,661 in depreciation associated with the right of use assets.

· IFRIC 23 – Uncertainty over Income Tax Treatments

In June 2017, the IASB issued IFRIC 23 to clarify the application of recognition and measurement requirements in IAS 12, Income Taxes, when there is uncertainty over income tax treatments. The Interpretation specifically addresses the following: whether an entity considers uncertain tax treatments separately; the assumptions an entity makes about the examination of tax treatments by taxation authorities; how an entity determines taxable profit (loss), tax bases, unused tax losses, unused tax credits and tax rates; and how an entity considers changes in facts and circumstances.

Uncertainty over income tax treatments can affect both current and deferred taxes. Recognizing the effects of uncertainty depends on whether the tax authority is likely or not to accept an uncertain tax treatment, assuming that the tax authority will examine the amounts that it is entitled to examine and has full knowledge of all the related information.

This interpretation became effective on January 1, 2019. The application of IFRIC 23 did not have a material impact on the Group’s consolidated financial statements.

ii.Amendments and Improvements

Amendments and Improvements	Mandatory Effective Date:
Amendment to IFRS 9: Prepayment Features with Negative Compensation	Annual periods beginning on or after January 1, 2019
Amendment to IAS 28: Long-term interests in Associates and Joint Ventures	Annual periods beginning on or after January 1, 2019
Annual Improvements to IFRS: 2015 - 2017 Cycle (IFRS 3, IFRS 11, IAS 12 and IAS 23)	Annual periods beginning on or after January 1, 2019
Amendment to IAS 19: Plan Amendment, Curtailment or Settlement	Annual periods beginning on or after January 1, 2019

· Amendment to IFRS 9: Prepayment Features with Negative Compensation

This amendment was issued on October 12, 2017 and amends the existing requirements in IFRS 9 Financial Instruments regarding termination rights in order to allow measurement of financial assets at amortized cost (or, depending on the business model, at fair value through other comprehensive income) even in the case of negative compensation prepayments.

Under IFRS 9, a debt instrument can be measured at amortized cost or at fair value through profit or loss in other comprehensive income, provided that the contractual cash flows are only principal and interest payments on the outstanding principal and the instrument is carried out within the business model for that classification. The amendments to IFRS 9 are intended to clarify that a financial asset meets the criterion of “only principal payments plus interest”, regardless of the event or circumstance that causes the early termination of the contract or of which party pays or receives reasonable compensation for the early termination of the contract.

The amendments to IFRS 9 should be applied when the prepayment is close to the unpaid amounts of principal and interest in such a way that it reflects the change in the benchmark interest rate. This implies that prepayments at fair value or for an amount that includes the fair value of the cost to terminate an associated hedging instrument will normally meet the criterion of only principal payments plus interest, only if other elements of the change in fair value, such as the effects of credit risk or liquidity, are minimal.

F-19

The application of this amendment, as of January 1, 2019, did not have a material impact on the Group’s consolidated financial statements.

· Amendments to IAS 28: Long-term interests in Associates and Joint Ventures

This amendment clarifies that IFRS 9 is applicable to an entity's long-term interests in an associate or joint venture to which the equity method is not applied. This clarification is relevant because it implies that the expected credit loss model, described in IFRS 9, applies to these long-term interests.

The application of this amendment, as of January 1, 2019. , did not have a material impact on the Group’s consolidated financial statements.

· Annual Improvements to IFRS: 2015 - 2017 Cycle (IFRS 3, IFRS 11, IAS 12 and IAS 23).

IFRS 3 Business Combinations and IFRS 11  Joint Arrangements : it clarifies the accounting for increases in ownership interest in a joint operation that meets the definition of a business. If a party maintains (or obtains) joint control, the previously held ownership interest is not remeasured. If a party obtains control, the transaction is a business combination  archivied in stages and the acquiring party remeasures the previously held ownership interest in the assets and liabilities of a joint operation, at fair value.

The IAS 12 Income Taxes amendment: it clarifies that the income tax on dividends is linked more directly to past transactions or events that generated distributable profits than to distributions to shareholders. Therefore, an entity recognizes income tax on dividends in profit or loss, other comprehensive income or equity according to where the entity originally recognized those past transactions or past events.

IAS 23 Borrowing Costs: it clarifies that loans that were specifically intended to finance qualifying assets become part of the entity's general loan pool for the purpose of calculating the capitalization rate, when substantially all of the activities necessary to prepare the asset for its intended use or sale are complete.

The application of these improvements, as of January 1, 2019 did not have a material impact on the Group’s consolidated financial statements.

· Amendment to IAS 19: Plan Amendment, Curtailment or Settlement

The amendment to IAS 19 Employee Benefits, issued in February 2018, addresses the accounting when a plan amendment, curtailment or settlement occurs during a reporting period. The amendment specifies that an entity is required to determine the current service cost and net interest for the remainder of the annual period using the actuarial assumptions used to remeasure the benefit liability (asset) and plan assets of the plan after the plan amendment, curtailment or settlement.

The amendment to IAS 19 also clarifies that an entity first determines any past service cost, or a gain or loss on settlement, without considering the effect of the asset ceiling. This amount is recognized in profit or loss. An entity then determines the effect of the asset ceiling after the plan amendment, curtailment or settlement. Any change in that effect, excluding amounts included in net interest, is recognized in other comprehensive income.

This clarification provides that entities might have to recognize a past service cost, or a gain or loss on settlement, that reduces a surplus that was not recognized before. Changes in the effect of the asset ceiling are not netted against such amounts.

The amendments to IAS 19 apply to a plan amendment, curtailment or settlement that occurred on or after January 1, 2019. The Group did not have any of those events during the year ended December 31, 2019.

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b) Accounting pronouncements with application effective as of January 1, 2020 and thereafter:

As of the date of issuance of these consolidated financial statements, the following accounting pronouncements had been issued by the IASB, but their application is not mandatorily effective:

i.   New Standards and Interpretations

Amendments and Improvements	Mandatory Effective date:
Conceptual Framework (Revised)	Annual periods beginning on or after January 1, 2020
Amendment to IFRS 3: Definition of a Business	Annual periods beginning on or after January 1, 2020
Amendment to IAS 1 and IAS 8: Definition of material or materiality	Annual periods beginning on or after January 1, 2020
Amendments to IFRS 9, IAS 39 and IFRS 7: Reform of the reference interest rates.	Annual periods beginning on or after January 1, 2020

· Conceptual Framework (Revised).

The IASB issued the Conceptual Framework (Revised) in March 2018. It incorporates some new concepts, provides updated definitions and recognition criteria for assets and liabilities and clarifies some important matters. Revisions to the Conceptual Framework may affect the application of IFRS when no standard applies to a particular transaction or event.

The IASB has also issued a separate accompanying document, “Amendments to References to the Conceptual Framework in IFRS Standards”, which establishes amendments to affected IFRSs in order to update references to the new Conceptual Framework.

The revised Conceptual Framework and the Amendments to the References to the Conceptual Framework in IFRS Standards take effect on January 1, 2020. Early application is allowed if all the changes made are adopted at the same time. Management estimates that the application of the Revised Conceptual Framework will not generate significant impacts on the Group's consolidated financial statements

· Amendments to IFRS 3  Definition of a Business

IFRS 3 Business Combinations was amended by the IASB in October 2018, to clarify the definition of business, in order to help entities to determine whether a transaction should be accounted for as a business combination or as the acquisition of an asset. To be considered as a business, an acquired integrated set of activities and assets must include, at least, an input and a substantive process that together contribute significantly to the ability to create output.

The amendment also adds guidance and illustrative examples to assess whether a substantial process has been acquired and introduces an optional fair value concentration test.

The amendment is applicable prospectively to business combinations and acquisitions of assets, the acquisition date of which is from January 1, 2020. Earlier application is permitted.

· Amendments to IAS 1 and IAS 8 Definition of Material or Materiality

In October 2018, the IASB amended IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors, to improve the definition of “material” and the explanations accompanying the definition. The amendments ensure that the definition of material is consistent in all IFRS.

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Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.

The amendments will be applicable prospectively for annual periods beginning on or after January 1, 2020. Earlier application is permitted.

· Amendments to IFRS 9, IAS 39 and IFRS 7 – Interest rate benchmark reform.

On September 26, 2019, the IASB issued amendments to IFRS 9 Financial Instruments, IAS 39 Financial Instruments: Recognition and Measurement, and IFRS 7 Financial Instruments: Disclosures, in response to the reform that gradually eliminates benchmark interest rates, such as interbank offer rates (IBORs). The amendments provide temporary reliefs which enable hedge accounting to continue during the period of uncertainty before the replacement of an existing interest rate benchmark with an alternative nearly risk-free interest rate (an RFR).

The amendments to IFRS 9:

The amendments include a number of reliefs, which apply to all hedging relationships that are directly affected by the interest rate benchmark reform. A hedging relationship is affected if the reform gives rise to uncertainties about the timing and/or amount of benchmark-based cash flows of the hedged item or the hedging instrument.

Application of the reliefs is mandatory. The first three reliefs provide for:

· The assessment of whether a forecast transaction (or component thereof) is highly probable

· Assessing when to reclassify the amount in the cash flow hedge reserve to profit and loss 

· The assessment of the economic relationship between the hedged item and the hedging instrument

For each of these reliefs, it is assumed that the benchmark on which the hedged cash flows are based (whether or not contractually specified) and/or, for relief three, the benchmark on which the cash flows of the hedging instrument are based, are not altered as a result of IBOR reform.

A fourth relief provides that, for a benchmark component of interest rate risk that is affected by IBOR reform, the requirement that the risk component is separately identifiable need be met only at the inception of the hedging relationship. Where hedging instruments and hedged items may be added to or removed from an open portfolio in a continuous hedging strategy, the separately identifiable requirement need only be met when hedged items are initially designated within the hedging relationship.

The reliefs continue indefinitely in the absence of any of the  events described in the amendments. When an entity designates  a group of items as the hedged item, the requirements for when  the reliefs cease are applied separately to each individual item  within the designated group of items.

The amendments also introduce specific disclosure requirements  for hedging relationships to which the reliefs are applied.

The amendments are applicable for annual periods beginning on or after January 1, 2020. Earlier application is permitted. Management is evaluating the potential impact of the application of these amendments on the consolidated financial statements of the Group.

2.3 Responsibility for the information, judgments and estimates provided

The Company’s Board of Directors is responsible for the information contained in these consolidated financial statements and expressly states that all IFRS principles and standards, have been fully implemented.

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In preparing the consolidated financial statements, certain judgments and estimates made by the Group’s Management have been used to quantify some of the assets, liabilities, revenue, expenses and commitments recognized.

The most important areas where critical judgment was required are:

· The identification of Cash Generating Units (CGU) for impairment testing (see Note 3.e).

· The hierarchy of information used to measure assets and liabilities at fair value (see Note 3.h)

· Application of the revenue recognition model in accordance with IFRS 15 (see Note 3.q)

The estimates refer basically to:

· The valuations performed to determine the existence of impairment losses in non-financial assets and goodwill (see Note 3.e).

· The assumptions used to calculate the actuarial liabilities and obligations with employees, such as discount rates, mortality tables, salary increases, etc. (see Notes 3.m.1 and 26).

· The useful lives of property, plant and equipment, and intangible assets (see Notes 3.a and 3.d).

· The assumptions used to calculate the fair value of financial instruments (see Notes 3.h and 23).

· The energy supplied to customer whose meters have not yet been read.

· Certain assumptions inherent in the electricity system affecting transactions with other companies, such as production, customer billings, energy consumption, that allow for estimation of electricity system settlements that occur on the corresponding final settlement dates, but that are pending as of the date of issuance of the consolidated financial statements and could affect the balances of assets, liabilities, income and expenses recognized in the financial statements (see Appendix 2.2).

· The interpretation of new regulations related to the Electric Sector, whose ultimate economic effects will be determined by the resolutions of the relevant agencies (see Notes 4 and 11).

· The probability that uncertain or contingent liabilities will be incurred and their related amounts (see Note 3.m).

· Future disbursements for closure of facilities and restoration of land, as well as associated discount rates to be used (see Note 3.a).

· The tax results of the various subsidiaries of the Group that will be reported to the respective tax authorities in the future, and that have been used as the basis for recording the various income tax related balances in these consolidated financial statements (see Note 3.p).

· The fair value of assets acquired and liabilities assumed, and any pre-existing interest in an entity acquired in a business combination.

· Determination of expected credit losses on financial assets (see Note 3.g.3).

· Determination of the lease term of contracts with renewal options, as well as the rates to be used to discount lease payments (see Note 3.f).

· Estimation of the company's incremental borrowing rate (IBR), to measure lease liabilities, if the interest rate implicit in the lease cannot be readily determined. The Group estimates the IBR using observable inputs (such

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as market interest rates) when available and is required to make certain entity-specific estimates (such as for subsidiaries that do not enter into financing transactions) or when they need to be adjusted to reflect the terms and conditions of the lease (for example, when leases are not in the subsidiary’s functional currency) (see Note 3.f).

Although these judgments and estimates have been based on the best available information as of the issuance date of these consolidated financial statements, future events may occur that would require a change (increase or decrease) to these judgments and estimates in subsequent periods. This change would be made prospectively, recognizing the effects of this change in judgment and estimation in the corresponding future consolidated financial statements.

2.4 Subsidiaries

Subsidiaries are defined as those entities controlled either, directly or indirectly by Enel Chile. Control is exercised if, and only if, the following conditions are met: the Company has i) power over the subsidiary; ii) exposure or rights to variable returns from these entities; and iii) the ability to use its power to influence the amount of these returns.

Enel Chile has power over its subsidiaries when it holds the majority of the substantive voting rights or, should that not be the case, when it has rights granting the practical ability to direct the entities’ relevant activities, that is, the activities that significantly affect the subsidiary’s results.

The Group will reassess whether or not it controls a subsidiary if facts and circumstances indicate that there are changes to one or more of the elements of control listed above.

Subsidiaries are consolidated as described in Note 2.7.

The following are the entities in which the Group has the ability to exercise control and are therefore included in these consolidated financial statements:

			Percentage of control at 12-31-2019			Percentage of control at 12-31-2018
Taxpayer ID No.	Company	Currency	Direct	Indirect	Total	Direct	Indirect	Total
76.722.488-5	Empresa de Trasmisión Chena S.A.	Chilean Peso	—	100.00%	100.00%	—	100.00%	100.00%
96.783.910-8	Empresa Eléctrica de Colina Ltda.	Chilean Peso	—	100.00%	100.00%	—	100.00%	100.00%
96.504.980-0	Empresa Eléctrica Pehuenche S.A.	Chilean Peso	—	92.65%	92.65%	—	92.65%	92.65%
96.800.570-7	Enel Distribución Chile S.A.	Chilean Peso	99.09%	—	99.09%	99.09%	—	99.09%
91.081.000-6	Enel Generación Chile S.A.	Chilean Peso	93.55%	—	93.55%	93.55%	—	93.55%
78.932.860-9	GasAtacama Chile S.A. *	Chilean Peso	—	—	—	2.63%	97.37%	100.00%
78.952.420-3	Gasoducto Atacama Argentina S.A.*	Chilean Peso	—	—	—	—	100.00%	100.00%
96.800.460-3	Luz Andes Ltda.	Chilean Peso	—	100.00%	100.00%	—	100.00%	100.00%
77.047.280-6	Sociedad Agrícola de Cameros Ltda.	Chilean Peso	57.50%	—	57.50%	57.50%	—	57.50%
96.920.110-0	Enel Green Power Chile Ltda.**	American Dollar	99.99%	—	99.99%	99.99%	—	99.99%
96.524.140-K	Empresa Eléctrica Panguipulli S.A.**	American Dollar	0.04%	99.96%	100.00%	0.04%	99.96%	100.00%
76.306.985-0	Diego de Almagro Matriz SpA**	American Dollar	—	100.00%	100.00%	—	100.00%	100.00%
76.179.024-2	Parque Eólico Tal Tal SpA**	American Dollar	0.01%	99.99%	100.00%	0.01%	99.99%	100.00%
96.971.330-6	Geotérmica del Norte S.A.**	American Dollar		84.59%	84.59%		84.59%	84.59%
99.577.350-3	Empresa Nacional de Geotermia S.A.**	American Dollar	—	51.00%	51.00%	—	51.00%	51.00%
76.052.206-6	Parque Eólico Valle de los Vientos SpA**	American Dollar	0.01%	99.99%	100.00%	0.01%	99.99%	100.00%
76.126.507-5	Parque Talinay Oriente S.A.**	American Dollar	—	60.91%	60.91%	—	60.91%	60.91%
76.321.458-3	Almeyda Solar SpA**	American Dollar	—	100.00%	100.00%	—	100.00%	100.00%
76.412.562-2	Enel Green Power del Sur SpA**	American Dollar	—	100.00%	100.00%	—	100.00%	100.00%
76.924.079-9	Enel X Chile SpA***	Chilean Peso	100.00%	—	100.00%	100.00%	—	100.00%

(*)       see section 2.4.1 (i)below

(**)     see section 2.4.1 (ii) below.

(***)   see section 2.4.1 (iii) below

2.4.1 Changes in the scope of consolidation

(i) Gasoducto GasAtacama Argentina S.A. was taken over by GasAtacama Chile S.A. on September 1, 2019, with the latter as the legal successor. Subsequently, on October 1, 2019, GasAtacama Chile S.A. was taken over by Enel Generación Chile S.A. as a result of a transaction approved by the Board of Directors of Enel Generación Chile S.A. on August 29, 2019. The transanction consisted of Enel Generación Chile S.A.’s acquisition of 2.63% of the shares in GasAtacama Chile S.A. held by Enel Chile. As a result, Enel

F-24

Generación Chile S.A. became the owner of 100% of the shares in GasAtacama Chile S.A., absorbing it through a merger, and becoming its legal successor.

(ii) On April 2, 2018, renewable energy assets held in Chile by Enel Green Power Latin Americas S.A. ("EGPL") were incorporated into Enel Chile (see Note 6). The EGPL group comprises the following companies.

-Enel Green Power Chile Ltda.

-Empresa Eléctrica Panguipulli S.A.

-Diego de Almagro Matriz SpA

-Parque Eólico Tal Tal S.p.A.

-Geotérmica del Norte S.A.

-Empresa Nacional de Geotermia S.A.

-Parque Eólico Valle de los Vientos S.p.A.

-Parque Talinay Oriente S.A.

-Almeyda Solar SpA

-Enel Green Power del Sur SpA

(i) On September 7, 2018, the subsidiary Enel X Chile SpA was incorporated. The purpose of this subsidiary, among others, is to develop, implement and sell products and services related to energy that incorporate innovation, state-of-the-art technology and trends of the future, other than the electricity distribution under concession and their related services, whether or not they are priced.

2.5 Investments in associates

Associates are those entities over which Enel Chile, either directly or indirectly, exercises significant influence.

Significant influence is the power to participate in the financial and operational policy decisions of the associate but is not control or joint control over those policies.

In assessing significant influence, the Group takes into account the existence and effect of currently exercisable voting rights or convertible rights at the end of each reporting period, including currently exercisable voting rights held by the Company or other entities. In general, significant influence is presumed to be those cases in which the Group has more than 20%of the voting power of the investee

Associates are accounted for under equity method as described in Note 3.i.

The detail of the companies that qualify as associates is the following:

			Ownership Interest at 12-31-2019			Ownership Interest at 12-31-2018
TaxpayerID No.	Company	Currency	Direct	Indirect	Total	Direct	Indirect	Total
76.418.940-K	GNL Chile S.A.	American Dollar	—	33.33%	33.33%	—	33.33%	33.33%
76.364.085-K	Energia Marina SpA	Chilean peso	—	25.00%	25.00%	—	25.00%	25.00%

-On April 2, 2018, renewable energy assets held in Chile EGPL were incorporated into Enel Chile (see Note 6). Among the added companies, it was included the associate Energía Marina SpA..

2.6 Joint arrangements

Joint arrangements are defined as those entities in which the Group exercises control under an agreement with other shareholders and jointly with them, in other words, when decisions on the entities’ relevant activities require the unanimous consent of the parties sharing control.

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Depending on the rights and obligations of the participants, joint agreements are classified as:

-      Joint venture: an agreement whereby the parties exercising joint control have rights to the entity’s net assets. Joint ventures are included in the consolidated financial statements using the equity method, as described in Note 3.i.

-      Joint operation: an agreement whereby the parties exercising joint control have rights to the assets and obligations with respect to the liabilities relating to the arrangement. Joint operations are included in the consolidated financial statements recognizing the interest in the contractually named assets and liabilities in the joint operation.

In determining the type of joint arrangement in which it is involved, the management of the Group assesses its rights and obligations arising from the arrangement by considering the structure and legal form of the arrangement, the terms agreed by the parties in the contractual arrangement and, when relevant, other facts and circumstances. If facts and circumstances change, the Group reassesses whether the type of joint arrangement in which it is involved has changed.

The detail of the companies that qualify as Associates and Joint Venture are the following:

			Ownership Interest at 12-31-2019			Ownership Interest at 12-31-2018
TaxpayerID No.	Company	Currency	Direct	Indirect	Total	Direct	Indirect	Total
76.091.595-5	Aysén Energía S.A. (1)	Chilean peso	—	—	—	—	51.00%	51.00%
76.041.891-9	Aysén Transmisión S.A. (1)	Chilean peso	—	—	—	—	51.00%	51.00%
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chilean peso	—	50.00%	50.00%	—	50.00%	50.00%

(1) The companies Aysén Energía S.A. and Aysén Transmission S.A. were liquidated on June 24, 2019.

Currently, Enel Chile is not involved in any joint arrangement that qualifies as a joint operation.

2.7 Basis of consolidation and business combinations

The subsidiaries are consolidated and all their assets, liabilities, revenues, expenses, and cash flows are included in the consolidated financial statements once the adjustments and eliminations from intra-group transactions have been made.

The comprehensive income of subsidiaries is included in the consolidated statement of comprehensive income from the date when the parent company obtains control of the subsidiary and until the date on which it loses control of the subsidiary.

The operations of the parent company and its subsidiaries have been consolidated under the following basic principles:

1. At the date the parent obtains control, the subsidiary’s assets acquired and its liabilities assumed are recorded at fair value, except for certain assets and liabilities that are recorded using valuation principles established in other IFRS standards. If the fair value of the consideration transferred plus the fair value of any non-controlling interests exceeds the fair value of the net assets acquired, this difference is recorded as goodwill. In the case of a bargain purchase, the resulting gain is recognized in profit or loss after reassessing whether all of the assets acquired and the liabilities assumed have been properly identified and following a review of the procedures used to measure the fair value of these amounts.

For each business combination, IFRSr allow the valuation of the non-controlling interests in the acquiree on the date of acquisition: i) at fair value; or ii) for the proportional ownership of the identifiable net assets of the acquiree, with the latter being the methodology that the Group has systematically applied to its business combinations.

If the fair value of all assets acquired and liabilities assumed at the acquisition date has not been completed, the Group reports the provisional values accounted for in the business combination. During the measurement period, which shall not exceed one year from the acquisition date, the provisional values recognized will be adjusted retrospectively as if the accounting for the business combination had been completed at the acquisition date, and also additional assets or liabilities will be recognized to reflect new information obtained about events and

F-26

circumstances that existed on the acquisition date, but which were unknown to the management at that time. Comparative information for prior periods presented in the financial statements is revised as needed, including making any change in depreciation, amortization or other income effects recognized in completing the initial accounting.

For business combinations achieved in stages, the Company’s previously held equity interest in the acquiree is remeasured to its acquisition date fair value and the resulting gain or loss, if any, is recognized in profit or loss.

2. Non-controlling interests in equity and in comprehensive income of the subsidiaries are presented, respectively, under the line items “Total Equity: Non-controlling interests” in the consolidated statement of financial position and “Net Income attributable to non-controlling interests” and “Comprehensive income (loss) attributable to non-controlling interests” in the consolidated statement of comprehensive income.

3. The financial statements of the companies operating in non- hyper-inflationary economies, with functional currencies other than the Chilean peso are translated as follows:

a. For assets and liabilities, the prevailing exchange rate on the closing date of the financial statements is used.

b. For items of the comprehensive income, the average exchange rate for the period is used (unless this average is not a reasonable approximation of the cumulative effect of the exchange rates in effect on the dates of the transactions, in which case the exchange rate in effect on the date of each transaction is used).

c. For equity accounts the historical exchange rate from the date of acquisition or contribution is used, and retained earnings are translated at the average exchange rate at the date of origination.

d. Exchange differences arising in translation of financial statements are recognized in the item “Foreign currency translation gains (losses)” within the consolidated statement of comprehensive income in other comprehensive income (see Note 27.3).

4. The financial statements of the subsidiaries whose functional currency comes from hyper-inflationary economies, as is the case of the Argentine economy (see Note 7), are first adjusted for the inflation effect, and any gain or loss in the net monetary position is recognized in profit or loss; then all the items (assets, liabilities, equity items, expenses and revenue) are translated using the closing exchange rate corresponding to the closing date of the most recent statement of financial position.

5. Balances and transactions between consolidated companies have been fully eliminated in the consolidation process.

6. Changes in the ownership interests in subsidiaries that do not result in the Group obtaining or losing control are recognized as equity transactions. The carrying amounts of the controlling and non-controlling interests are adjusted to reflect the changes in their relative interests in the subsidiaries. Any difference between the amount by which the non-controlling interests are adjusted and the fair value of the consideration paid or received, is recognized directly in Equity attributable to shareholders of the Parent.

Business combinations between entities under common control are accounted for using, as a reference, the ‘pooling of interest’ method. Under this method, the assets and liabilities involved in the transaction remain reflected at the same carrying amounts at which they were recognized in the ultimate controlling company, although subsequent accounting adjustments may need to be made to align the accounting policies of the companies involved.

Any difference between assets and liabilities contributed to the consolidation and the consideration paid is recorded directly in Net equity as a charge or credit to Other reserves. The Group does not restate comparative periods in its financial statements for business combinations under common control.

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3.    ACCOUNTING POLICIES.

The main accounting policies used in preparing the accompanying consolidated financial statements are the following:

a)    Property, plant and equipment

Property, plant and equipment are measured, with general character, at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. In addition to the price paid to acquire each item, the cost also includes, where applicable, the following concepts:

· Financing expenses accrued during the construction period that are directly attributable to the acquisition, construction, or production of qualified assets, which require a substantial period of time before being ready for use such as, for example, electricity generation or distribution facilities. The Group defines “substantial period” as one that exceeds twelve months. The interest rate used is that of the specific financing or, if none exists, the weighted average financing rate of the company carrying out the investment. (see Note 18.b.1).

· Employee expenses directly related to construction in progress. (see Note 18.b.2).

· Future disbursements that the Group will have to incur to close its facilities are added to the value of the asset at fair value, recognizing the corresponding provision for dismantling or restoration. The Group reviews its estimate of these future disbursements on an annual basis, increasing or decreasing the value of the asset based on the results of this estimate (see Note 25).

Items for construction work in progress are transferred to operating assets once the testing period has been completed and they are available for use, at which time depreciation begins.

Expansion, modernization or improvement costs that represent an increase in productivity, capacity or efficiency, or a longer useful life are capitalized as increasing the cost of the corresponding assets.

The replacement or overhaul of entire components that increase the asset’s useful life or economic capacity are recorded as an increase in cost for the respective assets, derecognizing the replaced or overhauled components.

Expenditures for periodic maintenance, conservation and repair are recognized directly as an expense for the year in which they are incurred.

Property, plant and equipment, net of its residual value, is depreciated by distributing the cost of the different items that comprise it on a straight-line basis over its estimated useful life, which is the period during which the Group expects to use the assets. Useful life estimates and residual values are reviewed on an annual basis and if appropriate adjusted prospectively.

In addition, the Group recognizes right-of-use assets for leases relating to property, plant and equipment in accordance with the criteria established in Note 3.f.

The following table are the main categories of property, plant and equipment with their respective estimated useful lives:

Categories of Property, plant and equipment	Yearsof estimated useful lives
Buildings	10 – 60
Plant and equipment	6 – 65
IT equipment	3 – 15
Fixtures and fittings	2 – 35
Motor vehicles	5 – 10

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Additionally, the following table sets forth more details on the useful lives of plant and equipment items:

Categories of Property, plant and equipment	Years of estimated useful lives
Generating facilities:
Hydroelectric plants
Civil engineering works	10 – 65
Electromechanical equipment	10 – 45
Fuel oil/coal-fired power plants	20 – 40
Combined cycle power plants	10 – 25
Renewable energy power plants	20
Transmission and distribution facilities:
High-voltage network	10 – 60
Low- and medium-voltage network	10 – 50
Measuring and remote control equipment	10 – 50
Primary substations	6 – 25
Natural gas transport facilities
Pipelines	20

Land is not depreciated since it has an indefinite useful life, unless it relates to a right of use asset in which case it is depreciated over the term of the lease.

An item of property, plant and equipment is derecognized when it is sold or otherwise disposed of, or when no future economic benefits are expected from its use, sale or other disposal.

Gains or losses that arise from the sale or disposal of items of Property, plant and equipment are recognized as “Other gains (losses)” in the comprehensive income statement and are calculated by deducting the net carrying amount of the asset and any sales expenses from the amount received in the sale.

b)    Investment property

“Investment property” includes basically land and buildings that are kept for the purpose of obtaining profits in future sales or lease arrangements.

Investment property is measured at acquisition cost, net of accumulated depreciation and any impairment losses they may have experienced. Investment properties, excluding land, are depreciated by distributing the cost of the various elements that make them up on a straight-line basis over the years of useful life.

An investment property is derecognized on disposal, or when no future economic benefits are expected from use or disposal.

Gains or losses that arise from the sale or disposal of items of investment property are recognized as “Other gains (losses)” in the comprehensive income statement and are calculated by deducting the net carrying amount of the asset and any sales costs from the consideration received in the sale.The breakdown of the fair value of investment property is detailed in Note 19.

c)    Goodwill

Goodwill arising from business combinations, and reflected upon consolidation, represents the excess value of the consideration paid plus the amount of any non-controlling interests over the Group’s share of the net value of the assets acquired and liabilities assumed, measured at fair value at the acquisition date. If the accounting for a business combination is completed within the following year after the acquisition date, and so is the goodwill determination, the entity recognizes the corresponding adjustments to the provisional amounts as if the accounting for the business combination had been completed at the acquisition date. If the accounting for a business combination is completed within the following year after the acquisition date, and thus the goodwill determination as well, the entity recognizes

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the corresponding adjustments to the provisional amounts as if the accounting for the business combination had been completed at the acquisition date (see Note 2.7.1).

Goodwill arising from acquisition of companies with functional currencies other than the Chilean peso is measured in the functional currency of the acquired company and translated to Chilean pesos using the exchange rate effective as of the date of the statement of financial position.

Goodwill is not amortized; instead, at the end of each reporting period or when there are indicators that an impairment might have occurred, the Group estimates whether any impairment loss has reduced its recoverable amount to an amount less than the carrying amount and, if so, an impairment loss is immediately recognized in profit or loss (see Note 3.e).

d)    Intangible assets other than goodwill

Intangible assets are initially recognized at their acquisition cost or production cost, and are subsequently measured at their cost, net of their accumulated amortization and impairment losses they may have experienced.

Intangible assets are amortized on a straight line basis during their useful lives, starting from the date when they are ready for use, except for those with an indefinite useful life, which are not amortized. As of December 31, 2019 and 2018, there are no significant intangible assets with an indefinite useful life.

An intangible asset is derecognized on disposal, or when no future economic benefits are expected from use or disposal.

Gains or losses arising from sales of intangible assets are recognized in profit or loss for the period and are determined as the difference between the sale value and the net book value of the asset.

The criteria for recognizing these assets’ impairment losses and, if applicable, recovery of impairment losses recorded in previous periods are explained in Note 3.e below.

d.1) Research and development expenses

The Group recognizes the costs incurred in a project’s development phase as intangible assets in the statement of financial position as long as the project’s technical feasibility and future economic benefits have been demonstrated.

Research costs are recorded as an expense in the consolidated statement of comprehensive income in the period in which they are incurred.

d.2) Other intangible assets

Other intangible assets correspond to computer software, water rights, and easements. They are initially recognized at acquisition or production cost and are subsequently measured at cost less accumulated amortization and impairment losses, if any.

Computer software is amortized (on average) over four years. Certain easements and water rights have indefinite useful lives and, therefore, are not amortized.

e)    Impairment of non-financial assets

During the year, and principally at the end of each reporting period, the Group evaluates whether there is any indication that an asset has been impaired. If any such indication exist, the Group estimates the recoverable amount of that asset to determine the amount of the impairment loss. In the case of identifiable assets that do not generate cash flows independently, the Group estimates the recoverable amount of the Cash Generating Unit (CGU) to which the asset belongs, which is understood to be the smallest identifiable group of assets that generates independent cash inflows.

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Notwithstanding the preceding paragraph, in the case of CGU’s to which goodwill or intangible assets with indefinite useful lives have been allocated, a recoverability analysis is performed routinely at each period end.

The criteria used to identify the CGUs are based, in line with the strategic and operational vision of management, on the specific characteristics of the business, on the operating standards and regulations of the market in which the Group operates and on the corporate organization.

Recoverable amount is the higher of fair value less costs of disposal and value in use, which is defined as the present value of the estimated future cash flows. In order to calculate the recoverable amount of Property, plant, and equipment, as well as of goodwill, and intangible assets, the Group uses value in use criteria in practically all cases.

To estimate value in use, the Group prepares future pre-tax cash flow projections based on the most recent budgets available. These budgets incorporate management’s best estimates of a CGU’s revenue and costs using sector projections, past experience and future expectations.

In general, these projections cover the next five years, estimating cash flows for subsequent years by applying reasonable growth rates which, in no case, are increasing rates nor exceed the average long-term growth rates for the particular sector and country in which the Group operates. As of December 31, 2019, the growth rate used to extrapolate the projections was between 2% and 3%. 

Future cash flows are discounted to calculate their present value at a pre-tax rate that covers the cost of capital for the business activity and the geographic area in which it is being carried out. The time value of money and risk premiums generally used among analysts for the business activity and the geographic zone are taken into account to calculate the pre-tax rate.

The minimum and maximum pre-tax discount rates applied in the period ended December 31, 2019 expressed in nominal terms were 7.7% and 10.7%, respectively.

The Company’s approach to allocate value to each key element used to project cash flows, considers:

- Evolution of demand: the growth estimate has been calculated based on the projected increase of the Gross Domestic Product (GDP), in addition to other assumptions used by the Company regarding the evolution of consumption.

- Energy purchase and sale prices: based on specifically developed internal projection models. The price of the planned “pool” is estimated by considering a series of determining factors, such as the various technologies’ costs and productions and electricity demand, among other items.

- Regulatory measures: an important part of the Company's business is regulated and subject to extensive standards, which could undergo revisions, either as a result of new laws or the amendment of existing ones, and therefore the projections include adequate application of the current standards and those that are currently in development, and those expected to be valid during the projected period.

- Installed capacity: in the estimate of the Group’s installed capacity, the existing facilities are taken into account, as well as the plans for both increasing and closing down capacity. The investment plan is constantly updated based on the evolution of the business, quality of service regulations determined by the regulator and changes in the business development strategy adopted by Management. The necessary investments are taken into account to maintain the installed capacity in appropriate operating conditions.

- Hydrology and NCRE: the projections are made from historical series of meteorological conditions and, based on them, an average year is projected.

- Fuel costs: to estimate fuel costs, existing supply contracts are taken into account and long-term projections of oil, gas or coal prices are made, based on forward markets and available analyst estimates.

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- Fixed costs: they are projected considering the foreseen level of business, both in terms of the evolution of the workforce (considering salary raises in line with the CPI), and in term of other operating and maintenance costs, the level of projected inflation and long-term existing maintenance or other contracts.  The efficiencies that the Group is adopting over time are also considered, such as those that arise from the initiatives of digitalization of internal processes.

- External sources are always considered to check against them hypotheses related to the macroeconomic environment such as price developments, GDP growth, demand, inflation, interest rates and exchange rates, among others.

Past experience has demonstrated the reliability of the Company's projections, which allows the key assumptions to be based on historical information. During 2019 the deviations observed with respect to the expectations established in the projections used to conduct the impairment tests as of December 31, 2018 have not been significant and the cash flows generated in 2019 were similar to those expected for that year, with the exception of the effect of the agreement signed in June 2019 between Enel Generación Chile and the Ministry of Energy for the progressive withdrawal of generating units running on coal (see Note 18.e.x) and the effect of Law 21,185, approved in October 2019, which establishes the mechanism for stabilizing electricity prices for customers subject to rate regulation (see Notes 4 and 11).

If the recoverable amount of the CGU is less than the net carrying amount of the asset, the corresponding impairment loss is recognized for the difference, and charged to “Reversal of impairment loss (impairment loss) recognized in profit or loss” in the consolidated statement of comprehensive income. The impairment is first allocated to the CGU’s goodwill carrying amount, if any, and then to the other assets comprising it, prorated on the basis of the carrying amount of each one, limited to its fair value less costs of disposal, or its value in use, a negative amount may not be obtained.

Impairment losses recognized in prior periods for an asset other than goodwill are reversed, if and only if, there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If this is the case, the carrying amount of the asset is increased to its recoverable amount and crediting profit or loss, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognized for the asset. In the case of goodwill, impairment losses are not reversed.

f)    Leases

In order to determine whether an arrangement is, or contains, a lease, the Group assesses the economic substance of the agreement, assessing whether the agreement transfers the right to control the use of an identified asset for a period of time in exchange for consideration.  Control is considered to exist if the customer has i) the right to obtain substantially all the economic benefits arising from the use of an identified asset; and ii) the right to direct the use of the asset.

When the Group acts as lessee, at the commencement of the lease (i.e. on the date on which the underlying asset is available for use) it records a right-of-use asset and a lease liability in the statement of financial position.

The Group initially recognizes right-of-use assets at cost. The cost of right-of-use assets comprises: (i) the amount of the initial measurement of the lease liability; (ii) lease payments made until the commencement date less lease incentives received; (iii) initial direct costs incurred; and (iv) the estimate of decommissioning or restoration costs.

Subsequently, the right-of-use asset is measured at cost, adjusted by any new measurement of the lease liability, less accumulated depreciation and accumulated impairment losses. A right-of-use asset is depreciated on the same terms as other similar depreciable assets if there is reasonable certainty that the lessee will acquire ownership of the asset at the end of the lease. If there is no such certainty, the asset is depreciated over the shorter of the asset’s useful life or the lease term.  The same criteria detailed in Note 3.e are applied to determine whether the right-of-use asset has become impaired.

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The lease liability is initially measured at the present value of the lease payments, discounted at the company's incremental borrowing rate, if the interest rate implicit in the lease cannot be readily determined. The IBR is the rate of interest that the Group would have to pay to borrow over a similar term, and with a similar security, the funds necessary to obtain an asset of a similar value to the right-of-use asset in a similar economic environment. The lease payments included in the measurement of the liability comprise: (i) fixed payments, less any lease incentive receivable; (ii) variable lease payments that depend on an index or rate; (iii) residual value guarantees; (iv) purchase option exercise price if it is reasonably certain the Group will exercise that option; and (v) lease termination penalties, if any.

After the start date, the lease liability increases to reflect the accrual of interest and is reduced by the lease payments made. In addition, the carrying amount of the liability is remeasured if there is a change in the terms of the lease (changes in the lease term, in the amount of expected payments related to a residual value guarantee, in the evaluation of a purchase option or in an index or rate used to determine lease payments). Interest expense is recognized as finance cost and distributed over the years making up the lease period, so that a constant interest rate is obtained in each year on the outstanding balance of the lease liability.

Short-term leases of one year or less or leases of low value assets are exempted from the application of the recognition criteria described above, recording the payments associated with the lease as expense on a straight-line basis over the term of the lease.

When the Group acts as lessor, it classifies at the inception of the agreement the lease as operating or finance, based on the substance of the transaction. Leases in which all the risks and rewards inherent to the ownership to the underlying asset are substantially transferred are classified as finance leases. All other leases are classified as operating leases.

In the case of finance leases, at the inception date, the company recognizes in its statement of financial position the assets held under finance leases and presents them as an account receivable, equal in value to the net investment in the lease, calculated as the sum of the present value of the lease payments and the present value of any accrued residual value, discounted at the interest rate implicit in the lease. Subsequently, finance income is recognized over the term of the lease, based on a model that reflects a constant rate of return on the net financial investment made in the lease.

In the case of operating leases, lease payments are recognized as income on a straight-line basis over the lease term, unless some other systematic basis of allocation is more representative. The initial direct costs incurred in obtaining an operating lease are added to the book value of the underlying asset and are recognized as expense throughout the lease period, applying the same basis as for rental income.

g)    Financial instruments

Financial instruments are contracts that give rise to both a financial asset in one entity and a financial liability or equity instrument in another entity.

g.1) Financial assets other than derivatives

The Group classifies its non-derivative financial assets, whether permanent or temporary, excluding investments accounted for using the equity method (see Notes 3.i and 15) and non-current assets and disposal groups held for sale or distribution to owners, into three categories (see Note 3.k):

· Amortized cost: This category includes the financial assets that meet the following conditions (i) the business model that supports it aims to maintain the financial assets to obtain the contractual cash flows, and (ii) the contractual terms of financial assets give rise on specific dates to cash flows that are solely payments of principal and interest (SPPI criterion).

Financial assets that meet the conditions established in IFRS 9, to be valued at amortized cost in the Group are: accounts receivable, loans and cash equivalents. These assets are recorded at amortized cost, which is the initial fair value, less repayments of principal, plus uncollected accrued interest, calculated using the effective interest rate method.

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The effective interest rate method is a method of calculating the amortized cost of a financial asset or a financial liability (or a group of financial assets or financial liabilities) and allocating the finance income or financial expenses throughout the relevant period. The effective interest rate is the discount rate that exactly matches the estimated cash flows to be received or paid over the expected useful life of the financial instrument (or when appropriate in a shorter period of time), with the net carrying amount of the financial asset or financial liability.

· Financial Assets Recorded at Fair Value through Other Comprehensive Income: This category includes the financial assets that the meet the following conditions: (i) they are classified in a business model, the purpose of which is to maintain the financial assets both to collect the contractual cash flows and to sell them, and (ii) the contractual conditions comply with the SPPI criterion.

These investments are recognized in the consolidated statement of financial position at fair value when it is possible to determine reliably. In the case of holdings in unlisted companies or companies with low liquidity, it is usually not possible to determine the fair value reliably. Therefore, when this circumstance occurs, such holdings are valued at their acquisition cost or for a lower amount if there is evidence of their impairment.

Changes in fair value, net of their tax effect, are recorded in the consolidated statement of comprehensive income: Other comprehensive income, until such time as the disposal of these financial assets takes place, at which time the accumulated amount in this section is fully posted in the result for the period with the exception of investments in equity instruments where the accumulated other comprehensive balance is reclassified to retained earnings.

In the event that the fair value is lower than the acquisition cost, if there is objective evidence that the asset has suffered an impairment that can not be considered as temporary, the difference is recorded directly in the losses for the period

· Financial Assets Recorded At Fair Value through Profit or Loss: This category includes the trading portfolio of the financial assets that have been allocated as such upon their initial recognition and which are administered and assessed according to the fair value criterion, and the financial assets that do not meet the conditions to be classified in the two above categories.

They are valued at fair value in the consolidated statement of financial position and any changes in value are recorded directly in profit or loss when they occur.

g.2) Cash and cash equivalents

This item within the consolidated statement of financial position includes cash and bank balances, time deposits, and other highly liquid investments (with original maturity of less than or equal to 90 days) that are readily convertible to cash and are subject to insignificant risk of changes in value.

g.3) Impairment of financial assets

Under IFRS 9, the Group applies an impairment model based on expected credit losses, based on the Group's past history, existing market conditions, and prospective estimates at the end of each reporting period. The new impairment model is applied to financial assets measured at amortized cost and those measured at fair value through other comprehensive income, except for investments in equity instruments.

The expected credit loss, determined considering Probability of Default (PD), Loss Given Default (LGD) and Exposure at Default (EAD), is the difference between all cash flows that are owed under the contract and all the cash flows that are expected to be received (that is, all cash deficiencies), discounted at the original effective interest rate.

To determine the expected credit losses the Group applies two separate approaches:

· General approach: applied to financial assets other than trade accounts receivable, contractual assets or lease receivables. This approach is based on the evaluation of significant increases in the credit risk of financial assets, from the date of initial recognition. If on the date of issuance of the financial statements the credit risk has not

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increased significantly, the impairment losses are measured by reference to the expected credit losses in the next 12 months; if, on the contrary, the credit risk has increased significantly, the impairment is measured considering the expected credit losses throughout the lifetime of the asset.

In general, the measurement of expected credit losses under the general approach is performed on an individual basis.

· Simplified approach: the Group applies a simplified approach for trade receivables, contract assets and lease receivables so that the impairment provision is always recognized in reference to the lifetime expected credit losses for the asset. This is the Group’s most applied approach since trade receivables represent the main financial asset of Enel Chile and its subsidiaries.

For trade accounts receivable, contractual assets and accounts receivable for lease, the Group applies two types of evaluations of expected credit losses:

- Collective evaluation: based on grouping accounts receivable into specific groups or “clusters”, taking into account each business and the local regulatory context. Accounts receivable are grouped according to the characteristics of client portfolios in terms of credit risk, maturity information and recovery rates. A specific definition of default is considered for each group.

- Analytical or individual evaluation: if accounts receivable are considered individually significant by Management, and there is specific information on any significant increase in credit risk, the Group applies an individual evaluation of accounts receivable. For the individual evaluation, the PD is obtained mainly from an external provider.

On the basis of the reference market and the regulatory context of the sector, as well as the recovery expectations after 90 days, for such accounts receivable, the Group mainly applies a default definition of 180 days of maturity to determine the expected credit losses, since this is considered an effective indicator of a significant increase in credit risk. Consequently, financial assets that are more than 90 days old are generally not considered in default.

To measure the expected credit losses collectively, the Group considers the following assumptions:

- PD: average default estimate, calculated for each group of trade accounts receivable, taking into account a minimum of 24-month historical data.

- LGD: calculated based on the recovery rates of a predetermined section, discounted at the effective interest rate; and

- EAD: accounting exposure on the date of report, net of cash deposits, including invoices issued, but not due and invoices to be issued.

Based on specific evaluations of Management, the prospective adjustment can be applied considering qualitative and quantitative information to reflect possible future events and macroeconomic scenarios, which may affect the risk of the portfolio or the financial instrument.

g.4) Financial liabilities other than derivatives

Financial liabilities, with general character, are recognized based on cash received, net of any costs incurred in the transaction. In subsequent periods, these obligations are measured at their amortized cost using the effective interest rate method (see Note 3.g.1).

Lease liabilities are initially measured at the present value of future lease payments, determined in accordance with the criteria described in Note 3.f.

In the particular case that a liability is the hedged item in a fair value hedge, as an exception, such liability is measured at its fair value for the portion of the hedged risk.

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In order to calculate the fair value of debt, both when it is recorded in the statement of financial position and for fair value disclosure purposes as shown in Note 23, debt has been divided into fixed interest rate debt (hereinafter “fixed-rate debt”) and variable interest rate debt (hereinafter “floating-rate debt”). Fixed-rate debt is that on which fixed-interest coupons established at the beginning of the transaction are paid explicitly or implicitly over its term. Floating-rate debt is that debt issued at a variable interest rate, i.e., each coupon is established at the beginning of each period based on the reference interest rate. All debt has been measured by discounting expected future cash flows with a market interest rate curve based on the payment currency.

g.5) Derivative financial instruments and hedge accounting

Derivatives held by the Group are transactions entered into to hedge interest and/or exchange rate risk, intended to eliminate or significantly reduce these risks in the underlying transactions being hedged.

Derivatives are recorded at fair value at the end of each reporting period as follows: if their fair value is positive, they are recorded within “Other financial assets”; and if their fair value is negative, they are recorded within “Other financial liabilities.” For derivatives on commodities, the positive fair value is recorded in “Trade and other receivables,” and negative fair values are recorded in “Trade and other liabilities”.

Changes in fair value are recognized directly in profit or loss, except when the derivative has been designated for  hedge accounting purposes as a hedge instrument (in a cash flow hedge) and all of the conditions for applying hedge accounting established by IFRS are met, including that the hedge be highly effective. In this case, changes are recognized as follows:

· Fair value hedges: The underlying portion for which the risk is being hedged (hedged risk) and the hedge instrument are measured at fair value, and any changes in value of both items are recognized in the consolidated statement of comprehensive income by offsetting the effects in the same comprehensive income statement account.

· Cash flow hedges: Changes in the fair value of the effective portion of the hedged item and hedge instrument are recognized in other comprehensive income and accumulated in an equity reserve known as “Reserve for cash flow hedges”. The cumulative loss or gain in this reserve is transferred to the consolidated statement of comprehensive income to the extent that the hedged item impacts the consolidated statement of comprehensive income offsetting the effect in the same comprehensive income statement account. Gains or losses from the ineffective portion of the hedge relationship are recognized directly in the statement of comprehensive income.

Hedge accounting is discontinued only when the hedging relationship (or a part of the relationship) fails to meet the required criteria, after making any rebalancing of the hedging relationship, if applicable. If it is not possible to continue the hedging relationship, including when the hedging instrument expires, is sold, settled or exercised, any gain or loss accumulated in equity at that date remains in  equity until the projected transaction affects the statement of comprehensive income. When a projected transaction is no longer expected to occur, the gain or loss accumulated in equity is immediately transferred to the income statement.

As a general rule, long-term commodity purchases or sales agreements are recognized in the consolidated statement of financial position at their fair value at the end of each reporting period, recognizing any differences in value directly in profit or loss, except for, when all of the following conditions are met:

· The sole purpose of the agreement is for its own use, which is understood as: (i) in the case of fuel purchase agreements such use is to generate electricity; (ii) in the case of electrical energy purchased for sale, its sale is to the end-customers; and (iii) in the case of electricity sales its sale is to the end-customers.

· The Group’s future projections evidence the existence of these agreements for own use.

· Past experience with agreements evidence that they are “own use” agreements, except in certain isolated cases when for exceptional reasons or reasons associated with logistical issues, they have been used for other purposes beyond the control and expectations of the Group.

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· The agreement does not stipulate net settlement and the parties have not made it a practice to net settle similar contracts in the past.

The long-term commodity purchase or sale agreements maintained by the Group, which are mainly for electricity, fuel, and other supplies, meet the conditions described above. Thus, the purpose of fuel purchase agreements is to use them to generate electricity, electricity purchase contracts are used to sell to end-customers, and electricity sale contracts are used to sell the Group’s own products.

The Group also evaluates the existence of derivatives embedded in contracts or financial instruments to determine if their characteristics and risk are closely related to the host contract, provided that when taken as a whole they are not being accounted for at fair value. If they are not closely related, they are recorded separately and changes in value are accounted for directly in the statement of comprehensive income.

g.6) Derecognition of financial assets and liabilities

Financial assets are derecognized when:

· The contractual rights to receive cash flows from the financial asset expire or have been transferred or, if the contractual rights are retained, the Group has assumed a contractual obligation to pay these cash flows to one or more recipients.

· The Group has substantially transferred all the risks and rewards of ownership of the financial asset, or, if it has neither transferred nor retained substantially all the risks and rewards, when it does not retain control of the financial asset.

Transactions in which the Group retains substantially all the inherent risks and rewards of ownership of the transferred asset, it continues recognizing the transferred asset in its entirety and recognizes a financial liability for the consideration received. Transactions costs are recognized in profit and loss by using the effective interest method (see Note 3.g.1).

Financial liabilities are derecognized when they are extinguished, that is, when the obligation arising from the liability has been paid or cancelled, or has expired. An exchange for a debt instrument with substantially different conditions, or a substantial modification in the current conditions of an existing financial liability (or a part thereof), is recorded as a cancellation of the original financial liability, and a new financial liability is recognized instead.

g.7) Offsetting financial assets and liabilities

The Group offsets financial assets and liabilities and the net amount is presented in the statement of financial position only when:

- there is a legally binding right to offset the recognized amounts; and

- the Company intends to settle them on a net basis, or to realize the asset and settle the liability simultaneously.

The right of offset may only be legally enforceable in the normal course of business, or in the event of default, or in the event of insolvency or bankruptcy, of one or all of the counterparties.

g.8) Financial guarantee contracts

The financial guarantee contracts, defined as the guarantees issued by the Group to third parties, are initially measured at their fair value, adjusted for transaction costs that are directly attributable to the issuance of the guarantee.

Subsequently to initial recognition, financial guarantee contracts are recognized at the higher of:

· the amount of the liability determined in accordance with the accounting policy in Note 3.m; and

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· the amount of the asset initially recognized less, if appropriate, any accumulate amortization recognized in accordance with the revenue recognition policies described in Note 3.q.

h)    Measurement of fair value

The fair value of an asset or liability is defined as the price that would be received from the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market, namely, the market with the greatest volume and level of activity for that asset or liability. In the absence of a principal market, it is assumed that the transaction is carried out in the most advantageous market available to the entity, namely, the market that maximizes the amount that would be received to sell the asset or minimizes the amount that would be paid to transfer the liability.

In estimating fair value, the Group uses valuation techniques that are appropriate for the circumstances and for which there is sufficient data to perform the measurement where it maximizes the use of relevant observable data and minimizes the use of unobservable data.

Given the hierarchy explained below, data used in the valuation techniques, assets and liabilities measured at fair value can be classified at the following levels:

· Level 1:  Quoted prices (unadjusted) in active markets for identical assets or liabilities;

· Level 2:  Inputs other than quoted prices included within Level 1 that are observable for the assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices). The methods and assumptions used to determine the fair values at Level 2 by type of financial assets or financial liabilities take into consideration estimated future cash flows discounted at market rates. Future cash flows for financial assets and financial liabilities are discounted with the zero coupon interest rate curves for each currency (these valuations are carried out using external tools such as Bloomberg); and

· Level 3:  Inputs for assets or liabilities that are not based on observable market data (unobservable inputs).

The Group takes into account the characteristics of the asset or liability when measuring fair value, in particular:

- For non-financial assets, fair value measurement takes into account the ability of a market participant to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset at its highest and best use;

- For liabilities and equity instruments, the fair value measurement assumes that the liability would not be settled and an equity instrument would not be cancelled or otherwise extinguished on the measurement date. The fair value of the liability reflects the effect of non-performance risk, namely, the risk that an entity will not fulfill the obligation, which includes but is not limited to, the Company’s own credit risk;

- For derivatives not traded on active markets, the fair value is determined by using the discounted cash flow method and generally accepted options valuation models, based on current and future market conditions as of the close of the financial statements. This methodology also adjusts the value based on the Company’s own credit risk (Debt Valuation Adjustment, DVA), and the counterparty risk (Credit Valuation Adjustment, CVA). These CVA and DVA adjustments are measured on the basis of the potential future exposure of the instrument (creditor or borrower position) and the risk profile of both the counterparties and the Group itself.

- For financial assets and financial liabilities with offsetting positions in market risks or counterparty credit risks, it is permitted to measure the fair value on a net basis. However, this must be consistent with the manner in which market participants would price the net risk exposure at the measurement date.

Financial assets and liabilities measured at fair value are shown in Note 23.3.

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i)    Investments accounted for using the equity method

The Group’s interests in joint ventures and associates are recognized using the equity method.

Under the equity method, an investment in an associate or joint venture is initially recognized at cost. As of the acquisition date, the investment is recognized in the statement of financial position based on the share of its equity that the Group’s interest represents in its capital, adjusted for, if appropriate, the effect of transactions with the Group plus any goodwill generated in acquiring the associate or joint venture. If the resulting amount is negative, zero is recorded for that investment in the statement of financial position, unless the Group has a present obligation (either legal or constructive) to support the investee’s negative equity situation, in which case a provision is recognized.

Goodwill from the associate or joint venture is included in the carrying amount of the investment. It is not amortized but is subject to impairment testing as part of the overall investment carrying amount when there are indicators of impairment.

Dividends received from these investments are deducted from the carrying amount of the investment, and any profit or loss obtained from them to which the Group is entitled based on its ownership interest is recognized under “Share of profit (loss) of associates accounted for using equity method.”

The companies classified as “Associates and Joint Ventures” (see Notes 2.5 and 2.6 respectively) in these consolidated financial statements are accounted for under this method.

j)      Inventories

Inventories are measured at their weighted average acquisition cost or the net realizable value, whichever is lower.

The net realizable value is the estimated selling price in the ordinary course of business less the estimated costs necessary to make the sale.

The cost of inventories includes all costs of purchase and all necessary costs incurred in bringing the inventories to their present location and condition. Trade discounts, rebates and other similar items are deducted in determining the costs of purchase.

k)    Non-current assets (or disposal group of assets) held for sale or held for distribution to owners and discontinued operations.

Non-current assets, including property, plant and equipment; intangible assets; investments accounted for using the equity method, joint ventures, and disposal groups (a group of assets to be disposed of and the liabilities directly associated with those assets), are classified as:

· Held for sale, if their carrying amount will be recovered principally through a sale transaction rather than through continuing use; or

· Held for distribution to owners, when the entity is committed to distribute the assets (or disposal groups) to the owners.

For the above classification, the assets must be available for immediate sale or distribution in their present condition and its sale or distribution is highly probable. For this transaction to be considered highly probable, management must be committed to the sale or distribution and actions to complete the transaction must have been initiated and should be expected to be completed within one year from the date of classification.

Actions required to complete the sale or distribution plan should indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. The probability of shareholders’ approval (if required in the jurisdiction) should be considered as part of the assessment of whether the sale or distribution is highly probable.

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Non-current assets or disposal groups held-for-sale or held for distribution to owners are measured at the lower of their carrying amount and fair value less costs to sell or costs to distribute, as appropriate.

Depreciation and amortization on these assets cease when they meet the criteria to be classified as non-current assets held for sale or held for distribution to owners.

Assets that are no longer classified as held for sale or held for distribution to owners, or are no longer part of a disposal group, are measured at the lower of their carrying amounts before being classified as held for sale or held for distribution less any depreciations, amortizations or revaluations that would have been recognized if they had not been classified as held for sale or held for distribution to owners and their recoverable amount at the date of subsequent decision where would be reclassified as non-current assets.

Non-current assets held for sale and the components of the disposal groups classified as held for sale or held for distribution to owners are presented in the consolidated statement of financial position as a single line item within assets called “Non-current assets or disposal groups held for sale or for distribution to owners,” and the respective liabilities are presented as a single line item within liabilities called “Liabilities included in disposal groups held for sale or for distribution to owners.”

The Group classifies as discontinued operations those components of the Group that either have been disposed of, or are classified as held for sale, and:

(i) represents a separate major lines of business or geographical area of operations;

(ii) is a part of a single coordinated plan to dispose a separate major line of business or geographical area of operations; or

(iii) is a subsidiary acquired exclusively with a view to resale.

The components of profit or loss after taxes from discontinued operations and the post-tax gain or loss recognized on the measurement to fair value less costs to sell or on the disposal of the assets or groups constituting the discontinued operation are presented as a single line item in the consolidated comprehensive income statement as “Income after tax from discontinued operations”.

l)      Treasury shares

Treasury shares are deducted from equity in the consolidated statement of financial position and measured at acquisition cost.

Gains and losses from the disposal of treasury shares are recognized directly in “Equity – Retained earnings”, without affecting profit or loss for the period.

m)      Provisions

Provisions are recognized when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of economic benefits will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation.

The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (when the effect of the time value of money is material). The unwinding of the discount is recognized as finance cost. Incremental legal cost expected to be incurred in resolving a legal claim is included in measuring of the provision.

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Provisions are reviewed at the end of each reporting period and adjusted to reflect the current best estimate. If it is no longer probable that an outflow of resources embodying economic benefits will be required to settle the obligation, the provision is reversed.

A contingent liability does not result in the recognition of a provision. Legal costs expected to be incurred in defending a legal claim are expensed as they are incurred. Significant contingent liabilities are disclosed unless the likelihood of an outflow of resources embodying economic benefits is remote.

m.1) Provisions for post-employment benefits and similar obligations

Some of the Group’s subsidiaries have pension and similar obligations to their employees. Such obligations, related to defined benefits plans, are basically formalized through pension plans, except for certain non-monetary benefits, mainly electricity supply commitments, which, due to their nature, have not been externalized and are covered by the related in-house provisions.

For defined benefit plans, the cost of providing benefits is determined using the Projected Unit Credit Method, with actuarial valuations being carried out at the end of each reporting period. Past service costs relating to changes in benefits are recognized immediately.

The defined benefit plan obligations in the statement of financial position represent the present value of the accrued obligations, adjusted, once the fair value of the different plans’ assets has been deducted, if any.

Actuarial gains and losses arising in measurements of both the plan liabilities and the plan assets (if any, and excluding interest) are recognized directly in other comprehensive income.

n)    Translation of foreign currency balances

Transactions carried out by each entity in a currency other than its functional currency are recognized using the exchange rates prevailing as of the date of the transactions. During the year, any differences that arise between the prevailing exchange rate at the date of the transaction and the exchange rate as of the date of collection or payment are recognized as “Foreign currency exchange differences” in the consolidated statement of comprehensive income.

Likewise, at the end of each reporting period, receivable or payable balances denominated in a currency other than each entity’s functional currency are translated using the closing exchange rate. Any differences are recorded as “Foreign currency exchange differences” in the consolidated statement of comprehensive income.

The Group has established a policy to hedge the portion of revenue from its consolidated entities that is directly linked to variations in the U.S. dollar, through obtaining financing in such currency. Exchange differences related to this debt, which is regarded as the hedging instrument in cash flow hedge transactions, are recognized, net of taxes, in other comprehensive income and are accumulated in an equity reserve and reclassified to profit or loss when the hedged cash flows affect profit or loss. This term has been estimated at ten years.

o)    Current/non-current classification

In these consolidated statements of financial position, assets and liabilities expected to be recovered or settled within twelve months are presented as current items, except for post-employment and other similar obligations. Those assets and liabilities expected to be recovered or settled in more than twelve months are presented as non-current items. Deferred income tax assets and liabilities are classified as non-current.

When the Group has any obligations that mature in less than twelve months but can be refinanced over the long term at the Group’s discretion, through unconditionally available credit agreements with long-term maturities, such obligations are classified as non-current liabilities.

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p)    Income taxes

Income tax expense for the period is determined as the sum of current taxes from each of the Group’s subsidiaries and results from applying the tax rate to the taxable income for the period, after permitted deductions have been made, plus any changes in deferred tax assets and liabilities and tax credits, both for tax losses and deductions. Differences between the carrying amount and tax basis of assets and liabilities generate deferred tax assets and liabilities, which are calculated using the tax rates expected to apply when the assets and liabilities are realized or settled, based on tax rates that have been enacted or substantively enacted by the end of the reporting period.

Deferred tax assets are recognized for all deductible temporary differences, tax losses and unused tax credits to the extent that it is probable that sufficient future taxable profits exist to recover the deductible temporary differences and make use of the tax credits. Such deferred tax asset is not recognized if the deductible temporary difference arises from the initial recognition of an asset or liability that:

· Did not arise from a business combination, and

· At initial recognition affected neither accounting profit nor taxable profit (loss).

With respect to deductible temporary differences associated with investments in subsidiaries, associates and joint arrangements, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profits will be available against which the temporary differences can be utilized.

Deferred tax liabilities are recognized for all temporary differences, except those derived from the initial recognition of goodwill and those that arose from investments in subsidiaries, associates and joint ventures in which the Group can control their reversal and where it is probable that they will not reverse in the foreseeable future.

Current tax and changes in deferred tax assets or liabilities are recorded in profit or loss or in equity, depending on where the gains or losses that triggered these tax entries have been recognized.

Any tax deductions that can be applied to current tax liabilities are credited to earnings within the line item “Income tax expenses”, except when exists uncertainty about their tax realization, in which case they are not recognized until they are effectively realized, or when they correspond to specific tax incentives, in which case they are recorded as government grants.

At the end of each reporting period, the Group reviews the deferred taxes assets and liabilities recognized, and makes, if any, necessary corrections based on the results of this analysis.

Deferred tax assets and deferred tax liabilities are offset in the consolidated statement of financial position if has a legally enforceable right to set off current tax assets against current tax liabilities, and only when the deferred taxes relate to income taxes levied by the same taxation authority.

q)    Revenue and expense recognition

Revenue is recognized when (or as) the control over a good or service is transferred to the customer. Revenue is measured based on the consideration to which it is expected to be entitled for said transfer of control, excluding the amounts collected on behalf of third parties.

The Group analyzes and takes into consideration all the relevant facts and circumstances for revenue recognition, applying the five step of the model established by IFRS 15: 1) Identifying the contract with a customer; 2) Identifying the performance obligations; 3) Determining the transaction price; 4) Allocating the transaction price; and 5) Recognizing revenue.

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The following are the criteria for revenue recognition by type of good or service provided by the Group:

· Electricity supply (sale and transportation): Corresponds to a single performance obligation that transfers to the customer a number of different goods/services that are substantially the same and that have the same transfer pattern. Since the customer receives and simultaneously consumes the benefits provided by the Company, it is considered a performance obligation met over time. In these cases, Enel Chile applies an output method to recognize revenue in the amount to which it is entitled to bill for electricity supplied to date.

· Generation: revenue is recorded according to the physical deliveries of energy and power, at the prices established in the respective contracts, at the prices stipulated in the electricity market by the current regulations, or at the marginal cost of energy and power, depending on whether they are unregulated, regulated customers or energy trading in the spot market are involved, respectively.

· Distribution of electricity: Revenue is recognized based on the amount of energy supplied to customers during the period, at prices established in the respective contracts or at prices stipulated in the electricity market by applicable regulations, as appropriate.

This revenue includes an estimate of the service provided and not invoiced at the balance sheet date (ee Notes 2.3 and 28 and Appendix 2.2).

· Sale and Transportation of Gas: Revenue is recognized over time, based on the actual physical deliveries of gas in the period of consumption, at the prices established in the respective contracts.

· Other services: mainly the provision of supplementary services to the electricity business, construction of works and engineering and consulting services. Customers control committed assets as they are created or improved. Therefore, the Company recognizes this revenue over time based on the progress, measuring progress through output methods (performance completed to date, milestones reached, etc.), or resource methods (resources consumed, hours of labor spent, etc.), as appropriate in each case.

· Sale of goods: revenue from the sale of goods is recognized at a certain time, when control of the goods have been transferred to the customer, which generally occurs at the time of the physical delivery of the goods. Revenues are measured at the independent sale price of each good, and any type of applicable variable compensation.

In contracts in which multiple committed goods and services are identified, the recognition criteria will be applied to each of the identifiable performance obligation of the transaction, based on the control transfer pattern of each good or service that is separate and an independent selling price allocated to each of them, or to two or more transactions jointly, when these are linked to contracts with customers that are negotiated with a single commercial purpose and the goods and services committed represent a single performance obligation and their selling prices are not independent.

Enel Chile determines the existence of significant financing components in its contracts, adjusting the value of the consideration if applicable, to reflect the effects of the time value of money. However, the Group applies the practical solution provided by IFRS 15, and will not adjust the value of the consideration committed for the purpose of a significant financing component, if the Company expects, at the beginning of the contract, that the period between the payment and the transfer of goods or service to the customer is one year or less.

The Group excludes the gross revenue of economic benefits received when acting as an agent or broker on behalf of third parties from the revenue figure. The Group only records as revenue the payment or commission to which it expects to be entitled.

Given that the Company mainly recognizes revenue for the amount to which it has the right to invoice, it has decided to apply the practical disclosure solution provided in IFRS 15, through which it is not required to disclose the aggregate

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amount of the transaction price allocated to the obligations of performance not met (or partially not met) at the end of the reporting period.

In addition, the Group evaluates the existence of incremental costs of obtaining a contract and costs directly related to the fulfillment of a contract. These costs are recognized as an asset, if their recovery is expected, and amortized in a manner consistent with the transfer of the related goods or services. As a practical solution, the incremental costs of obtaining a contract can be recognized as an expense, if the depreciation period of the asset that has been recognized is one year or less. Costs that do not qualify for capitalization are recognized as expenses at the time they are incurred, unless they are explicitly attributable to the customer.

As of December 31, 2019 and 2018, the Group has not incurred costs to obtain or fulfill a contract which meet the conditions for such capitalization. The costs incurred to gain a contract are substantially commission payments for sales that, although they are incremental costs, are related to short-term contracts or performance obligations that are met at a certain point; therefore, the Group has decided to recognize these costs as an expense when they occur.

Interest revenue (expenses) is (are) recorded considering the effective interest rate applicable to the principal with pending amortization, during the corresponding accrual period.

r)    Earnings per share

Basic earnings per share are calculated by dividing net income attributable to shareholders of the Parent Company by the weighted average number of ordinary shares outstanding during the period, excluding the average number of shares of the Parent Company held by other subsidiaries within the Group, if any.

Basic earnings per share for continuing and discontinued operations are calculated by dividing net income from continuing and discontinued operations attributable to shareholders of the Parent Company (the numerator) by the weighted average number of ordinary shares outstanding (the denominator) during the year, excluding the average number of shares of the Parent Company held by other subsidiaries within the Group, if any.

Diluted EPS is calculated by dividing net income to shareholders of the Parent Company by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares, if any.

s)    Dividends

Article No. 79 of the Chilean Corporations Act Law No. 18,046; establishes that, unless unanimously agreed otherwise by the shareholders of all issued shares, listed corporations must distribute a cash dividend to shareholders on an annual basis, pro rata to the shares owned or the proportion established in the company’s by-laws if there are preferred shares, of at least 30% of net income for each period, except when accumulated losses from prior years must be absorbed.

As it is practically impossible to achieve a unanimous agreement given the Company’s highly fragmented share capital, at the end of each reporting period the amount of the minimum statutory dividend obligation to its shareholders is determined, net of interim dividends approved during the fiscal year, and then accounted for in “Trade and other current payables” and “Accounts payable to related companies”, as appropriate, and recognized in equity.

Interim and final dividends are deducted from equity as soon as they are approved by the competent body, which in the first case is normally the Company’s Board of Directors and in the second case is the shareholders as agreed at an Ordinary Shareholders’ Meeting.

t)Share issuance costs

Share issuance costs, only when they represent incremental expenses directly attributable to the transaction, are recognized directly in net equity as a deduction from “Share premiums,” net of any applicable taxes.

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If the share premium account has a zero balance or if the share issuance and brokerage expenses exceed the balance, they are recognized in “Other reserves". Subsequently, these costs must be deducted from the paid-in capital, and this deduction that must be approved at the Extraordinary Shareholders Meeting that takes place immediately after the date on which the costs were incurred.

u)    Statement of cash flows

The statement of cash flows reflects changes in cash and cash equivalents that took place during the period, determined with the direct method. It uses the following expressions and corresponding meanings:

· Cash flows: inflows and outflows of cash or cash equivalents, which are defined as highly liquid investments maturing in less than three months with a low risk of changes in value.

· Operating activities: the principal revenue-producing activities of the Group and other activities that cannot be considered investing or financing activities.

· Investing activities: the acquisition and disposal of long-term assets and other investments not included in cash and cash equivalents.

· Financing activities: activities that result in changes in the size and composition of the total equity and borrowings of the Group.

4.    SECTOR REGULATION AND ELECTRICITY SYSTEM OPERATIONS.

a)  Regulatory framework:

The electricity sector is regulated by the General Law of Electrical Services No. 20,018 (Chilean Electricity Law), also known as DFL No. 1 of 1982, of the Ministry of Mining, whose compiled and coordinated text was established in DFL No. 4 issued in 2006 by the Ministry of Economy (the Electricity Law), as well as by an associated Regulation (D.S. No. 327 issued in 1998).

Three government bodies are primarily responsible for enforcing this law: the National Energy Commission (CNE in its Spanish acronym), which has the authority to propose regulated tariffs (node prices) and to draw up indicative plans for the construction of new generating units; the Superintendency of Electricity and Fuels (SEF), which supervises and oversees compliance with the laws, regulations, and technical standards that govern the generation, transmission, and distribution of electricity, as well as liquid fuels, and gas; and the Ministry of Energy, which is responsible for proposing and guiding public policies on energy matters. It also oversees the SEF, the CNE, and the Chilean Commission for Nuclear Energy (CChEN in its Spanish acronym), thus strengthening coordination and allowing for an integrated view of the energy sector. The Ministry of Energy also includes the Agency for Energy Efficiency and the National Center for Innovation and Development of Sustainable Energy (Centro Nacional para la Innovación y Fomento de las Energías Sustentables, or CIFES). The Chilean Electricity Law has also established a Panel of Experts whose main task is to resolve potential discrepancies among the participants in the electricity market, including electricity companies, system operators, regulators, etc.

From a physical point of view, the Chilean power sector is divided into three electrical grids: the Sistema Electrico Nacional (SEN) and two separate medium-size grids in southern Chile, one in Aysén and the other in Magallanes. The SEN was incorporated in November 2017 through the interconnection of the Sistema Interconectado Central (SIC) and the Sistema Interconectado del Norte Grande (SING). Prior to the interconnection, the SIC was the main electrical grid, running 2,400 km. longitudinally and connecting the country from Taltal in the north, to Quellón on the island of Chiloé in the south. The SING covered the northern part of the country, from Arica down to Coloso, covering a length of about 700 km.

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The electricity industry is organized into three business activities: generation, transmission, and distribution, all operating in an interconnected and coordinated manner, and whose main purpose is to supply electrical energy to the market at minimum cost while maintaining the quality and safety service standards required by the electrical regulations. As essential services, the power transmission and distribution businesses are natural monopolies; these segments are regulated as such by the Chilean Electricity Law, which requires free access to networks and regulates tariffs.

Under the Chilean Electricity Law, the electricity market coordinates their operations through a centralizing operating agent, the Coordinador Eléctrico Nacional (CEN), in order to operate the system at minimum cost while maintaining reliable service, and the SEN. The CEN plans and operates the systems, including the calculation of the so-called “marginal cost,” which is the price assigned to energy transfers among power generating companies.

Consumers are classified according to the size of their demand as regulated or unregulated clients. Regulated customers are those customers who have a connected capacity of less than 5,000 kW. Without prejudice to this, customers with power connected between 500 kW and 5,000 kW may opt for an unregulated or regulated rate regime.

Limits on integration and concentration

Chile has legislation in effect that defends free competition and, together with specific regulations that apply to the electricity market, defines criteria to avoid certain levels of economic concentration and/or abusive market practices. In principle, the regulator allows the participation of companies in different activities (e.g. generation, distribution, and commercialization) as long as there is an adequate separation of each activity, for both accounting and corporate purposes. Nevertheless, most of the restrictions imposed involve the transmission sector mainly due to its nature and the need to guarantee adequate access to all agents.

The Chilean Electricity Law establishes limits for participation of generation or distribution companies in the Trunk Transmission Systems, and prohibits participation of Trunk Transmission Systems’ companies in the generation and distribution segment.

a.1  Generation Segment

Generation companies must comply with the operation plan of the CEN. However, each generation company is free to decide whether to sell its energy to regulated or unregulated customers. Any surplus or deficit between a company’s sales to its customers and its energy supply is sold to, or purchased from, other generators at the spot market price.

A generation company may have the following types of customers:

(i) Unregulated customers: Those customers, mainly industrial and mining companies, with a connected capacity higher than 5,000 kW. These customers can freely negotiate prices for electrical supply with generators and/or distributors. Those customers with connected capacity between 500 and 5,000 kW have the option to contract energy at prices agreed upon with their suppliers or be subject to regulated prices, with a minimum term of at least four years under each pricing system.

(ii) Distribution companies that supply power to regulated customers: Participation in public tenders regulated by the CNE for the supply to their unregulated customers through bilateral contracts.

(iii) Other Generating Companies: The relationship between generating companies could occur through bilateral contracts or through Spot Market or short-term transfers. The latter correspond to energy and power transactions between generating companies that result from the coordination performed by the CEN to achieve the economic operation of the system; the excesses (deficits) of its production in relation to its commercial commitments are transferred through sales (purchases) to the other part of the system generators, valuing the energy at marginal cost and the power at the corresponding node price fixed every six months by the authority.

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In Chile, the capacity that must be paid to each generator depends on an annual calculation performed by the CEN to determine the sufficiency capacity of each power plant, which is not the same as the dispatched capacity.

Non-Conventional Renewable Energy

Law No. 20,257 was enacted in April of 2008 to encourage the use of Non-Conventional Renewable Energy (NCRE). The principal aspect of this law is that at least 5% of the energy sold by generation companies to their customers must come from renewable sources between years 2010 and 2014. This requirement progressively increases by 0.5% from 2015 until 2024, when a 10% renewable energy requirement will be reached. This law was amended in 2013 by Law No. 20,698, referred to as the “20/25 law,” as it establishes that by 2025, 20% of energy supplied must be generated by NCRE. It does not change the previous law’s plan for supplying energy under agreements in effect at July 2013.

a.2 Transmission Segment

The transmission segment is comprised of a combination of lines, substations and equipment for the transmission of electricity from the production points (generators) to the centers of consumption or distribution, which do not correspond to distribution facilities. The transmission segment is divided into National Transmission System, Development Poles Transmission System, Zonal Transmission System and Dedicated Transmission System. The International Interconnection Systems, which are governed by special rules, are also part of the transmission segment.

The transmission system is open access, and transmission companies may impose rights of way over the available transmission capacity under non-discriminatory conditions. The fees of the existing facilities of the National and Zonal Transmission Systems is determined through a tariff setting process that is carried out every four years. In that process, the Annual Value of the Transmission is determined, which comprises efficient operation and maintenance costs and the annuity of the investment value, determined on the basis of a discount rate fixed by the authority on a quarterly basis (minimum 7% after tax) and the economic useful life of the facilities.

The planning of the National and Zonal Transmission Systems a regulated and centralized process, in which the CEN annually issues an expansion plan report, which is published by the CEN to receive proposals from companies. The expansion plan report can receive comments from participants and must be approved ultimately by the CEN.  The expansions of both systems are carried out through open tenders, distinguishing between new projects (with tenders open to any bidder) and expansion of existing facilities projects (participation in the expansion corresponds to owners of the original facilities under modification). Both types of tenders are managed by the CEN. The bids correspond to the value resulting from the tender, which constitutes the revenues for the first 20 years from the start of operations. As of year 21, the fees of such transmission facilities are determined as if they were existing facilities.

The current regulations define that the transmission is remunerated by the sum of the tariff revenues and the collection of charges for the use of the transmission system. This charge is defined (Ch$ / kWh) by the CNE, on a half-yearly basis.

a.3 Distribution segment

The distribution segment is defined for regulatory purposes as all electricity supplied to end customers at a voltage no higher than 23 kV. Distribution companies operate under a distribution public utility concession regime, with service obligations and regulated tariffs for supplying regulated customers.

Customers are classified based on their demand as regulated and unregulated. Regulated customers are those with connected capacity of more than 5,000 kW. Customers with connected capacity between 500 kW and 5,000 kW can choose either a regulated or an unregulated regime.

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Distribution companies can supply both regulated customers, under supply conditions regulated by the Chilean Electricity Law, and unregulated customers, whose supply conditions are freely negotiated and agreed in bilateral contracts with energy suppliers (generation or distribution companies).

Regarding price regulation, the Chilean Electricity Law establishes that distribution companies must permanently have available energy supply, on the basis of open, non-discriminatory and transparent public tenders. These bidding processes are managed by the CNE and are carried out at least five years in advance. The result of the process is a “pay as bid” contract, with an extension up to 20 years. In case of unforeseen deviations in the projections of demand, the regulator has the authority to carry out short-term tenders. In addition, a reimbursement mechanism exists allowing supply without contract and regulating corresponding tariffs.

Tariffs in this segment are set every four years, based on a cost study to determine the Value Added of Distribution (VAD). The determination of the VAD is based on an efficient model business scheme and the typical area concept.

To determine the VAD, the CNE classifies companies with similar distribution costs into groups called “typical areas”. For each typical area, the CNE orders a study from independent consultants, in order to determine the costs associated with a model efficient company, considering overhead, average energy and power losses and standard investment, maintenance and operation costs associated with distribution, and including some restrictions faced by actual distribution companies. Annual investment costs are calculated considering the New Replacement Value (VNR) of the facilities adapted to the demand, their useful life and an update rate, calculated every four years by the CNE.

On December 21, 2019, the Ministry of Energy published Law No. 21,194 (Short Law) that reduces the profitability of distribution companies, wich cannot be less than 6% or greater than 8% a year after tax, and improves the electricity distribution tariff process. As a result, the process for determining distribution tariffs in the 4-year period 2020-2024 incorporates the provisions of this Short Law.

Subsequently, tariffs are structured and the economic after tax rate of return is validated, and that rate cannot differ by more than two points upwards and three points downwards from the rate defined by the CNE.

Additionally, every four years a review of services associated with the calculation of VAD is carried out, which do not represent energy supply and which the Free Competition Court qualifies as subject to tariff regulation.

The Chilean distribution tariff model is a consolidated model, which already had eight cycles of tariff settings since the enactment of the General Electric Services Law in 1982.

b)  Regulatory Developments in 2019

Laws Published in 2019

Law No. 21,185, of the Ministry of Energy, published on November 2, 2019 sets up a Transitional Mechanism for the Stabilization of Electric Power Prices for Customers subject to Tariff Regulation. Through this Law, between July 1, 2019 and December 31, 2020, the prices to be charged to regulated customers are kept at the same price levels defined for the first half of 2019 (Decree 20T / 2018) and will be called “ Stabilized Price to Regulated Client ”(PEC). Between January 1, 2021 and until the end of the stabilization mechanism, the prices will be those established semi-annually in accordance with article 158 of the Electricity Law, but may not exceed the PEC adjusted for the Consumer Price Index as of January 1, 2021 based on the same date (adjusted PEC). The differences that occur between the billing applying the stabilization mechanism and the theoretical billing considering the price that would have been applied in accordance with the conditions of the respective contracts with the electricity distribution companies, will generate an account receivable in favor of the electricity generation companies with a limit of US 1.35 billion until 2023. All billing differences will be denominated in US dollars and will not accrue interest until December 31, 2025The balance must be recovered no later than December 31, 2027.

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Law No. 21,194, of the Ministry of Energy, published on December 21, 2019, effective as of that same date reduces the profitability of distribution companies and improves the electricity distribution’s tariff process. Through this Law, the proportion of consideration  of two thirds for the VAD study carried out by the CNE and one third for the VAD study carried out by the distribution companies is eliminated, and is replaced with a single study requested by the CNE. On the other hand, the rate for updating the calculation of annual investment costs is changed from the actual annual 10% to a rate calculated by the CNE every four years, which cannot be less than 6% or greater than 8% a year after tax. The distribution companies’ after-tax rate of return may not differ by more than two points upwards and three points downwards from the rate defined by the CNE. Additionally, as of January 2021, distribution companies must have a single line of business.

CNE 2019 Regulatory Plan

Under the Exempt Resolution No. 790 dated December 10, 2018, in accordance with the provisions of Article 72-19 of the General Electric Services Law, the CNE published its Annual Work Plan for the preparation of the technical regulations for 2019. The document defines the general guidelines and the program priorities of the CNE’s Regulatory Work Plan 2019 and the pending regulatory procedures of the 2018 Work Plan, the preparation of which continued being performed during 2019.

Regulations Published in 2019

Regulation of Supplementary Services. On March 27, 2019, the Ministry of Energy approved Decree No. 113/2017 which is the Supplementary Services Regulation referred to in article No. 72-7 of the General Law of Electric Services, . This Decree's effective date is January 1, 2020.

2017 Transmission Expansion Plan

In accordance with the stages of the process established in the law, on November 8, 2018, the Chilean Ministry of Energy published Exempt Decree No. 293/2018 establishing the Expansion Works of the National and Zonal Transmission Systems that must start their tender process in the next twelve months. Subsequently, on August 13, 2019, it published Exempt Decree No. 202/2019 which revises the prior Decree regarding the Extension Works.

On January 9, 2019, the Ministry of Energy published Exempt Decree No. 4/2019 establishing the New Works of the National and Zonal Transmission Systems who must start their tender process in the next twelve months.

2018 Transmission Expansion Plan

According to the stages of the Transmission Expansion Plan, the CNE issued the Final Technical Report through Exempt Resolution No. 14 on January 11, 2019. Subsequently, the persons concerned filed their discrepancies before a Panel of Experts in a public hearing. In this regard, the CNE issued the Final Technical Report by means of Exempt Resolution No. 334 dated May 29, 2019.

In accordance with the stages of the process established in the law, on September 24, 2019, the Ministry of Energy published Exempt Decree No. 231/2019 establishing the New Works of the National and Zonal Transmission Systems who must start their tender process or study of the allocated capacity in the next twelve months.

On August 10, 2019, it published Exempt Decree No. 198/2019 establishing the Expansion Works of the National and Zonal Transmission Systems who must start their tender process in the next twelve months. Such relates to the expansion plan of 2018.

2019 Transmission Expansion Plan

According to article 91 of Law 20,936/2016, which establishes the Transmission Planning Procedure, the CNE has the obligation to send to the CNE, the proposal to expand the different segments of the transmission system. On January 22, 2019 the document with the proposal was generated.

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The CNE summoned all interested parties to submit proposals for Transmission Expansion projects until April 22, 2019, in accordance with the provisions of article 91 of the Law.

On December 23, 2019, the CNE issued an Exempt Resolution No. 801 Updating the Citizen Participation Registry of the corresponding Annual Transmission Planning Process, in accordance with the provisions of article 90 of the General Law of Electrical Services and establishes a consolidated list of participants and interested users and institutions.

c. Tariff Revisions:

c.1  Distribution Tariff Setting

The process of setting tariffs for the four-year period 2016-2020 ended on August 24, 2017 with the publication of the Decree No. 11T/2016 in the Official Gazette. This decree established tariff formulas at the distribution level, and was effective as of November 4, 2016.

On June 27, 2018, the Ministry of Energy published  the Decree No. 2T/2018, which sets the power adjustment factor of the tariff formulas applicable to supplies, subject to regulated prices which applies for the four years  November 2016 - November 2020.

Decree No. 5T of the Ministry of Energy became effective on September 28, 2018. This decree updated Decree No. 11T of 2016 of the Ministry of Energy. Therefore, it updated tariffs for the electricity distribution segment in effect until the next tariff setting.

On July 26, 2019, through Resolution No. 15699/2019, SEF implemented  an action plan to make effective the adjustment indicated in Resolution No. 490/2019 of CNE, with  respect to Decree No. 5T/2018 of the Ministry of Energy. The validity of the adjustment was retroactive from September 28, 2018.

The tariffs applied in 2019 to end customers were determined based on the following decrees and resolutions:

i. Decree No. 11T/2016 published in the Official Gazette on August 24, 2017, set the tariff indexation formulas applicable to energy supplies subject to regulated prices. Tariffs were retroactively applied from November 4, 2016.

ii. Decree No. 2T/2018, which sets the power adjustment factor of the tariff formulas applicable to supplies subject to regulated prices, published in the Official Gazette on June 27, 2018 and which applies for the four years between November 2016 to November 2020.

iii. Decree No. 5T/2018, which sets tariff formulas applicable to electricity supplies subject to regulated prices listed in Decree No. 11T dated 2016 of the Ministry of Energy, published in the Official Gazette on September 28, 2018 and which is effective from its publication date.

iv. SEF Resolution No15699/2019, which implements an  adjustment action plan indicated in the CNE Resolution No 490/2019, issued by CNE, regarding Decree No. 5T/ 2018 of the Ministry of Energy, with retroactive effect from September 28, 2018 and which is effective until November 3, 2020.

v. Decree No. 6T/2017, which fixes Annual Value per Tranche of the Zonal and Dedicated Transmission Facilities used by users subject to price regulation, their tariffs and indexing formulas for the two-year period 2018-2019, published by the Ministry of Energy in the Official Gazzete on October 5, 2018, which has effect from January 1, 2018 to December 31, 2019.

vi. Tariff Decrees

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Average node prices:

On September 28, 2018, the Ministry of Energy published Decree No. 7T/2018 in the Official Gazette, which sets the regulated prices for electricity supplies and sets adjustments and surcharges for the application of the Residential Tariff Equality Mechanism, with retroactive effect from July 1, 2018.

On May 6, 2019, the Ministry of Energy published Decree No. 20T/2018 in the Official Gazette, which sets the regulated prices for electricity supplies and sets adjustments and surcharges for the application of the Residential Tariff Equality Mechanism, with retroactive effect from January 1, 2019.

On October 5, 2019, the Ministry of Energy published Decree No.7T/2019 in the Official Gazette, which sets the regulated  prices for electricity supplies and sets adjustments and surcharges for the application of the Residential Tariff Equality Mechanism, with retroactive effect from July 1, 2019.

On November 2, 2019, the Ministry of Energy published Law No. 21,185 that creates a transitional mechanism for the stabilization of electric energy prices for customers subject to tariff regularization. Article 5 of this Law repeals Decree No. 7T/ 2019, and extends the validity of Decree No. 20T/2018 from its original validity until the publication of the decree of average regulated node price that corresponds after the entry into force of the law.

Short-term node prices:

The Ministry of Energy published Decree No. 1T/2018 on June 28, 2018, which fixed node prices for electricity supplies, with retroactive effect from April 1, 2018

On February 8, 2019, the Ministry of Energy published Decree No. 12T/2018, which sets the regulated prices for electricity supplies, with retroactive effect from October 1, 2018.

On June 5, 2019, the Ministry of Energy published Decree No. 1T/2019, which sets the regulated prices for electricity supplies, with retroactive effect from April 1, 2019.

On October 23, 2019, the Ministry of Energy published the Decree No. 9T/2019, which sets the regulated prices for electricity supplies, with retroactive effect from October 1, 2019.

c.2 Setting of Service Tariffs Associated with Distribution

The Ministry of Energy published Decree No. 13T/2018 in the Official Gazette on July 24, 2018. This decree established tariffs for Non-Consistent Services in Energy Supplies associated with electricity distribution. These tariffs have been in force since the publication of the decree and they are in effect to date.

c.3 Subtransmission Tariff Setting

The Ministry of Energy published Decree No. 6T/2017 on October 5, 2018. This decree set annual value per tranche of the Zonal and Dedicated transmission facilities used by users subject to price regulation, their tariffs and indexation formulas for the two-year period 2018-2019.

c.4 Transmission Tariff Setting 2020‑2023

In the framework of the process of Transmission Tariff Setting 2020-2023, the processes of Qualification of Facilities of the Transmission Systems, Setting of Useful Life of the Transmission Facilities and definition of the Technical and Administrative Bases for the Study of Valuation of Transmission Facilities are in progress.

In this context, for the purposes of the Qualification Process of Transmission System Facilities for the period 2020-2023, the CNE, issued the preliminary technical report defining which transmission facilities correspond to

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each segment (National, Zonal and Dedicated) dated April 9, 2019.   In compliance with the stages established by the regulations, the CNE through Exempt Resolution No. 244 issued the Final Technical Report..

Also, for the purposes of the process of Setting of Useful Life of the Transmission Facilities,on June 5, 2018, the CNE approved the Final Technical Report that determines Useful Lives, by means of Exempt Resolution No. 412.

Finally, for the purposes of the definition of the Technical and Administrative basis for the Study of Valuation of Transmission Facilities, the CNE published the Technical and Administrative Preliminary for the end of 2017, which in general terms, this document regulates the contracting process of the tariff study and defines the rules for carrying out the tariff study of the entire transmission system, defining the tender of two studies: one for National facilities and another for Zonal and Dedicated facilities

On April 26, 2019, and in compliance with the stages contemplated by the Law, the CNE through Exempt Resolution No.272, approved the Definitive Technical and Administrative Bases for conducting the Valuation Studies of the Transmission Systems. On December 11, 2019, the CNE issued Exempt Resolution No. 766 that rectifies the previous resolution.

Following the stages of the process established by the Law, the CNE established a committee for the adjudication and supervision of the valuation studies of the Transmission facilities, through Exempt Resolution No. 271 dated April 26, 2019. Additionally, through Exempt Resolution No. 678 dated October 24, 2019, it approved the Service Provision Contract for the National Transmission Study.

c.5  Energy Tenders

Under the new law for energy tenders, three bidding processes have been carried out: Supply Bidding No. 2015/01, Supply Bidding No. 2015/02 and Supply Bidding No. 2017/01. In addition, the CNE declared the start of a fourth process called Supply BiddingNo. 2019 01/2019.

Supply Bidding No. 2015/02 was launched in June 2015 and finalized in October 2015. The final outcome of the process resulted in three energy blocks awarded for a total of 1.2 GWh per year (100%) at a weighted average price of US$ 79.3 per MWh.

Supply Bidding No. 2015/01 was launched in May 2015 and finalized in July 2016. The final outcome of the process resulted in five energy blocks awarded for a total of 12.4 GWh (100%) to 84 companies at a weighted average price of US$ 47.6 per MWh.

Enel Generación Chile was awarded with 5.9 TWh per year, which represents 47.6% of the total energy awarded.

Supply Bidding No. 2017/01 was launched in January, 2017 and finalized in November 2017. The final outcome of the process resulted in five energy blocks awarded to five companies for a total of 2,200 GWh per year at a weighted average price of US$ 32.5 per MWh.

Enel Generación Chile was awarded with 1.2 TWh per year, which represents 54% of the total energy awarded.

During 2019, the Supply Bidding No. 2019/01 process began, which contemplates a total amount of 5.8TWh per year to be tendered, with a validity period between 2026 and 2040. The closing date for the presentation of bids, is May 27, 2020, as announced by the CNE.

5.    NON-CURRENT ASSETS OR DISPOSAL GROUPS CLASSIFIED AS HELD FOR SALE.

i.   Electrogas S.A.

On December 16, 2016, our subsidiary Enel Generación Chile S.A. signed an agreement to sell all shares of its equity method investee Electrogas S.A., representing a 42.5% ownership interest, to Aerio Chile SpA (“Aerio Chile”) which

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is an indirectly wholly-owned subsidiary of REN – Redes Energéticas Nacionais, S.G.P.S., S.A., under which Enel Generación Chile sold all its shares in Electrogas S.A., representing 42.5% of the capital of said company. The total price was US$180 million, which was paid on the closing date of the referred transaction. Finally, the amount collected was ThCh$115,582,806 and originated a pre-tax gain of ThCh$105,311,912 (see Notes 8.c and 33, respectively).

Electrogas S.A. is a private corporation whose purpose is to provide services of transportation of natural gas and other fuels, on its own and on behalf of third parties. In order to provide its services, it can build, operate and maintain gas and oil pipelines, polyducts and supplementary facilities.

6.    BUSINESS COMBINATIONS UNDER COMMON CONTROL.

Corporate restructuring project

Considering the high priority given to renewable energies in the Open Power strategy, and with the purpose of consolidating a vehicle that maximizes this strategy, on August 25, 2017 Enel Chile proposed for the consideration of Enel S.p.A., a corporate restructuring of Renewable Assets(hereinafter the “Reorganization”) which consisted of integrating the renewable energy assets in Chile maintained by Enel Green Power Latin America S.A. (“EGPL“) with Enel Chile, which in turn controlled the conventional power generation assets belonging to Enel Generación Chile S.A. (“Enel Generación Chile“) and the electricity distribution assets belonging to Enel Distribución Chile S.A.

Enel Chile and Enel Generación Chile are entities registered with the Financial Market Commission of Chile and had American Depository Receipts (“ADS“) traded on the New York Stock Exchange, and are therefore also subject to regulation by the Securities and Exchange Commission of the United States of America.

EGPL was an indirect subsidiary of Enel S.p.A., directly controlled by Enel Green Power SpA. (“EGP”).

The Reorganization involved two principal phases, each of which was conditional on the implementation of the other, as follows:

i) Public tender offer

Enel Chile presented a public tender offer (the “Tender Offer”) for all of the shares (including in the form of American Depositary Shares (“ADSs”)) of its subsidiary Enel Generación Chile held by non-controlling interests (equivalent to approximately 40% of the share capital). The Tender Offer consideration was paid in cash, subject to the condition that tendering Enel Generación Chile shareholders agreed to use Ch$236 of the Ch$590 cash tender offer consideration for each Enel Generación Chile share and Ch$7,080 of the Ch$17,700 cash tender offer consideration for each Enel Generación Chile ADS to subscribe for shares of Enel Chile common stock at a subscription price of Ch$82 per Enel Chile share (or Ch$4,100 per Enel Chile ADS) (the “Share/ADS Subscription Condition”).

ii) Capital increase

Enel Chile undertook  a capital increase (the “Capital Increase”) to make available a sufficient number of shares of Enel Chile common stock to deliver to tendering holders of Enel Generación Chile shares and ADSs to satisfy the Share/ADS Subscription Condition.

In connection with the Capital Increase, in accordance with Chilean law, Enel Chile made a preemptive rights offering, in which shareholders or third parties could exercise their subscription rights and pay Ch$82 per subscribed Enel Chile shares.

iii) Merger

After the Tender Offer was declared successful, EGPL merged with Enel Chile (the ”Merger“). Consequently, the renewable assets held by EGPL were integrated into Enel Chile.

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On December 20, 2017, the Extraordinary Shareholders’ Meeting of Enel Chile approved the Reorganization, subject to compliance with the conditions established for the Tender Offer, Capital Increase and Merger. The Board also approved the capital increase of Enel Chile in the amount of Ch$1,891,727,278,668, through the issuance of 23,069,844,862 new common shares, all of the same series and without par value, at the price and other conditions approved by the Board.

Finally, on March 25, 2018, the amendments to Enel Chile’s by-laws were approved to reflect the merger, capital increase and expansion of Enel Chile’s corporate purpose, among other provisions. The preemptive rights offering took place between February 16 and March 22, 2018; the shares were subscribed between February 15 and March 16, 2018 to cover the capital increase; and the Reorganization (including the Merger) was completed and became effective as of April 2, 2018 and resulted in an increase of Enel Chile’s ownership in Enel Generación Chile from 59.98% to 93.55% and the Merger of Enel Chile with EGPL effective as of this date, a process whereby Enel S.p.A. increased its total interest in Enel Chile to 61.93%.

Since the date of acquisition, EGP Chile Group has contributed revenue of ThCh$52,892,734 and pretax income of ThCh$30,471,438  to the profit and loss of Enel Chile for the period ended December 31, 2018. If the acquisition had occurred on January 1, 2018, it is estimated that the consolidated revenue for the year ended December 31, 2018 would have increased to ThCh$71,072,559 and the consolidated gain before tax would have increased by ThCh$43,360,620.

Carrying amount of the assets and liabilities of EGPL at the merger date:

Identifiable net assets acquired	ThCh$
Cash and cash equivalents	12,173,982
Other current financial assets	8,460
Other current non-financial assets	3,832,583
Trade and other current receivables	27,414,273
Current accounts receivables to related parties	73,749,131
Inventories	2,851,171
Current tax assets	2,750,250
Other non-current financial assets	5,685,422
Other non-current non-financial assets	262,878
Trade and other non-current receivables	43,829,961
Intangible assets other than goodwill	41,786,159
Goodwill	6,652,935
Property, plant and equipment	1,365,850,084
Deferred tax assets	21,246,605
Other current financial liabilities	(62,444,763)
Trade and other current payables	(49,109,886)
Current accounts payable to related parties	(33,381,911)
Current tax liabilities	(347,483)
Other non-current financial liabilities	(259,856,654)
Non-current accounts payable to related parties	(396,081,972)
Other non-current provision	(9,169,918)
Deferred tax liabilities	(58,067,689)
Provisions for non-current employee benefits	(603,109)
Net identifiable assets acquired	739,030,509

7.    ARGENTINA’S HYPERINFLATIONARY ECONOMY.

Since July 2018, Argentina’s economy is considered hyper-inflationary under the provisions of IAS 29 - Financial Reporting in Hyperinflationary Economies. A number of qualitative and quantitative criteria led to this qualification; chief among them is the cumulative inflation rate over three years exceeding 100%.

In accordance with the provisions of IAS 29, the financial statements of the companies in Argentina in which Enel Chile has an interest have been retrospectively restated by applying a general price index to the historical cost, in order to reflect changes in the purchasing power of the Argentine currency as of the closing date of these financial statements.

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The general price indices used at the close of the reporting periods are as follows:

	General price index
From January 2015 to December 2017	85.52%
From January to December 2018	47.83%
From January to December 2019	53.64%

The following is a summary of the effect in the Consolidated Statements of Comprehensive Income of Enel Chile:

	As of December 31,
Result due to Hyperinflation	2019	2018
	ThCh$	ThCh$
Intangible assets other than goodwill	203	180
Property, plant and equipment	1,132,453	1,035,084
Equity	(5,805,120)	(3,743,959)
Other Services Provision	(664,454)	(1,189,452)
Other Variable Provisioning and Services	431	21,503
Employee benefits expenses	166,715	143,148
Other Fixed Operating Expenses	127,226	147,975
Financial income	(367,059)	(268,511)
Financial costs	44,707	67,707
Result due to Hyperinflation *	(5,364,898)	(3,786,325)

(*) Corresponds to the financial effect derived from the application of IAS 29 Financial Reporting in Hyperinflationary Economies, which is derived from the results arising from the net position of monetary assets and liabilities. This result is determined through the restatement of non-monetary assets and liabilities, as well as those income statements that are not determined from an updated base (see Note 34).

The cumulative effects of adoption IAS 29 as of January 1, 2018 on the financial statements of Enel Chile’s Argentine subsidiary was a credit of ThCh$664,470, net of tax, and was recognized as an adjustment to beginning retained earnings. (see Note 2.7.4).

8.    CASH AND CASH EQUIVALENTS.

a) The detail of cash and cash equivalents as of December 31, 2019 and 2018, is as follows:

	As of December 31,
	2019	2018
Cash and Cash Equivalents	ThCh$	ThCh$
Cash balances	31,416	44,326
Bank balances	24,960,269	98,395,997
Time deposits	14,600,772	5,782,252
Other fixed-income instruments	196,092,043	140,949,349
Total	235,684,500	245,171,924

Time deposits have a maturity of three months or less from their date of acquisition and accrue the market interest for this type of short-term investment. Other fixed-income instruments, are mainly comprised of repurchase agreements maturing in 90 days or less from the date of investment. There are no restrictions for significants amounts of cash availability.

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b) The detail of cash and cash equivalents by currency is as follows:

	As of December 31,
	2019	2018
Currency	ThCh$	ThCh$
Chilean peso	209,818,277	222,434,412
Argentine peso	7,096,519	6,057,793
Euros	654,319	103,847
U.S. dollar	18,115,385	16,575,872
Total	235,684,500	245,171,924

c) The following tables sets forth cash and cash equivalents that have been received from the sale of shares of associates during the years ended December 31, 2019, 2018 and 2017:

	2019	2018	2017 (*)
Loss of control at Associates	ThCh$	ThCh$	ThCh$
Amounts received for the sale of Associates (*)	—	—	115,582,806
Total	—	—	115,582,806

(*)  See Note 5.

d) Reconciliation of liabilities arising from financing activities:

		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2019 (1)	From	Used	Interestpaid	Total	Acquisition of subsidiaries	Changes in fair value	Foreignexchange differences	Financial costs  (2)	New leases	Other changes	Balance as of 12-31-2019 (1)
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Bank loans (Note 21.1)	512,547,718	—	(284,022,562)	(16,242,086)	(300,264,648)	—	—	24,797,525	15,926,293	—	(4,462,601)	248,544,287
Unsecured obligations (Note 21.2)	1,505,282,083	—	(31,300,902)	(80,892,559)	(112,193,461)	—	—	99,245,420	85,089,982	—	(134,121)	1,577,289,903
Leases (Note 21.4)	14,476,450	—	(4,498,202)	(641,609)	(5,139,811)	—	—	4,437,227	1,815,169	37,818,654	—	53,407,689
Financial derivatives for hedging (Note 9 and 23)	40,611,925	1,791,715	(33,584,639)	(5,805,822)	(37,598,746)	—	46,396,434	(32,145,989)	398,636	—	(1,418,539)	16,243,721
Loans to related parties (Note 12.1.b)	447,317,781	283,831,505	—	(30,847,678)	252,983,827	—	—	52,606,156	31,328,749	—	(2,360,689)	781,875,824
Other obligations	—	—	(1,744,199)	—	(1,744,199)	—	—	—	1,744,199	—	—	—
Total	2,520,235,957	285,623,220	(355,150,504)	(134,429,754)	(203,957,038)	—	46,396,434	148,940,339	136,303,028	37,818,654	(8,375,950)	2,677,361,424
		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2018 (1)	From	Used	Interestpaid	Total	Acquisition of subsidiaries	Changes in fair value	Foreignexchange differences	Financial costs  (2)	New leases	Other changes	Balance as of 12-31-2018 (1)
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Bank loans (Note 21.1)	122	940,414,450	(812,568,125)	(22,902,945)	104,943,380	322,301,558	—	51,622,432	27,929,781	—	5,750,445	512,547,718
Unsecured obligations (Note 21.2)	763,579,584	625,368,154	(5,654,112)	(59,362,432)	560,351,610	—	—	128,056,234	64,400,703	—	(11,106,048)	1,505,282,083
Finance leases (Note 21.4)	14,608,914	—	(1,889,685)	(739,070)	(2,628,755)	—	—	1,757,221	739,070	—	—	14,476,450
Other liabilities (Note 18.1)	—	—	(1,303,692)		(1,303,692)		—	52,972		—	1,250,720	—
Financial derivatives for hedging (Note 9 and 23)	(29,478,642)	—	—	(3,496,889)	(3,496,889)	(5,495,214)	48,389,489	32,202,403	3,569,025	—	(5,078,247)	40,611,925
Loans to related parties (Note 12.1.b)	—	—	—	(30,039,555)	(30,039,555)	398,462,271	—	51,063,262	29,906,460	—	(2,074,657)	447,317,781
Other obligations	—	—	(23,307,842)	—	(23,307,842)	—	—	—	23,307,842	—	—	—
Total	748,709,978	1,565,782,604	(844,723,456)	(116,540,891)	604,518,257	715,268,615	48,389,489	264,754,524	149,852,881	—	(11,257,787)	2,520,235,957
		Financing Cash Flows				Non-Cash Changes
Liabilities arising from financing activities	Balance as of 1-1-2017	From	Used	Interestpaid	Total	Acquisition of subsidiaries	Changes in fair value	Foreignexchange differences	Financial costs  (2)	New leases	Other changes	Balance as of 12-31-2017
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Bank loans (Note 21.1)	4,274	—	(4,156)	(12,581)	(16,737)	—	—	—	12,585	—	—	122
Unsecured obligations (Note 21.2)	802,306,160	—	(5,530,327)	(43,514,578)	(49,044,905)	—	—	(33,226,098)	43,544,427	—	—	763,579,584
Finance leases (Note 21.4)	17,749,647	—	(2,592,236)	—	(2,592,236)	—	—	(1,359,668)	811,171	—	—	14,608,914
Financial derivatives for hedging (Note 9 and 23)	23,640,892	—	(3,543,399)	—	(3,543,399)	—	(25,059,561)	(23,488,917)	3,473,938	—	(4,501,595)	(29,478,642)
Loans to related parties (Note 12.1.b)	—	150,000,000	(150,000,000)	(289,800)	(289,800)	—	—	—	289,800	—	—	—
Other obligations	—	—	(1,305,389)	—	(1,305,389)	—	—	—	1,305,389	—	—	—
Total	843,700,973	150,000,000	(162,975,507)	(43,816,959)	(56,792,466)	—	(25,059,561)	(58,074,683)	49,437,310	—	(4,501,595)	748,709,978

(1) Balance corresponds to current and non-current portion.

(2) Other changes include interest accruals

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9.    OTHER FINANCIAL ASSETS.

The detail of other financial assets as of December 31, 2019 and 2018 is as follows:

	Current		Non-current
	12-31-2019	12-31-2018	12-31-2019	12-31-2018
Other Financial Assets	ThCh$	ThCh$	ThCh$	ThCh$
Financial assets at fair value with changes in results	—	90,839	—	—
Financial assets at fair value with changes in other comprehensive income	127,854	269,031	2,349,223	2,352,894
Financial assets Financial assets measured at amortized cost	860,425	880,268	—	689,146
Hedging derivatives	322,316	39,022,012	4,871,397	4,191,543
Non-Hedging derivatives	—	41,023	—	36,086
Total	1,310,595	40,303,173	7,220,620	7,269,669

10. OTHER NON-FINANCIAL ASSETS AND LIABILITIES

a) Other non-financial assets

Details of other non-financial assetsas of December 31, 2019 and 2018 are as follows:

	Currrent		Non-Current
Other non-financial assets	12-31-2019	12-31-2018	12-31-2019	12-31-2018
	ThCh$	ThCh$	ThCh$	ThCh$
VAT Tax Credit and Other Taxes	19,497,233	11,281,502	19,799,224	29,198,027
Prepaid expenses	12,329,859	4,711,173	-	-
Guarantee deposit	-	-	1,879,019	1,902,479
PPM water rights	-	-	7,670,114	6,544,100
Spare parts with consumption schedule over 12 months	-	-	5,773,991	4,324,153
Other	2,807,471	6,413,413	2,927,836	2,639,253
Total	34,634,563	22,406,088	38,050,184	44,608,012

b) Other non-financial liabilities

Details of other non-financial liabilities as of December 31, 2019 and 2018 are as follows:

	Currrent		Non-Current
Other non-financial liabilities	12-31-2019	12-31-2018	12-31-2019	12-31-2018
	ThCh$	ThCh$	ThCh$	ThCh$
VAT and Other Taxes due	31,616,664	56,341,865		-
Reimbursable financial contributions	-	-	1,302,759	226,653
Splices	9,283,177	10,456,081		-
Transfer of networks	2,845,708	1,786,635		-
Products and services	1,088,498	1,502,411		-
Other	674,336	1,221,990		-
Total	45,508,383	71,308,982	1,302,759	226,653

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11.    TRADE AND OTHER RECEIVABLES.

a) The detail of trade and other receivables as of December 31, 2019 and 2018, is as follows:

	As of December 31,
	2019		2018
	Current	Non-current	Current	Non-current
Trade and Other Receivables, Gross	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, gross	566,919,977	313,574,385	527,649,947	60,527,843
Trade receivables, gross	500,040,783	191,966,929	457,053,617	2,046,845
Leasing accounts receivables, gross	13,158,795	117,873,340	6,791,579	55,651,630
Other receivables, gross	53,720,399	3,734,116	63,804,751	2,829,368
	As of December 31,
	2019		2018
	Current	Non-current	Current	Non-current
Trade and Other Receivables, Net	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other receivables, net	511,455,330	313,574,385	478,170,067	60,527,843
Trade and other receivables, net	456,552,682	191,966,929	417,927,182	2,046,845
Leasing accounts receivables, net	11,121,878	117,873,340	6,101,812	55,651,630
Other receivables, net (1)	43,780,770	3,734,116	54,141,073	2,829,368

(1) The details of Other Receivables, net is as follows:

	As of December 31,
	2019		2018
Other receivables, net	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Other receivables, net	43,780,770	3,734,116	54,141,073	2,829,368
Recoveries from insurance companies	2,011,406	—	18,805,057	—
Accounts receivable from employees	10,017,453	3,308,861	9,237,209	2,426,697
Advances to suppliers and creditors	19,864,669	415,787	19,236,907	402,671
Others	11,887,242	9,468	6,861,900	—

As of December 31, 2019, non-current trade accounts receivable , gross increased by ThCh$189,920,084 compared to December 31, 2018.

On November 2, 2019, the Ministry of Energy published Law No.21,185, which creates a Transitional Mechanism for the Stabilization of Electricity Prices for Customers Subject to Tariffs Regulation. Through this Law, between July 1, 2019 and December 31, 2020, the prices to be charged to regulated customers are kept at the same price levels defined for the first half of 2019 (Decree 20T/2018) and will be called the “ Stabilized Price to Regulated Client ”(PEC in Spanish).

Between January 1, 2021 and until the end of the stabilization mechanism, the prices will be the amounts established semi-annually in accordance with article 158 of the Electricity Law, but may not exceed the PEC as adjusted by the Consumer’s Price Index as of January 1, 2021 based on the same date (adjusted PEC)

The differences that occur between the billing applying the stabilization mechanism and the theoretical billing, considering the price that would have been applied in accordance with the conditions of the respective contracts with the electricity distribution companies, will generate an account receivable in favor of the electricity generation companies with a limit of US$1,350 million until 2023. All billing differences will be denominated in US dollars and will not accrue interest until December 31, 2025. The balance must be recovered no later than December 31, 2027.

The application of the aforementioned Law, causes a greater lag in the billing and collection of sales generated in our Electricity Generation segment, with the corresponding financial and accounting impact that the situation entails. For this reason, at the end of 2019, Enel Generación Chile recognized lower revenues from energy sales and a higher

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financial expense of ThCh$2,600,428 and ThCh$14,250,887, respectively. In addition, a profit was recorded for exchange differences of ThCh$ 3,835,024, due to the dollarization of accounts receivable pending for invoicing, and financial income of ThCh$414,292.

In the case of our Electricity Distribution segment, the financial and accounting effects are neutralized (pass-through principle). In effect, at the end of 2019, Enel Distribución Chile recognized lower sales revenues to end customers of ThCh$ 2,083,048 and the same value as lower cost of energy purchase. On the other hand, it recognized ThCh$10,241,505 as financial income for the postponement of payment to the electricity supply providers and the same amount as financial expense for the postponement of the payment to final customers, as well as positive and negative exchange differences for ThCh$2,825,769, for the dollarization of the corresponding accounts payable and receivable already mentioned.

As a result of the situations described above and after eliminating transactions between related companies, at the end of 2019, the Group reclassified non-current trade accounts receivable for ThCh$182,076,569 and suppliers for energy purchases for ThCh$53,941,373 (see Note 24). Along with this, it meant an impact on lower revenues from energy sales of ThCh $ 3,782,091 and a lower cost in energy purchases of ThCh$1,181,163, and higher revenues and financial costs of ThCh$5,225,739 and ThCh$ 19,062,333, respectively, were recognized, (see Note 34). In addition, the Group recorded a profit for net exchange differences of ThCh $ 3,835,024, for the dollarization of accounts receivable pending billing (see Trade and other current receivable, in Note 34 corresponds to financial results).

As of December 31, 2018, the accounts receivable and payable that resulted from the differences between the prices of the electricity supply contracts and the regulated prices, amounted to ThCh$48,196,306 and ThCh$6,718,177, respectively, and were presented in short term.

The concepts indicated above, both commercial and non-commercial, although they are included in the impairment loss determination model (see Note 3.g.3), do not have a greater impact at the end of December 2019, due to the nature of these items: invoices pending issuance, invoices pending expiration or invoices due within normal business ranges.

There are no significant trade and other receivables balances held by the Group that are not available for its use.

The Group does not have customers with sales representing 10% or more of its total consolidated revenues for the years ended December 31, 2019 and 2018. Refer to Note 12.1 for detailed information on amounts, terms and conditions associated with accounts receivable from related parties.

a) Lease receivables

As of December 31, 2019 and 2018, the present value of minimum lease payments receivable is as follows:

	12-31-2019			12-31-2018
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	15,313,622	4,191,744	11,121,878	8,033,838	1,932,026	6,101,812
From one to two years	17,350,359	3,919,937	13,430,422	8,033,838	1,553,584	6,480,254
From two to three years	17,350,359	3,630,136	13,720,223	8,033,838	1,549,927	6,483,911
From three to four years	17,316,251	3,115,800	14,200,451	8,033,838	1,512,895	6,520,943
From four to five years	17,271,708	2,246,896	15,024,812	7,994,153	1,028,452	6,965,701
More than five years	65,391,395	3,893,963	61,497,432	31,901,489	2,700,668	29,200,821
Total	149,993,694	20,998,476	128,995,218	72,030,994	10,277,552	61,753,442

Lease arrangements are related to public lightning developments mainly to municipalities.

F-59

b) As of December 31, 2019 and 2018, the analysis of trade accounts receivable due and unpaid, but of which no impairment losses have been recorded, is as follows:

Trade Receivables Past Due But Not Impaired (*)	As of December 31,
	2019	2018
	ThCh$	ThCh$
Less than three months	43,661,270	37,711,262
Between three and six months	6,462,265	3,916,489
Between six and twelve months	5,162,189	5,312,988
More than twelve months	10,668,714	11,328,175
Total	65,954,438	58,268,914

c) The reconciliation of changes in the allowance for credit loss of trade receivables, determined according to Note 3.g.3, is as follows:

	Current and
	Non-current
Trade Receivables allowance for credit loss	ThCh$
Balance at December 31, 2017	43,874,059
Initial balance adjustment for IFRS 9	4,673,467
Amounts written off	(3,863,702)
Increase (decreases) for the year	4,783,072
Other movements	12,984
Balance at December 31, 2018	49,479,880
Increases (decreases) for the year (*)	10,047,000
Amounts written off	(4,067,201)
Foreign currency translation differences	4,968
Balance at December 31, 2019	55,464,647

(*)   See Note 31 for impairment of financial assets.

Write-offs for past due receivables

Past due receivables are written off once all collection procedures and legal proceedings have been exhausted and the debtors’ insolvency has been demonstrated. In our power generation business, this process normally takes at least one year. In our distribution business the process takes at least twenty four months. Overall, the risk of writing off our trade receivables is limited (see Notes 3.g.3 and 22.5)

d) Additional information:

-Additional statistical information required under Official Bulletin 715 of the CMF of February 3, 2012 (XBRL Taxonomy). See Appendix 2.

-Supplementary information on trade receivables. See Appendix 2.1.

F-60

12.    BALANCES AND TRANSACTIONS WITH RELATED PARTIES.

Related party transactions are performed at current market conditions.

Transactions between the Group and its subsidiaries, associates and joint ventures have been eliminated on consolidation and are not itemized in this note.

As of the date of these consolidated financial statements, no guarantees have been given or received nor has any allowance for bad or doubtful accounts been recorded with respect to receivable balances for related party transactions.

The controlling shareholder of the Company is the Italian corporation Enel S.p.A..

Enel Chile S.A. provides administrative services to its subsidiaries, through a Centralized Cash Contract that has been in effect since the second half of 2018, which finances the cash deficits of its subsidiaries or consolidates their cash surpluses. These accounts may have a debit or credit balance and are prepayable in the short-term , where interest rate is variable and represents market conditions. To reflect these market conditions, interest rates are periodically reviewed through an update procedure approved by the Board of Directors of the companies involved. Prior to the entry into the Centralized Cash Contract, Enel Chile and some subsidiaries had a Trade Checking Account Contract, through which intercompany loans could be delivered to each other.

12.1 Balances and transactions with related parties

The accounts receivable and payable balances as of December 31, 2019 and 2018 are as follows:

a)    Receivables from related parties

							Current		Non-current
Taxpayer ID							12-31-2019	12-31-2018	12-31-2019	12-31-2018
Number	Company	Country	Relationship	Currency	Descriptionof transaction	Term of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	26,979	27,023	-	-
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	146,061	-	-	-
Foreign	Enel Green Power Morocco	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	94,340	-	-	-
76.418.940-K	GNL Chile S.A.	Chile	Associate	US$	Advance Gas Purchase	Less than 90 days	31,025,024	14,666,414	34,407,142	-
76.418.940-K	GNL Chile S.A.	Chile	Associate	US$	Dividends	Less than 90 days	-	788,336	-	-
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	45,069	41,820	-	-
Foreign	Enel Italy SrL.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	403,854	295,892	-	-
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	120,276	44,675	-	-
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Gas sales	Less than 90 days	16,880,527	18,565,698	-	-
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Commodity derivatives	Less than 90 days	2,962,387	3,671,446	-	-
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	467,393	415,200	-	-
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	CH$	Other services	Less than 90 days	-	281,002	-	-
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	R$	Other services	Less than 90 days	705,954	-	-	-
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	-	173,300	-	-
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	578,847	703,368	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	$ Col	Other services	Less than 90 days	-	427,882	-	-
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	859,573	-	-	-
Foreign	Enel Generación Peru S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	1,180,707	973,873	-	-
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	-	107,071	-	-
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	2,850,769	4,197,951	-	-
Foreign	Enel Green Power Colombia SAS	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	489,301	419,032	-	-
Foreign	Enel Generación Piura S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	60,670	89,545	-	-
Foreign	Enel Green Power Spa IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,399,057	2,405,958	-	-
Foreign	Enel Green Power Spa IT	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	1,509,373	-	-	-
Foreign	Sociedad Portuaria Central Cartagena S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	149,525	-	-	-
Foreign	Enel Distribución Peru S.A.	Peru	Common Immediate Parent	CH$	Other services	Less than 90 days	603,171	354,283	-	-
Foreign	Enel Green Power México	México	Common Immediate Parent	US$	Other services	More than 90 days	-	98,519	-	-
Foreign	Enel Green Power Peru	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	1,765,939	1,959,124	-	-
Foreign	Energía Nueva Energía Limpia Mexico S.R.L	México	Common Immediate Parent	US$	Other services	Less than 90 days	108,327	52,241	-	-
Foreign	Proyectos y Soluciones Renovables S.A.C.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	60,717	29,054	-	-
Foreign	Enel Generacion Costanera S.A.	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	34,771	32,264	-	-
Foreign	Enel Generacion El Chocon S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	12,589	13,367	-	-
Foreign	Enel Green Power Brazil Participacoes LTDA.	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	-	52,215	-	-
Foreign	Enel Green Power Brazil Participacoes LTDA.	Brazil	Common Immediate Parent	R$	Other services	Less than 90 days	127,879	23,329	-	-
Foreign	Enel Finance International NV	Holland	Common Immediate Parent	US$	Loan receivable	Less than 90 days	-	1,008,208	-	-
Foreign	Enel Green Power Argentina	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	284,876	276,607	-	-
Foreign	Energetica Monzon S.A.C.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	461,677	601,512	-	-
Foreign	Enel Green Power RSA (PTY) LTD	South Africa	Common Immediate Parent	US$	Other services	Less than 90 days	385,716	466,281	-	-
Foreign	Enel Green Power RSA (PTY) LTD	South Africa	Common Immediate Parent	CH$	Other services	Less than 90 days	110,699	-	-	-
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	141,708	57,761	-	-
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	CH$	Other services	Less than 90 days	7,381	-	-	-
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	CH$	Other services	Less than 90 days	-	23,077	-	-
Foreign	Empresa Distribuidora Sur S.A.	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	1,305,475	464,846	-	-
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	341,200	309,717	-	-
Foreign	Enel X SLR	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	26,954	14,233	-	-
Foreign	Enel Global I&N S.R.L.	Italy	Common Immediate Parent	CH$	Other services	Less than 90 days	-	10,365	-	-
Foreign	Enel Produzione	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	13,781	-	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	273,003	-	-	-
Foreign	Enel X North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	92,730	-	-	-
Foreign	Parque Amistad II SA de CV	México	Common Immediate Parent	US$	Other services	Less than 90 days	50,264	-	-	-
Foreign	Parque Amistad IV SA de CV	México	Common Immediate Parent	US$	Other services	Less than 90 days	17,590	-	-	-
76.091.595-5	Aysén Energía	Chile	Joint venture	CH$	Other services	Less than 90 days	-	14,286	-	-
76.041.891-9	Aysén Transmisión	Chile	Joint venture	CH$	Other services	Less than 90 days	-	14,285	-	-
						Total	68,182,133	54,171,060	34,407,142	-

F-61

b)    Accounts payable to related parties

							Current		Non-current
Taxpayer ID							12-31-2019	12-31-2018	12-31-2019	12-31-2018
Number	Company	Country	Relationship	Currency	Description of transaction	Terms of transaction	ThCh$	ThCh$	ThCh$	ThCh$
Foreign	Endesa Spain	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	159,940	159,940	—	—
Foreign	Enel Brasil S.A.	Brazil	Common Immediate Parent	US$	Other services	Less than 90 days	—	74,949	—	—
Foreign	Enel Trading Argentina S.R.L.	Argentina	Common Immediate Parent	US$	Other services	Less than 90 days	86,189	77,624	—	—
Foreign	Emgesa S.A. E.S.P.	Colombia	Common Immediate Parent	$ Col	Other services	Less than 90 days	4,723	4,723	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	1,909,747	1,461,815	—	—
94.271.000-3	Enel Américas S.A.	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	—	1,987	—	—
Foreign	Enel Distribución Peru S.A.	Peru	Common Immediate Parent	US$	Other services	Less than 90 days	2,291	2,291	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	57,324	—	—	—
Foreign	Enel Global Infrastructure and Network	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	1,984,129	1,235,525	—	—
76.418.940-K	GNL Chile S.A.	Chile	Associate	US$	Gas Purchase	Less than 90 days	4,980,936	5,935,652	2,497,660	—
76.418.940-K	GNL Chile S.A.	Chile	Associate	CH$	Other services	Less than 90 days	—	12,389	—	—
Foreign	Endesa Generación	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	216,522	702,702	—	—
Foreign	Enel Iberia SRL	Spain	Common Immediate Parent	CH$	Other services	Less than 90 days	—	35	—	—
Foreign	Enel Iberia SRL	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	883,576	820,642	—	—
Foreign	E-Distribuzione Spa	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	49,488	336,814	—	—
Foreign	Enel Produzione IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	6,043,110	7,482,038	—	—
Foreign	Enel Energía	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	452,289	452,289	—	—
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Joint venture	CH$	Tolls	Less than 90 days	13,887	13,887	—	—
Foreign	Enel Green Power Spain SL	Spain	Common Immediate Parent	Euros	Other services	Less than 90 days	352,233	217,859	—	—
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	1,099,133	2,258,059	—	—
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Commodity derivatives	Less than 90 days	9,295,836	9,849,260	—	—
Foreign	Enel Global Trading S.p.A. IT	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	2,857,244	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	CH$	Dividends	Less than 90 days	35,863,042	67,197,814	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Dividends	Less than 90 days	19,155,829	—	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Technical services	Less than 90 days	6,982,284	2,825,084	—	—
Foreign	Enel S.p.A.	Italy	Parent	Euros	Other services	Less than 90 days	2,965,604	3,041,172	—	—
Foreign	Enel Italy SrL IT	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	6,438,614	1,528,308	—	—
Foreign	Enel Italy SrL IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	9,115,709	10,658,407	—	—
Foreign	Codensa S.A.	Colombia	Common Immediate Parent	US$	Other services	Less than 90 days	17,950	13,579	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	3,017,847	2,199,811	—	—
Foreign	Enel Global Thermal Generation S.r.l.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	681,544	—	—	—
Foreign	Enel Green Power Spa IT	Italy	Common Immediate Parent	US$	Other services	Less than 90 days	6,328,568	—	—	—
Foreign	Enel Green Power Spa IT	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	19,758,903	13,743,624	—	—
Foreign	Enel Green Power Spa IT	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	8,514,576	16,609,801	—	—
Foreign	Enel Green Power North America Inc	United States	Common Immediate Parent	US$	Other services	Less than 90 days	248,051	149,591	—	—
Foreign	Enel Finance International NV (*)	Holland	Common Immediate Parent	US$	Loan	Less than 90 days	—	123,979	781,875,824	447,193,802
Foreign	Enel Finance International NV	Holland	Common Immediate Parent	US$	Other services	Less than 90 days	134,278	—	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	344,877	370,028	—	—
76.802.924-3	Energía y Servicios South America Spa	Chile	Common Immediate Parent	US$	Other services	Less than 90 days	107,037	—	—	—
76.364.085-K	Energía Marina S.P.A	Chile	Common Immediate Parent	CH$	Other services	Less than 90 days	2,357	—	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	198,815	40,656	—	—
Foreign	Enel X S.R.L.	Italy	Common Immediate Parent	Euros	Technical services	Less than 90 days	147,488	—	—	—
Foreign	Cesi S.p.A.	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	890,343	458,228	—	—
Foreign	Tecnatom SA	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	29,093	102,962	—	—
Foreign	Enel Green Power Spa GLO	Italy	Common Immediate Parent	Euros	Other services	Less than 90 days	8,418,481	7,772,801	—	—
						Total	159,809,887	157,936,325	784,373,484	447,193,802

(*)See section d) below.

c)    Significant transactions and effects on income/expenses:

The details of the most significant non-consolidated transactions with related parties, are as follows:

					For the years ended December 31,
					2019	2018	2017
Taxpayer ID No.	Company	Relationship	Country	Description of transaction	ThCh$	ThCh$	ThCh$
Foreign	Endesa Energía S.A.	Common Immediate Parent	Spain	Gas sales	-	-	10,394,146
94.271.000-3	Enel Américas S.A.	Common Immediate Parent	Chile	Other services rendered	4,748,244	5,071,453	4,737,522
76.418.940-K	GNL Chile S.A.	Associate	Chile	Fuel consumption	( 99,801,403 )	( 131,521,989 )	( 194,163,392 )
96.524.140-K	Empresa Eléctrica Panguipulli S.A.	Common Immediate Parent	Chile	Energy purchase	-	( 1,954,523 )	( 11,758,824 )
76.321.458-3	Sociedad Almeyda Solar Spa	Common Immediate Parent	Chile	Energy purchase	-	( 1,052,840 )	( 4,306,145 )
76.052.206-6	Parque Eolico Valle de los Vientos SpA	Common Immediate Parent	Chile	Energy purchase	-	( 3,349,525 )	( 16,630,422 )
Foreign	Enel S.p.A.	Parent	Italy	Technical services	( 4,110,257 )	-	-
Foreign	Enel Italy Servizi	Common Immediate Parent	Italy	Other fixed operating expenses	-	-	( 2,230,668 )
76.412.562-2	Enel Green Power del Sur SPA	Common Immediate Parent	Chile	Energy purchase	-	( 30,205,373 )	( 104,865,684 )
76.179.024-2	Parque Eolico Tal Tal SpA	Common Immediate Parent	Chile	Energy purchase	-	( 4,448,833 )	( 25,959,608 )
Foreign	Enel Global Trading S.p.A.	Common Immediate Parent	Italy	Commodity derivatives	( 12,118,800 )	7,584,772	18,311,343
Foreign	Enel Global Trading S.p.A.	Common Immediate Parent	Italy	Technical services	( 1,634,832 )	( 1,213,116 )	-
Foreign	Enel Global Trading S.p.A.	Common Immediate Parent	Italy	Gas sales	58,352,346	34,701,425	21,484,590
Foreign	Enel Finance International NV	Common Immediate Parent	Holland	Financial expense	( 31,328,749 )	( 23,253,535 )	-
Foreign	Enel Italy Servizi	Common Immediate Parent	Italy	Other fixed operating expenses	-	-	( 2,230,668 )
Foreign	Enel Italy IT	Common Immediate Parent	Italy	Other fixed operating expenses	-	( 4,111,525 )	-
Foreign	Enel Italy IT	Common Immediate Parent	Italy	Other services rendered	( 3,089,599 )	-	-
Foreign	Enel Italy S.R.L. GLO	Common Immediate Parent	Italy	Technical services	( 2,750,306 )	-	-
Foreign	Enel Global Thermal Generation S.r.l.	Common Immediate Parent	Italy	Other fixed operating expenses	-	( 1,845,425 )	-
Foreign	Enel Green Power Spa IT	Common Immediate Parent	Italy	Technical services	-	( 4,257,363 )	-
Foreign	Enel Green Power Spa GLO	Common Immediate Parent	Italy	Technical services	( 3,898,762 )	-	-

F-62

d) Significant transactions

i) Enel Chile

· On December 21, 2018, Enel Finance International NV provided Enel Chile S.A. a loan  in US dollars for an amount committed up to US$400 million, with a variable interest rate of LIBOR 6M plus a margin of 1.00% annually, with semiannual interest payment and maturity on December 21, 2022. The credit agreement allowed Enel Chile S.A. to make indefinite draws for up to the amount committed until June 21, 2019, defined as the availability period, during which Enel Chile S.A. must pay an annual availability fee equivalent to 35% of the margin on the undrawn amount. On June 3 and 18, 2019, Enel Chile S.A. drew down that line in its entirety. The loan contracted by Enel Chile S.A. has a bullet maturity and can be repaid in advance, partially or totally, the commitment and interest accrued without any other fine than ”bankruptcy costs“, by delivering to Enel Finance International NV a duly anticipated pay-off request completed no later than 10 (ten) days prior to the prepayment date. Enel Chile S.A. will not have to pay any “bankruptcy costs” if the repayment date falls on an interest payment date. The balance of the debt as of December 31, 2019 amounts to US$ 400 million equivalent to ThCh$ 299,496,000. As of December 31, 2018 the line was available but not drawn.

· In June 2019, Enel Chile S.A. entered into a revolving committed credit line with Enel Finance International NV in US dollars for a total of US$50 million, with a variable interest rate of LIBOR 1M, 3M or 6M plus a margin of 0.90 %, with monthly, quarterly or semi-annual interest payments and expiration on December 24, 2024. During the availability period, Enel Chile S.A. pays an annual availability commission equivalent to 0.25% on the undrawn amount. This revolving line of credit has no guarantees and the commitment can be repaid, partially or totally, together with the accrued interest or any other cost under the agreement. Enel Chile S.A. may require  renewal of  the draft by sending a letter 5 (five) business days before the obligation expires. As of December 31, 2019 this line was not drawn.

· In May 2017, Enel Chile S.A. received short-term loans of ThCh$150,000,000 from Enel Américas S.A., which were fully amortized on May 25, 2017. These loans accrued a TIP rate of interest + 0.05% per month. As of December 31, 2018, there was no outstanding debt between Enel Chile S.A. and Enel Américas S.A.

ii) EGP Chile Group

· On December 31, 2015, Enel Green Power International B.V. (currently Enel Finance International NV) provided Parque Eólico Renaico SpA (currently Enel Green Power del Sur SpA.) a US dollar loan for a committed amount of up to US$650 million, at a variable interest rate of LIBOR 6M plus a margin of 4.94% per annum, with semi-annual interest payment and maturity on December 31, 2027. The credit agreement allowed Enel Green Power del Sur SpA to make indefinite draws up to the amount committed until December 31, 2017, defined as the availability period, during which Enel Green Power del Sur SpA paid an annual availability fee equivalent to 35% of the margin on the undrawn amount. On June 28, 2019, the interest rate margin was reduced to 1.40% annually. Additionally, on December 31, 2019, the parties agreed to modify the credit agreement again, under the following terms: (i) modification of the interest rate, from variable to fixed, establishing it at 2.82% per year, with semi-annual interest payment; and (ii) modification of  the semi-annual amortization schedule, beginning on June 30, 2024, maintaining the voluntary prepayment with bankruptcy cost (modifying the definition of bankruptcy cost); and expiration on December 31, 2027. The balance of the debt at December 31, 2019 amounts to US$644 million equivalent to ThCh$482,466,643 (US$644 million at December 31, 2018 and 2017 equivalent to ThCh$447,431,880 and ThCh$395,899,000, repectively). This is a bullet credit and is guaranteed by Enel Chile S.A.

· On February 25, 2011, Enel Green Power International B.V. (currently Enel Finance International NV) formalized with Enel Latin America Ltda. (currently Enel Green Power Chile) a mercantile mandate contract by means of which it could invest the funds and surpluses generated by the latter. The currency

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used for the movements was the U.S. dollar. This contract established annual extensions, and has been renewed and periodically amended. The conditions in force during 2018 of the contract established a variable interest rate of LIBOR 1M plus a margin of 0.80% per annum, the balance placed by Enel Green Power Chile for investment at December 31, 2019 amounted to US$0.00 million (US$1,453 million as of December 31, 2018 equivalent to ThCh$1,008,208 and US$78 million at December 31, 2017 equivalent to ThCh$47,950,500). The contract expired on December 31, 2018 and was not renewed. On February 12, 2019 the amount was repaid in full.

· On December 20, 2012, Enel Green Power International B.V. (currently Enel Finance International NV) formalized with Enel Latin America Ltda. (currently Enel Green Power Chile) a revolving credit line in U.S. dollars for an amount of up to US$250 million, at a variable interest rate of LIBOR 3M plus a margin of 2.50% per annum, with quarterly interest payment and maturity on December 31, 2013. This contract was renewed annually and increased during 2017 to US$ 800 million and during the first half of 2017, the amount committed was reduced to US$50 million. On March 28, 2018, the interest rate margin was reduced to 1.35% per annum. On October 10, 2018, the contract, which did not have associated debts, was terminated early.

12.2 Board of Directors and Key management personnel

The Company is managed by a Board of Directors which consists of seven members. Each director serves for a three-year term after which they can be reelected.

The Board of Directors as of December 31, 2019, was elected at the Ordinary Shareholders Meeting held on April 25, 2018. At a Board Meeting held on the same date the current Board Chairman and Secretary were appointed.

a)    Account receivable and payable and other transactions

· Accounts receivable and payable

There are no outstanding amounts receivable or payable between the Company and the members or the Board of Directors and key management personnel.

· Other transactions

No transactions other than the payment of compensation have taken place between the Company and the members of the Board of Directors and key management personnel and other than transactions in the normal course of business-electricity supply.

b)    Compensation for directors

In accordance with Article 33 of Law No. 18,046 governing stock corporations, the compensation of Directors is established each year at the Ordinary Shareholders Meeting of the Company.

The compensantion consists of paying to each member of the Board of Director a monthly payment, one part in a fixed monthly fee and another part dependent on meetings attended. This compensation is broken down as follows:

-     UF 216 as a fixed monthly fee in all event; and

-     UF 79.2 as a per diem for each Board meeting attended, all with a maximum of sixteen sessions in total, whether ordinary or extraordinary, in the corresponding year.

As stated in the by-laws, the compensation for the Chairman of the Board will be double that of a Director.

If any Director of the Company is a member of more than one Board in any Chilean or foreign subsidiaries and/or associates, or holds the position of director or advisor in other Chilean or foreign companies or legal entities in which

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Enel Chile S.A. has a direct or indirect ownership interest, that Director can be compensated for his/her participation in only one of those Boards or Management Committees.

The executive officers of the Company and/or any of its Chilean or foreign subsidiaries or associates will not receive any compensation or per diem if they hold the position of director in any of the Chilean or foreign subsidiaries or associates of the Company. Nevertheless, the executives may receive such compensation or per diem, provided there is prior express authorization, as a payment in advance of the variable portion of their compensation received from the respective companies through which they are employed.

Directors’ Committee:

Each member will be paid a monthly compensation, one part in a fixed monthly fee and another part dependent on meetings attended. This compensation is broken down as follows:

-     UF 72 as a fixed monthly fee, and

-     UF 26.4 as a per diem for each Board meeting attended, all with a maximum of sixteen sessions in total, whether ordinary or extraordinary, in the corresponding year.

The following tables show details of the compensation paid to the members of the Board of Directors of the Company for the years ended December 31, 2019, 2018 and 2017:

				December 31, 2019
				Enel Chile Board	Board of subsidiaries	Directors' Committee
TaxpayerID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Herman Chadwick Piñera	Chairman	January - December 2019	206,350	—	—
Foreign	Giulio Fazio	Director	January - December 2019	—	—	—
4.461.192-9	Fernan Gazmuri Plaza	Director	January - December 2019	103,175	—	33,648
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2019	103,175	—	33,648
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2019	103,175	—	33,648
Foreign	Daniele Caprini	Director	January - December 2019	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2019	—	—	—
			Total	515,875	—	100,944

				December 31, 2018
				Enel Chile Board	Board of subsidiaries	Directors' Committee
Taxpayer ID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Herman Chadwick Piñera	Chairman	January - December 2018	181,789	—	—
Foreign	Giulio Fazio	Director	January - December 2018	—	—	—
4.461.192-9	Fernan Gazmuri Plaza	Director	January - December 2018	90,894	—	31,018
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2018	90,894	—	31,018
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2018	90,894	—	31,018
Foreign	Daniele Caprini	Director	April  - December 2018	—	—	—
Foreign	Salvatore Bernabei	Director	January - December 2018	—	—	—
			Total	454,471	—	93,054

				December 31, 2017
				Enel Chile Board	Board of subsidiaries	Directors' Committee
Taxpayer ID No.	Name	Position	Period in position	ThCh$	ThCh$	ThCh$
4.975.992-4	Hermán Chadwick Piñera	Chairman	January - December 2016	178,065	—	—
Foreigner	Giulio Fazio	Director	January - December 2016	—	—	—
4.461.192-9	Fernán Gazmuri Plaza	Director	January - December 2016	89,032	—	28,504
4.774.797-K	Pedro Pablo Cabrera Gaete	Director	January - December 2016	89,032	—	28,504
5.672.444-3	Juan Gerardo Jofré Miranda	Director	January - December 2016	89,032	—	28,504
Foreigner	Vicenzo Ranieri	Director	January - December 2016	—	—	—
Foreigner	Salvatore Bernabei	Director	January - December 2016	—	—	—
			Total	445,161	—	85,512

c)    Guarantees given by the Company in favor of the directors

No guarantees have been given in favor of the directors.

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12.3 Compensation for key management personnel

Key personnel for Enel Chile as of December 31, 2019 are represented  by the following people:

Key Management Personnel
Taxpayer ID No.	Name	Position
Foreign	Paolo Palloti (1)	Chief Executive Officer
Foreign	Giuseppe Turchiarelli (2)	Administration, Finance and Control Officer
13.903.626-3	Liliana Schnaidt Hagedorn (3)	Human Resources and Organization Manager
6.973.465-0	Domingo Valdés Prieto	General Counsel and Secretary to the Board
Foreign	Raffaele Cutrignelli	Internal Audit Officer

(1)On October 1, 2018, Mr. Paolo Pallotti assumed the Chief Executive Officer position of Enel Chile replacing Mr. Nicola Cotugno.

(2)Mr. Marcelo Antonio de Jesús, who served as Adminstration, Finance and Control Officer of the Company, submitted his resignation to the Company, which became effective as of August 16 , 2019. His replacement, Mr. Giuseppe Turchiarelli  was appointed, and assumed his duties as of November 15, 2019

(3)On February 1, 2018 Mrs. Liliana Schnaidt H.  assumed the position of Human Resources and Organization Manager.

The executives listed below were part of the Company’s key personnel until September 24, 2019;

- Mónica De Martino, Regulation Officer

- Antonella Pellegrini, Sustainability and Community Manager

- Claudia Navarrete Campos, Planning and Control Officer

- Alison Dunsmore M., Services Officer

- Pedro Urzúa Frei, Institutional Relations Officer

- Raúl Puentes Barrera, Supply Manager

- Andrés Pinto Bonta, Security Manager

- Ángel Barrios Romo, ICT Officer

12.4 Incentive plans for key management personnel

The Company has implemented an annual bonus plan for its executives based on meeting company-wide objectives and on the level of their individual contribution in achieving the overall goals of the Company. The plan provides for a range of bonus amounts according to seniority level. The bonuses paid to the executives consist of a certain multiple of monthly gross compensation.

Compensation received by key management personnel in the aggregate is the following:

	December 31, 2019	December 31, 2018	December 31, 2017
	ThCh$	ThCh$	ThCh$
Cash compensation	2,357,252	2,959,019	2,959,467
Short-term benefits for employees	207,391	497,424	557,122
Other long-term benefits	2,088	322,865	183,453
Total	2,566,731	3,779,308	3,700,042

a) Guarantees established by the Company in favor of key management personnel

No guarantees have been given in favor of key management personnel.

12.5 Compensation plans linked to share price

There are no payment plans granted to the Directors or key management personnel based on the share price of the Company.

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13.  INVENTORIES.

The detail of inventories as of December 31, 2019 and 2018, is as follows:

	As of December 31,
	2019	2018
Classes of Inventories	ThCh$	ThCh$
Supplies for Production	18,352,465	35,786,830
Gas	2,287,934	7,115,226
Oil	3,888,712	2,684,688
Coal	12,175,819	25,986,916
Supplies for projects and spare parts	18,073,825	12,951,779
Electrical materials	3,245,960	8,223,034
Total	39,672,250	56,961,643

There are no inventories pledged as security for liabilities.

For the years ended December 31, 2019, 2018 and 2017, the raw materials and supplies recognized as fuel costs amounted to ThCh$230,944,415, ThCh$231,028,169 and ThCh$280,739,362, respectively. See Note 29.

14.  CURRENT TAX ASSETS AND LIABILITIES.

The detail of current tax assets and liabilities as of December 31, 2019 and 2018, is as follows:

	As of December 31,
	2019	2018
Tax Receivables	ThCh$	ThCh$
Monthly provisional tax payments	38,896,220	52,950,410
Tax credit for absorbed profits	85,708,128	46,343,265
Tax credit for training expenses	2,668,941	470,142
Total	127,273,289	99,763,817

The details of accounts payable associated with current taxes as of December 31, 2019 and 2018 are as follows:

	As of December 31,
	2019	2018
Tax Payables	ThCh$	ThCh$
Income tax	17,995,833	17,677,920
Total	17,995,833	17,677,920

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15.  INVESTMENTS ACCOUNTED FOR USING THE EQUITY METHOD.

15.1. Investments accounted for using the equity method

a. The following tables present the changes in investments in associates and joint ventures accounted for using the equity method as of December 31, 2019 and 2018:

							Share of		Foreign	Other	Balance as
					Balance as of		Profit	Dividends	Currency	Increase	of
Taxpayer ID				Ownership	1-1-2019	Additions	(Loss)	Declared	Translation	(Decrease)	12-31-2019
Number	Associates and Joint Ventures	Country	Currency	Interest	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
76.418.940-K	GNL Chile S.A.	Chile	U.S. dollar	33.33%	3,052,983	—	(254,132)	(1,518,880)	130,235	—	1,410,206
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Chilean peso	50.00%	9,473,711	—	695,437	(4,069,920)	—	—	6,099,228
76.014.570-K	Enel Argentina S.A.	Argentina	Angentine peso	0.08%	300,198	—	104,335	—	(95,726)	93,101	401,908
76.364.085-K	Energía Marina SpA.	Chile	Chilean peso	25.00%	46,639	131,647	(179,551)	—	—	18,511	17,246
				TOTAL	12,873,531	131,647	366,089	(5,588,800)	34,509	111,612	7,928,588

							Share of		Foreign	Other	Other	Balance as
					Balance as of		Profit	Dividends	Currency	Comprehensive	Increase	of
Taxpayer ID				Ownership	1-1-2018	Additions	(Loss)	Declared	Translation	Income	(Decrease)	12-31-2018
Number	Associates and Joint Ventures	Country	Currency	Interest	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
76.418.940-K	GNL Chile S.A.	Chile	U.S. dollar	33.33%	3,783,316	—	805,972	(1,884,140)	347,835	—	—	3,052,983
76.652.400-1	Centrales Hidroeléctricas De Aysén S.A. (*)	Chile	Chilean peso	—	4,205,233	—	1,734,508	—	—	—	(5,939,741)	—
77.017.930-0	Transmisora Eléctrica de Quillota Ltda.	Chile	Chilean peso	0.08%	8,818,759	—	654,952	—	—	—	—	9,473,711
Foreign	Enel Argentina S.A.	Argentina	Argentine peso	0.12%	105,146	—	86,021	—	(108,069)	—	217,100	300,198
76.364.085-K	Energía Marina SpA	Chile	Chilean peso	25.00%	—		(91,213)				137,852	46,639
				TOTAL	16,912,454	—	3,190,240	(1,884,140)	239,766	—	(5,584,789)	12,873,531

(*)See section b) below

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b. Centrales Hidroeléctricas de Aysén S.A. (Hidroaysén)

In May 2014, the Committee of Ministers revoked the Environmental Qualification Resolution (“RCA”) of the Centrales Hidroeléctricas de Aysén S.A. project, in which the Company participated by accepting some of the claims filed against this project. It is a public information that this decision was resorted before the Environmental Courts in Valdivia and Santiago. On January 28, 2015, it was made public that the water rights request made by Centrales Hidroeléctricas de Aysén S.A. has been partially rejected in 2008.

The Company had expressed its intention to promote at Centrales Hidroeléctricas de Aysén S.A. the defense for water rights and the environmental qualification granted to the project in the corresponding instances, continuing with the judicial actions already started or implementing new administrative or judicial actions that are necessary to this end, and it maintained the belief that water resources of the Aysén region are important for the energy development of the country.

Nevertheless, there was uncertainty on the recoverability of the investment made so far at Centrales Hidroeléctricas de Aysén S.A., since it depended both on judicial decisions and on definitions in the energy agenda which could not been foreseen , consequently the investment was not included in the portfolio of the Company’s immediate projects. At closing date of fiscal year 2014, the Company recognized an impairment of its participation in Centrales Hidroeléctricas de Aysén S.A. amounting to ThCh$ 69,066,857.

On December 7, 2017, an extraordinary meeting of shareholders of Centrales Hidroeléctricas de Aysén S.A. was held, in which the early dissolution of the same was agreed and how the liquidation process of the assets of the company will be carried out. The liquidation process contemplated a distribution of assets to its shareholders Enel Generación and Colbún according to their stakes of 51% and 49% respectively. This liquidation process and the corresponding distribution took place on September 7, 2018.

The following was the individual balance sheet considered for the liquidation process:

CENTRALES HIDROELECTRICAS DE AYSEN S.A.	Liquidation Balance	Recognized by Enel Generación (51%)
	09-07-18	09-07-18
ASSETS	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	72,339	36,892
Current accounts receivable from related parties	56,021	28,571
TOTAL CURRENT ASSETS	128,360	65,463
NON-CURRENT ASSETS
Property, plant and equipment	11,603,281	5,917,673
TOTAL NON-CURRENT ASSETS	11,603,281	5,917,673
TOTAL ASSETS	11,731,641	5,983,136
	09-07-18	09-07-18
CURRENT LIABILITIES	ThCh$	ThCh$
Other current provisions	83,403	42,535
TOTAL CURRENT LIABILITIES	83,403	42,535
EQUITY
Issued capital	188,855,665	96,316,389
Retained earnings	(177,207,427)	(90,375,788)
TOTAL EQUITY	11,648,238	5,940,601
TOTAL LIABILITIES AND EQUITY	11,731,641	5,983,136

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15.2. Investments with significant influence

The following tables show financial information as of December 31, 2019 and 2018, from the financial statements of the investments in associates where the Group has significant influence:

	As of December 31, 2019
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A	33.33%	67,419,256	1,615,973,312	161,197,047	1,517,964,903	582,441,735	(583,204,131)	(762,396)	389,843	(372,553)

	As of December 31, 2018
	% Ownership Interest Direct /	Current Assets	Non-current Assets	Current Liabilities	Non-current Liabilities	Revenues	Expenses	Profit (Loss)	Other Comprehensive Income	Comprehensive Income
Investments with Significant Influence	Indirect	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GNL Chile S.A	33.33%	75,571,058	267,884	66,679,077	—	707,597,382	(705,179,062)	2,418,157	1,043,609	3,461,766

None of our associates have published price quotations

15.3. Joint ventures

The following tables present information from the statement of financial position and statement of income as of and for the year ended December 31, 2019 and 2018, on the main joint ventures:

	Centrales Hidroeléctricas		Transmisora Eléctrica
	de Aysén S.A. (*)		de Quillota Ltda.
	(—)%	(—)%	50.0%	50.0%
	12-31-2019	12-31-2018	12-31-2019	12-31-2018
	ThCh$	ThCh$	ThCh$	ThCh$
Total current assets	—	—	3,346,667	9,360,553
Total non-current assets	—	—	10,834,220	11,530,788
Total current liabilities	—	—	365,640	235,264
Total non-current liabilities	—	—	1,616,791	1,708,660
Cash and cash equivalents	—	—	2,403,904	8,185,391
Revenues	—	—	3,191,566	3,003,757
Other fixed operating expenses	—	(125,182)	(768,866)	(758,607)
Depreciation and amortization expense	—	—	(782,800)	(784,364)
Other Income	—	3,526,179	6,087	—
Interest income	—	—	152,370	187,601
Income tax expense	—	—	(407,478)	(349,848)
Profit (loss)	—	3,400,997	1,390,879	1,309,903
Other comprehensive income	—	—	—	—
Comprehensive income	—	3,400,997	1,390,879	1,309,903

(*) See Note 15.1.b.

- There are no significant commitments and contingencies, or restrictions on funds transfers to the owners of associates and joint ventures.

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16.  INTANGIBLE ASSETS OTHER THAN GOODWILL.

The following table presents intangible assets as of December 31, 2019 and 2018:

	As of December 31,
	2019	2018
Intangible Assets, Net	ThCh$	ThCh$
Intangible Assets, Net	132,278,593	115,372,393
Easements and water rights	17,352,892	17,736,954
Concessions	26,156,419	25,953,878
Patents, Registered Trademarks and Other Rights	316,970	7,394
Computer software	76,162,800	60,067,635
Other identifiable intangible assets	12,289,512	11,606,532

	2019	2018
Intangible Assets, Gross	ThCh$	ThCh$
Intangible Assets, Gross	229,944,365	202,377,094
Easements and water rights	22,553,618	22,011,401
Concessions	34,718,676	32,055,825
Patents, Registered Trademarks and Other Rights	771,002	12,484
Computer software	156,836,017	133,931,876
Other identifiable intangible assets	15,065,052	14,365,508

	2019	2018
Intangible Assets, Amortization and Impairment	ThCh$	ThCh$
Accumulated Amortization and Impairment, Total	(97,665,772)	(87,004,701)
Easements and water rights	(5,200,726)	(4,274,447)
Concessions	(8,562,257)	(6,101,947)
Patents, Registered Trademarks and Other Rights	(454,032)	(5,090)
Computer software	(80,673,217)	(73,864,241)
Other identifiable intangible assets	(2,775,540)	(2,758,976)

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The reconciliations of the carrying amounts of intangible assets as of December 31, 2019 and 2018 are as follows:

	Easements	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	Other Identifiable Intangible Assets	Intangibles Assets, Net
Changes in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance January 1, 2019	17,736,954	25,953,878	7,394	60,067,635	11,606,532	115,372,393
Changes in identifiable intangible assets
Increases (decreases) other than from business combinations	—	—	—	25,208,199	—	25,208,199
Increase (decrease) from exchange differences, net	425,373	2,028,583	—	156,906	926,375	3,537,237
Amortization (1)	(809,435)	(1,826,042)	(24,200)	(9,241,732)	(1,598)	(11,903,007)
Increases (decreases) from transfers and other changes	—	—	333,776	(91,776)	(242,000)	—
Increases (decreases) from transfers	—	—	333,776	(91,776)	(242,000)	—
Argentina Hyperinflation Effect	—	—	—	—	203	203
Increase (decrease)	—	—	—	63,568	—	63,568
Total changes in identifiable intangible assets	(384,062)	202,541	309,576	16,095,165	682,980	16,906,200
Closing balance December 31, 2019	17,352,892	26,156,419	316,970	76,162,800	12,289,512	132,278,593

	Easements	Concessions	Patents, Registered Trademarks and Other Rights	Computer Software	OtherIdentifiable Intangible Assets	Intangibles Assets, Net
Changes in Intangible Assets	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance January 1, 2018	12,608,950	—	—	38,254,793	4,307,161	55,170,904
Changes in identifiable intangible assets
Increases (decreases) other than from business combinations	2,721	—	12,484	25,759,609	—	25,774,814
Acquisitions made through business combination	—	30,077,961	—	2,113,933	9,594,267	41,786,161
Increase (decrease) from exchange differences, net	769,421	2,033,761	—	4,111,021	—	6,914,203
Amortization (1)	(347,397)	(4,109,453)	(5,090)	(7,750,745)	(2,723)	(12,215,408)
Increases (decreases) from transfers and other changes	5,213,240	(2,048,391)	—	(866,790)	(2,298,059)	—
Increases (decreases) from transfers	5,213,240	(2,048,391)	—	(866,790)	(2,298,059)	—
Disposals and removal from service	(509,981)	—	—	—	—	(509,981)
Removals from service	(509,981)	—	—	—	—	(509,981)
Argentina Hyperinflation Effect	—	—	—	—	180	180
Increase (decrease)	—	—	—	(1,554,186)	5,706	(1,548,480)
Total changes in identifiable intangible assets	5,128,004	25,953,878	7,394	21,812,842	7,299,371	60,201,489
Closing balance December 31, 2018	17,736,954	25,953,878	7,394	60,067,635	11,606,532	115,372,393

(1) See Note 31.

According to the Group management’s estimates and projections, the expected future cash flows attributable to intangible assets allow the recovery of the carrying amount of these assets recorded as of December 31, 2019 (see Note 3.e).

17.  GOODWILL.

The following table shows goodwill by the Cash-Generating Unit or group of Cash-Generating Units to which it belongs and changes as of December 31, 2019 and 2018:

		Opening Balance 01-01-2018	Business combinations	Foreign Currency Translation	Closing Balance 12/31/2018	Transfer Fusion by absortion	Foreign currency exchange difference	Closing Balance 12-31-2019
Company	Cash Generating Unit	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Empresa Eléctrica de Colina Ltda.	Empresa Eléctrica de Colina Ltda.	2,240,478	—	—	2,240,478	—	—	2,240,478
Enel Distribución Chile S.A.	Enel Distribución Chile	128,374,362	—	—	128,374,362	—	—	128,374,362
Enel Generación Chile S.A.	Enel Generación Chile	731,782,459	—	—	731,782,459	24,860,356	—	756,642,815
GasAtacama Chile S.A.	Enel Generación Chile	24,860,356	—	—	24,860,356	(24,860,356)	—	—
Empresa Eléctrica Panguipulli S.A.	Enel Green Power Chile Ltda.	—	17,543,347	2,603,476	20,146,823	—	1,673,580	21,820,403
Geotérmica del Norte	Enel Green Power Chile Ltda.	—	65,871	9,775	75,646	—	6,284	81,930
Parque Eólico Talinay Oriente	Enel Green Power Chile Ltda.	—	6,587,064	977,537	7,564,601	—	628,385	8,192,986
	Total	887,257,655	24,196,282	3,590,788	915,044,725	—	2,308,249	917,352,974

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According to the Group management’s estimates and projections, the expected future cash flows projections attributable to the Cash-Generating Units or groups of Cash-Generating Units, to which the acquired goodwill has been allocated, allow recovery of its carrying amount as of December 31, 2019 (see Note 3.e).

The origin of the goodwill is detailed below:

1.- Empresa Eléctrica de Colina Ltda.

On December 31, 1996, Enel Distribución Chile S.A. acquired 100% of Empresa Eléctrica de Colina Ltda. from the investment company Saint Thomas S.A., which is neither directly nor indirectly related to Enel Distribución Chile S.A.

2.- Enel Distribución Chile S.A.

In November 2000, Enersis S.A. (now Enel Américas S.A.) acquired an additional 25.4% ownership interest in Enel Distribución Chile S.A. in a public bidding process, reaching a 99.99% ownership interest in the company.

3.- Enel Generación Chile S.A.

On May 11, 1999, Enersis S.A. (now Enel Américas S.A.) acquired an additional 35% in Enel Generación Chile S.A. in a public bidding process on the Santiago Stock Exchange and by buying shares in the U.S. (30% and 5%, respectively), reaching a 60% ownership interest in the generation company.

4.- GasAtacama Chile S.A. (Formerly named Inversiones GasAtacama Holding Limitada)

On April 22, 2014, Enel Generación Chile S.A. acquired the remaining 50% equity interest in GasAtacama Chile S.A that was owned at that time by Southern Cross Latin America Private Equity Fund III L.P.

5.- Empresa Eléctrica Pangue S.A. (Currently named GasAtacama Chile S.A.)

On July 12, 2002, Enel Generación Chile S.A. acquired 2.51% of the shares of Empresa Eléctrica Pangue S.A. through a put option held by the minority shareholder International Finance Corporation (IFC).

On May 2, 2012, Empresa Eléctrica Pangue S.A. merged with Compañía Eléctrica San Isidro S.A., with the latter company being the surviving entity.

6.- Compañía Eléctrica San Isidro S.A. (Currently named GasAtacama Chile S.A.)

On August 11, 2005, Enel Generación Chile S.A. acquired the shares of Inversiones Lo Venecia Ltda., whose only asset was a 25% interest in Compañía Eléctrica San Isidro S.A. (acquisition of non-controlling interests).

On September 1, 2013, Compañía Eléctrica San Isidro S.A. was merged with Endesa Eco S.A., the latter being the surviving entity.

On November 1, 2013, Endesa Eco S.A. was merged with Compañía Eléctrica Tarapacá, the latter being the surviving entity. 

On November 1, 2016, Compañía Eléctrica Tarapacá S.A. was merged with GasAtacama Chile S.A. with the latter being the surviving company.

7.- Enel Green Power Chile Ltda.

On March 26, 2013, Enel Green Power Chile Ltda. acquired an ownership interest in Parque Eólico Talinay Oriente S.A..On August 6, 2001, Enel Green Power Chile Ltda. acquired an ownership interest in Empresa Eléctrica

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Panguipulli S.A. and Empresa Eléctrica Puyehue S.A., which later merged with Panguipulli, with the latter being the legal surviving company.

18.  PROPERTY, PLANT AND EQUIPMENT.

The following table shows property, plant and equipment as of December 31, 2019 and 2018:

	As of December 31,
	2019	2018
Classes of Property, Plant and Equipment, Net	ThCh$	ThCh$
Property, Plant and Equipment, Net	5,360,319,624	5,308,647,633
Construction in progress	1,048,988,931	862,274,093
Land	77,754,923	74,753,283
Buildings	420,319,759	384,027,047
Plant and equipment	2,895,992,861	3,143,869,929
Network infrastructure	809,428,974	764,095,247
Fixtures and fittings	47,758,908	55,091,617
Other property, plant and equipment under lease	4,231,758	6,881,745
Right-of-use assets	55,843,510	17,654,672

	As of December 31,
	2019	2018
Classes of Property, Plant and Equipment, Gross	ThCh$	ThCh$
Property, Plant and Equipment, Gross	9,296,027,122	8,747,182,818
Construction in progress	1,048,988,931	862,274,093
Land	77,754,923	74,753,283
Buildings	531,250,194	470,833,768
Plant and equipment	6,002,160,751	5,824,130,347
Network infrastructure	1,396,996,724	1,318,208,218
Fixtures and fittings	150,242,089	151,363,603
Other property, plant and equipment under lease	18,259,978	16,859,475
Right-of-use assets	70,373,532	28,760,031

	As of December 31,
	2019	2018
Classes of Accumulated Depreciation and Impairment in Property, Plant and Equipment	ThCh$	ThCh$
Total Accumulated Depreciation and Impairment in Property, Plant and Equipment	(3,935,707,498)	(3,438,535,185)
Buildings	( 110,930,435 )	(86,806,721)
Plant and equipment	( 3,106,167,890 )	(2,680,260,418)
Network infrastructure	( 587,567,750 )	(554,112,971)
Fixtures and fittings	( 102,483,181 )	(96,271,986)
Other property, plant and equipment under lease	( 14,028,220 )	(9,977,730)
Right-of-use assets	( 14,530,022 )	( 11,105,359 )

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The detail and changes in property, plant, and equipment at December 31, 2019 and 2018, are as follows:

	Construction in progress	Land	Buildings	Generation Plant and Equipment	Network infrastructure	Fixtures and Fittings	Other Property, Plant and Equipment under Financial Lease	Right of use Assets	Property, Plant and Equipment, Net
Changes in 2019	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance January 1, 2019	862,274,093	74,753,283	384,027,047	3,143,869,929	764,095,247	55,091,617	6,881,745	17,654,672	5,308,647,633
Changes:		-	-	-					-
Effects first application IFRS 16	-	-	-	-	-	-	-	28,814,142	28,814,142
Increases other than from business combinations	320,298,423	-	-	-	-	-	-	-	320,298,423
Increases (decreases) from foreign currency translation differences	9,880,815	36,282	29,731,649	81,221,513	4,238,408	65,341	361,574	1,537,867	127,073,449
Depreciation (1)	-	-	( 17,944,173 )	( 159,163,293 )	( 34,964,877 )	( 6,299,395 )	( 3,011,561 )	( 3,321,268 )	( 224,704,567 )
Impairment losses recognized in profit or loss for the period (2)	( 32,967,462 )	-	-	( 247,052,801 )	-	-	-	-	( 280,020,263 )
Increases (decreases) from transfers and other changes	(121,288,336)	4,151,834	22,879,420	17,534,668	74,941,622	1,780,792	-	-	-
Increases (decreases) for transfers	(121,288,336)	4,151,834	22,879,420	17,534,668	74,941,622	1,780,792	-	-	-
Disposals and removals from service	—	( 406,656 )	(792,638)	(948,350)	(1,880,608)	(837,345)	-		( 4,865,597 )
Disposals	—	( 406,656 )	—	(948,350)	—	—	-	-	( 1,355,006 )
Removals from service	—	-	(792,638)	—	(1,880,608)	(837,345)	-	-	( 3,510,591 )
Other increases (decreases) (3)	10,843,933	( 779,820 )	2,418,454	59,398,742	2,999,182	(2,042,102)	-	11,158,097	83,996,486
Argentina Hyperinflationary Effect	(52,535)	-	—	1,132,453	—	—	-	-	1,079,918
Total changes	186,714,838	3,001,640	36,292,712	(247,877,068)	45,333,727	(7,332,709)	(2,649,987)	38,188,838	51,671,991
Closing balance December 31, 2019	1,048,988,931	77,754,923	420,319,759	2,895,992,861	809,428,974	47,758,908	4,231,758	55,843,510	5,360,319,624

	Construction in progress	Land	Buildings	Generation Plant and Equipment	Network infrastructure	Fixtures and Fittings	Other Property, Plant and Equipment under Financial Lease	Finance Lease Asset	Property, Plant and Equipment, Net
Changes in 2018	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Opening balance January 1, 2018	666,590,543	67,485,380	12,793,641	2,080,903,064	683,120,815	56,284,762	—	18,508,932	3,585,687,137
Changes:
Increases other than from business combinations	321,183,398	5,893,739	1,000,411	1,638,436	2,455	935,982	143,120	—	330,797,541
Acquisitions through business combinations	44,088,988	623,052	329,152,208	941,871,560	47,727,579	2,018,760	6,904,334	368,008	1,372,754,489
Increases (decreases) from exchange differences, net	14,849,366	50,004	46,040,633	128,411,179	6,928,376	338,619	982,330	22,471	197,622,978
Depreciation (1)	—	—	(13,795,237)	(149,247,118)	(32,011,964)	(4,935,435)	(2,105,472)	(857,075)	(202,952,301)
Increases (decreases) from transfers and other changes	(193,895,804)	—	12,450,092	146,447,942	32,105,004	2,692,671	222,027	(21,932)	—
Increases (decreases) for transfers	(193,895,804)	—	12,450,092	146,447,942	32,105,004	2,692,671	222,027	(21,932)	—
Disposals and removals from service	—	(5,411)	—	(90,513)	(1,132,103)	(1)	-	—	(1,228,028)
Disposals	—	—	—	(90,513)	(436,956)	—	-	—	(527,469)
Removals from service	—	(5,411)	—	—	(695,147)	(1)	-	—	(700,559)
Other increases (decreases)	9,457,602	706,519	(3,614,701)	(7,977,450)	27,355,085	(2,243,741)	735,406	(365,732)	24,052,988
Argentina Hyperinflationary Effect	—	—	—	1,912,829	—	—	-	—	1,912,829
Total changes	195,683,550	7,267,903	371,233,406	1,062,966,865	80,974,432	(1,193,145)	6,881,745	(854,260)	1,722,960,496
Closing balance December 31, 2018	862,274,093	74,753,283	384,027,047	3,143,869,929	764,095,247	55,091,617	6,881,745	17,654,672	5,308,647,633

(1) See Note 31.

(2) See paragraph x) in section e) Other information, of this Note.

(3) See Note 25.

Additional information on property, plant and equipment, net

a)    Main investments

Major additions to property, plant and equipment are investments in operating plants and new projects amounting to ThCh$320,298,296  for the year ended December 31, 2019 (ThCh$330,797,541for the year ended December 31, 2018). In the generation business the advances in the new capacity program are included such as the advances in the construction of the Los Cóndores hydroelectric plant, which will use the resources of the Maule Lagoon and will have an installed capacity of approximately 150 MW. Additions related to this project amounted ThCh$91,638,411 for the year ended December 31, 2019 (ThCh$142,578,993 for the year ended December 31, 2018) while in the distribution business, the main investments are extensions and investments in networks to optimize their operation, in order to improve the efficiency and quality of service level, for ThCh$92,392,704 for the year ended December 31, 2019 (ThCh$84,727,900 for the year ended December 31, 2018). In the case of Enel Green Power Chile, the main projects correspond to Cerro Pabellón and Campos de Sol, with investments of ThCh$33,134,694 and ThCh$ 27,506,626 for the year ended December 31, 2019, respectively (ThCh$2,360,416 and ThCh$2,227,380 for the year ended December 31, 2018, respectively), both belonging to the subsidiaries Geotérmica del Norte S.A. and Enel Green Power del Sur SpA.

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b)    Capitalized expenses

b.1) Borrowing costs

Capitalized borrowing costs were ThCh$9,321,354, ThCh$6,435,646 and ThCh$4,078,463 for the years ended December 31, 2019, 2018 and 2017, respectively (see Note 34). The weighted-average borrowing rate was in the range of 8% and 7.71% for the year ended December 31, 2019 (7.71% and 7.12% for the year ended December 31, 2018).

b.2) Employee expenses capitalized

Employee expenses capitalized that are directly attributable to constructions in progress were ThCh$17,610,861, ThCh$16,710,963 and ThCh$14,388,987 during the years ended December 31, 2019, 2018 and 2017, respectively.

c) Right to use assets

The detail of the right-of-use assets as of December 31, 2019 corresponds to the following:

	Land	Other Plants and Equipments	Right-of-use assets, Net
Changes in 2019	ThCh$	ThCh$	ThCh$
Opening balance January 1, 2019	2,758	17,651,914	17,654,672
Effects first time adoption IFRS 16	23,097,767	5,716,375	28,814,142
Opening balance January 1, 2019	23,100,525	23,368,289	46,468,814
Increases (decreases) from foreign currency translation differences, net	1,537,867	-	1,537,867
Depreciation	( 1,482,706 )	( 1,838,562 )	( 3,321,268 )
New agreements (decreases)	10,926,113	231,984	11,158,097
Total changes	10,981,274	( 1,606,578 )	9,374,696
Closing balance December 31, 2019	34,081,799	21,761,711	55,843,510

As of December 31, 2019 and 2018, the main right-of-use assets and lease liabilities relate to the following:

-A contract for Electric Transmission Lines and Installations (Ralco-Charrúa 2X220 KV), made between Enel Generación Chile S.A. and Transelec S.A . The lease agreement has a 20‑year term and bears interest at an annual rate of 6.5%. This contract qualified as a financial liability as of December 31, 2018 and December 31, 2019, due to the application of IAS 17 and IFRS 16, respectively.

- Additionally, as a result of the application of IFRS 16 (see Notes 2.2.a.i and 3.f) the Group recognized as of January 1, 2019 right-of-use assets related to property, plant and equipment for an amount of ThCh$28,814,142

The present value of future payments derived from such contracts is as follows:

	As of December 31,
	2019			2018
	Gross	Interest	Present Value	Gross	Interest	Present Value
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Less than one year	7,602,720	1,760,705	5,842,015	2,779,080	612,805	2,166,275
From one to two years	6,234,867	1,719,045	4,515,822	2,779,080	471,998	2,307,082
From two to three years	6,049,847	1,484,321	4,565,526	2,779,080	322,037	2,457,043
From three to four years	8,326,858	1,265,224	7,061,634	7,726,436	180,386	7,546,050
From four to five years	2,964,375	1,180,435	1,783,940	—	—	—
More than five years	38,630,310	8,991,558	29,638,752	—	—	—
Total	69,808,977	16,401,288	53,407,689	16,063,676	1,587,226	14,476,450

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d)    Short term lease and variable payments on lease

The consolidated statement of comprehensive income for the year ended December 31, 2019 includes expenses of ThCh$3,824,195, corresponding to payments for short-term leases in the amount of ThCh$1,995,392 and ThCh$1,828,803 related to variable payments on leases, which are exempted from the application of IFRS 16 (see Notes 2.2.ai and 3.f). As of December 31, 2018, the amount recognized in results was ThCh$ 3,775,007, coming from leases of assets classified as operating leases, according to IAS 17.

As of December 31, 2019, the future payments derived from such contracts are as follows:

	As of December 31,
	2019
	ThCh$
Less than one year	3,485,151
From one to two years	—
From two to three years	—
From three to four years	—
From four to five years	—
More than five years	—
Total	3,485,151

e)    Other information

(i) As of December 31, 2019 and 2018, the Group had contractual commitments for the acquisition of property, plant and equipment amounting to ThCh$185,457,682 and ThCh$269,176,169, respectively.

(ii) As of December 31, 2019 and 2018, the Group does not have property, plant and equipment pledged as security for liabilities.

(iii) The Group and its consolidated entities have insurance policies for all risks, earthquake and machinery breakdown and damages for business interruption with a €1,000 million (ThCh$844,140,650),  including business interruption coverage. Additionally, the Group has Civil Liability insurance to meet claims from third parties with a €500 million (ThCh$422,070,325) limit when the demands are a product of the breakdown of any of the dams owned by the Company or its subsidiaries and environmental damages amounting to €20 million (ThCh$16,882,813). The insurance premiums associated with these policies are presented proportionally for each company in the caption “Prepaid expenses”.

(iv) The condition of certain assets of our subsidiary Enel Generación Chile S.A. changed, primarily works and infrastructure for facilities built to support power generation in the SIC grid in 1998, due primarily to the installation in the SIC of new thermoelectric plants, the arrival of LNG, and new other projects. As such, a new supply configuration for the upcoming years, in which it is expected that these facilities will not be used. Therefore, in 2009, Enel Generación Chile S.A. recognized an impairment loss of ThCh$43,999,600 for these assets, which is still has not reversed.

(v) At the end of 2014, the Group recognized an impairment loss of ThCh$12,581,947 related to the Punta Alcalde project. This impairment loss was triggered because the current definition of the project is not fully aligned with the strategy that the Company is reformulating; particularly, with regard to technological leadership, and to community and environmental sustainability. The Company has decided to suspend the project as its profitability is still unclear (see Note 3.e).

(vi) As of December 31, 2015, Enel Generación Chile S.A. recognized an impairment loss of ThCh$2,522,445 related to the Waiwen wind project. This loss was a result of new assessment of the feasibility of the project performed by the Company and a conclusion that, under existing conditions to date, its profitability is uncertain.

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(vii) In line with its sustainability strategy and in order to develop community relationships, Enel Generación Chile S.A. has decided to research new design alternatives for the Neltume project, in particular regarding the issue of the discharge of Lake Neltume, which has been raised by the communities in the various instances of dialogue.

To start a new phase of research of an alternative project, which includes the discharge of water on the Fuy River in late December 2015, the Company withdrew the Environmental Impact Study. This decision applies only to the portion of the Neltume project related to the power plant and not to portion related to the transmission project, which continues its course on handling in the Environmental Assessment Service.

As a result of the above, as of December 31, 2015, Enel Generación Chile S.A. recognized a loss of ThCh$2,706,830, associated with the write down of certain assets related to Environmental Impact Study, which has been withdrawn and to other studies directly linked to the old design of assets.

Consequently, in line with the new sustainability strategy and as a result of sustained dialog with the communities, Enel Generación Chile’s projects in the territory, namely Neltume and Choshuenco, have good prospects from a social community point of view. Nonetheless, given the current condition of the Chilean electricity market, expected profitability of the Neltume and Choshuenco projects is lower than the total capitalized investment in them. As a result, at the end of 2016, Enel Generación Chile recognized an impairment loss of ThCh$20,459,461 associated with the Neltume project and ThCh$3,748,124 associated with the Choshuenco project.

At the end of 2017, after a deep analysis during the last months, Enel Generación Chile determined to abandon the Neltume project; a decision justified mainly by the high-sustained competitiveness in the Chilean electricity market, which was ratified in November 2017 with the result of the last tender of Electric Distributors. Added to the above, there is the time associated with developing the alternative water discharge, considering a period of no less than 5 years, given the necessity to request and obtain a transfer of the current water right and commission a new Envorimental Impact Study. The abandonment implied the recognition of a ThCh$21,975,641 loss, with the purpose of reducing to zero the net book value of the assets associated with the project.

Additionally, the Company also decided to abandon the Choshuenco project, mainly because the strong synergies considered with the Neltume hydroelectric project would not exist anymore and make it not viable. This decision involved recognizing a loss of ThCh$3,130,270, with the purpose of reducing the net book value of the assets associated with the project to zero.

(viii) On August 31, 2016, Enel Generación Chile S.A. decided to withdraw from the water rights associated with the Bardón, Chillan 1, Chillan 2, Futaleufú, Hechún and Puelo hydroelectric projects. This decision was made because of, among other evaluation aspects, the high annual maintenance cost of these unused water rights, lack of technical and economic feasibility and insufficient local communities support. As a result, the Group wrote off a total amount of ThCh$ 32,834,160 of property, plant and equipment and ThCh$ 2,549,926 of intangible assets, which represent 100% of the related costs previously capitalized.

(ix) As of December 31, 2016, Enel Generación Chile S.A. recognized an impairment loss of ThCh$ 6,577,946 associated with certain Non-Conventional Renewable Energy (“NCRE”) initiatives, such as wind, mini-hydro, biomass and solar projects. These initiatives deal with collection of natural resources data (wind speed, solar radiation, etc.) as well as engineering studies enabling the Company to perform and support technical and economical assessments in order to visualize their perspectives and decide on future steps. The results of the studies have not been entirely satisfactory, mainly due to the current conditions in the Chilean electricity market, as future viability of the NCRE projects is uncertain. As a result, Enel Generación Chile recognized an impairment loss for 100% of the capitalized investments to date in NCRE projects.

On the other hand, Enel Generación Chile decided to write off 100% of capitalized investment in the Tames and Totoralillo thermal projects that until now were held in its portfolio. These projects were being developed within the framework of the public land concessions offered by the National Heritage Ministry in 2013. The amount of the write-off was ThCh$ 1,096,137 and arose as a result of the current conditions in the Chilean electricity market, lack of future viability of this type of technology (steam-coal) and high development costs, which make these projects unfeasible. In addition, Enel Generación Chile recognized a provision of ThCh$2,244,900 for the fines

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to be paid upon withdrawing from the concessions related to these projects. During fiscal year 2017, the Ministry of National Assets and Enel Generación Chile resolved to extinguish the concessions by mutual agreement, and fines were not applied.

(x) On June 4, 2019, our subsidiaries Enel Generación Chile and GasAtacama Chile signed an agreement whereby both companies, in line with their own sustainability strategy and strategic plan, and the Ministry of Energy, regulated how to proceed with respect to the progressive closures of the Tarapacá, Bocamina I and Bocamina II coal generating units (hereinafter, Tarapacá, Bocamina I and Bocamina II). 

The agreement is subject to the condition precedent that the regulation of power transfers between generating companies enters into full effect, which establishes, among other items, the essential conditions that ensure a non-discriminatory treatment between the different generators and define the Strategic Reserve State. Therefore, Enel Generación and GasAtacama Chile would be formally and irrevocably bound to the final closures of Bocamina I and Tarapacá, respectively, from the National Electric System, establishing deadlines of May 31, 2020 for the Tarapacá plant, and on December 31, 2023 for the Bocamina I plant.

The Group’s intention is to accelerate the closures of Tarapacá and Bocamina I in full coordination with the Authority. In this context, on June 17, 2019, GasatAcama Chile requested of the CNE that the final retirement, disconnection and cessation of operations of Tarapacá be carried out in advance, as of December 31, 2019. On July 26, 2019, by issuance of Exempt Resolution No. 450 and in accordance with the provisions of article 72 ° -18 of the General Law of Electric Services, the CNE authorized the final retirement, disconnection and cessation of operation of the Tarapacá coal generating unit as of December 31, 2019.

As a result of the foregoing, the Group has recorded an impairment loss of ThCh$197,188,542 and ThCh $82,831,721 to adjust the carrying amount of the capitalized investment in Tarapacá and Bocamina 1, respectively, to their recoverable value.

In relation to Bocamina II, Enel Generación Chile set its goal for early retirement as  no later than December 31, 2040. All of the above is subject to the authorization established in the General Law of Electric Services. The financial effects will depend on factors that influence the behavior of the electricity market, such as, among others, the price of fuels, hydrological conditions; the growth of electricity demand and international inflation rates, which to date are not possible to determine.

Notwithstanding the foregoing, the useful lives of Bocamina II assets have been adjusted, so that in no case will the depreciation be recorded for a date  beyond December 31, 2040. This measure implied recognizing a larger amount of depreciation at December 31 2019 of ThCh$ 4,083,855.

(xi) On a result of the public disorders that have affected Chile since October 18, 2019, fixed assets were written off for a total of ThCh$1,629,983 as of December 31, 2019. There are insurance policies, which are in the process of investigation  with respect to  the settlement of the incident. On the other hand, equipment retirement were made which corresponds to ThCh$1,880,608. Together, the amounts  total ThCh$3,510,591; (see Note 32).

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19.  INVESTMENT PROPERTY.

The detail and changes in investment property during the years ended December 31, 2019 and 2018, are as follows:

	Investment Properties,Gross	Accumulated Depreciation, Amortization and Impairment	Investment Properties, Net
Investment Properties	ThCh$	ThCh$	ThCh$
Balance at January 1, 2018	9,189,377	(832,605)	8,356,772
Depreciation expense	—	(19,591)	(19,591)
Other increases (decreases)	—	(779,825)	(779,825)
Balance at December 31, 2018	9,189,377	(1,632,021)	7,557,356
Depreciation expense	—	(19,812)	(19,812)
Impairment (*)	—	(742,389)	(742,389)
Balance at December 31, 2019	9,189,377	(2,394,222)	6,795,155

(*) See Note 31.

There were no investment properties disposed of during the periods ended December 31, 2019 and 2018.

Fair value measurement and hierarchy

As of December 31, 2019, the fair value of the Group’s investment properties was ThCh$7,880,432 ( ThCh$8,228,673 as of December 31, 2018) which was determined using independent appraisals.

The fair value measurement for these investment properties was categorized as Level 3 within the fair value hierarchy.

The following is the fair value hierarchy of investment properties:

	Fair value measured at the end of the reporting period using:
	Level 1	Level 2	Level 3
	ThCh$	ThCh$	ThCh$
Investment properties	—	—	7,880,432

See Note 3.h.

For the years ended December 31, 2019, 2018 and 2017, the detail of income and expenses from investment properties is as follows:

	For the years ended December 31,
	2019	2018	2017
Income and expense from investment properties	ThCh$	ThCh$	ThCh$
Rental income from investment properties	202,896	204,166	192,719
Direct operating expense from investment properties generating   rental income	(44,136)	(56,327)	(78,367)
Total	158,760	147,839	114,352

The Group has no repair, maintenance, acquisition, construction or development agreements that represent future obligations for the Group as of December 31, 2019.

The Group has insurance policies to cover operational risks of its investment properties, as well as to cover legal claims against the Group that could potentially arise from exercising its business activity. Management considers that the insurance policy coverage is sufficient against the risks involved.

F-80

20.  INCOME TAX AND DEFERRED TAXES.

a)    Income taxes

The following table presents the components of the income tax expense / (benefit) for the years ended December 31, 2019, 2018 and 2017:

	For the years ended December 31,
	2019	2018	2017
Current Income Tax and Adjustments to Current Income Tax for Previous Periods	ThCh$	ThCh$	ThCh$
Current income tax	(54,904,679)	(47,354,780)	(162,820,181)
Adjustments to current tax from the previous period	(2,251,167)	(6,304,285)	(1,127,646)
Other current tax benefit / (expense)	(37,369,930)	(61,507,252)	15,934,106
Current tax expense, net	(94,525,776)	(115,166,317)	(148,013,721)
Benefit / (expense) from deferred taxes for origination and reversal of temporary differences	33,297,872	(43,134,500)	4,671,420
Adjustments to deferred taxes from the previous period	—	4,818,298	—
Total deferred tax benefit / (expense)	33,297,872	(38,316,202)	4,671,420
Income tax expense	(61,227,904)	(153,482,519)	(143,342,301)

The following table reconciles income taxes resulting from applying the local current tax rate to “Net income before taxes” and the actual income tax expense recorded in the accompanying Consolidated Statement of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017:

		12-31-2019		12-31-2018		12-31-2017
Reconciliation of Tax Expense	Rate	ThCh$	Rate	ThCh$	Rate	ThCh$
ACCOUNTING INCOME BEFORE TAX		377,321,122		566,330,276		666,760,212
Total tax income (expense) using statutory rate	(27.00%)	(101,876,703)	(27.00%)	(152,909,175)	(25.50%)	(170,023,854)
Tax effect of rates applied in other countries	0.06%	232,897	—	—	0.05%	328,968
Tax effect of non-taxable operations	11.30%	42,638,986	0.31%	1,746,052	5.67%	37,774,743
Tax effect of non-tax-deductible expenses	(2.76%)	(10,399,776)	(2.26%)	(12,786,965)	(3.11%)	(20,737,858)
Tax effect of adjustments to taxes in previous periods	(0.60%)	(2,251,167)	(1.11%)	(6,304,285)	(0.17%)	(1,127,646)
Adjustments for prior periods deferred taxes	—	—	0.85%	4,818,298	—	—
Price level restatement for tax purposes (investments and equity)	2.76%	10,427,859	2.11%	11,953,556	1.57%	10,443,346
Total adjustments to tax expense using statutory rate	10.77%	40,648,799	(0.10)%	(573,344)	4.00%	26,681,553
Income tax benefit (expense)	(16.23%)	(61,227,904)	(27.10%)	(153,482,519)	(21.50%)	(143,342,301)

F-81

b)    Deferred taxes

The origination and changes in deferred tax assets and liabilities as of December 31, 2019 and 2018, are as follows:

	December 31, 2019		December 31, 2018
	Assets	Liabilities	Assets	Liabilities
Deferred Tax Assets (Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$
Accumulated depreciation	10,652,313	(404,453,928)	9,636,857	(359,613,258)
Post-employment benefit obligations	7,772,646	(34,413)	6,131,110	(421,462)
Revaluations of financial instruments	456,888	—	—	—
Tax loss	81,154,636	—	36,921,157	—
Provisions	87,275,541	—	55,080,385	—
Dismantling Provision	44,485,711	—	23,627,264	—
Provision for Civil Contingencies	3,502,161	—	4,108,710	—
Provision Contingencies Workers	492,522	—	430,900	—
Provision for doubtful trade accounts	14,555,712	—	13,253,612	—
Provision of Human Resources accounts	7,859,341	—	7,432,939	—
Other Provisions	16,380,094	—	6,226,960	—
Other Deferred Taxes	20,980,774	(31,240,859)	14,277,897	(20,921,510)
Capitalization of financial expenses	—	(11,412,737)	—	(11,202,063)
Argentina Hyperinflationary Effect	—	(657,871)	—	(425,687)
Other Deferred Taxes	20,980,774	(19,170,251)	14,277,897	(9,293,760)
Deferred Tax Assets/Liabilities before compensation	208,292,798	(435,729,200)	122,047,406	(380,956,230)
Compensation of Assets (Liabilities) for deferred taxes	(186,444,559)	186,444,559	(102,876,176)	102,876,176
Deferred Tax Assets (Liabilities) after compensation	21,848,239	(249,284,641)	19,171,230	(278,080,054)

		Changes 2019
	Opening balance January 1, 2019	Increase (decrease) in profit or loss	Increase (decrease) in other comprehensive income	Foreign Currency Translation	Other increases (decreases)	Closing balance December 31, 2019
Deferred Tax Assets (Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Accumulated depreciation	(349,976,401)	(5,668,543)	—	(1,561,204)	(36,595,467)	(393,801,615)
Post-employment benefit obligations	5,709,648	126,352	2,099,845	—	(197,612)	7,738,233
Revaluations of financial instruments	—	—	710,523	—	(253,635)	456,888
Tax loss	36,921,157	14,343,314	—	2,096,339	27,793,826	81,154,636
Provisions	55,080,385	24,123,136	—	795,123	7,276,897	87,275,541
Dismantling Provision	23,627,264	20,711,621	—	34,574	112,252	44,485,711
Provision for Civil Contingencies	4,108,710	(606,549)	—	—	—	3,502,161
Provision Contingencies Workers	430,900	61,622	—	—	—	492,522
Provision for doubtful trade accounts	13,253,612	1,302,403	—	128	(431)	14,555,712
Provision of Human Resources accounts	7,432,939	3,233,471	—	(13,109)	(2,793,960)	7,859,341
Other Provisions	6,226,960	(579,432)	—	773,530	9,959,036	16,380,094
Other Deferred Taxes	(6,643,613)	373,614	992	—	(3,991,078)	(10,260,085)
Capitalization of financial expenses	(11,202,063)	(407,318)		—	196,643	(11,412,738)
Argentina Hyperinflation Effect	(425,687)	(207,916)		—	(24,268)	(657,871)
Other Deferred Taxes	4,984,137	988,848	992	—	(4,163,453)	1,810,524
Deferred Tax Assets (Liabilities)	(258,908,824)	33,297,873	2,811,360	1,330,258	(5,967,069)	(227,436,402)

				Changes 2018
	Opening balance January 1, 2018	Effects first application IFRS 9 and IAS 29	Net balance restated as of January 1, 2018	Increase (decrease) in profit or loss	Increase (decrease) in other comprehensive income	Acquisitions Through Business Combinations	Foreign currency translation	Other increases (decreases)	Closing balance December 31, 2018
Deferred Tax Assets (Liabilities)	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Accumulated depreciation	(263,685,283)	—	(263,685,283)	(3,851,978)	—	(74,336,810)	(10,342,994)	2,240,664	(349,976,401)
Post-employment benefit obligations	5,971,995	—	5,971,995	(250,223)	(10,228)	—	—	(1,896)	5,709,648
Tax loss carryforwards	9,536,102	—	9,536,102	(3,278,563)		32,058,724	2,831,404	(4,226,510)	36,921,157
Provisions	39,890,472	1,261,836	41,152,308	4,032,271	—	5,183,782	973,961	3,738,063	55,080,385
Dismantling Provision	17,411,395	—	17,411,395	4,442,928	—	1,707,519	59,520	5,902	23,627,264
Provision for Civil Contingencies	3,762,772	—	3,762,772	306,893	—	—	39,045	—	4,108,710
Provision Contingencies Workers	5,989	—	5,989	333,704	—	8,016	83,191	—	430,900
Provision for doubtful trade accounts	11,976,401	1,261,836	13,238,237	13,646	—	3,434	989	(2,694)	13,253,612
Provision of Human Resources accounts	6,497,206	—	6,497,206	178,162	—	70,795	686,776	—	7,432,939
Other Provisions	236,709		236,709	(1,243,062)	—	3,394,018	104,440	3,734,855	6,226,960
Other Deferred Taxes	38,900,825	(213,442)	38,687,383	(34,967,709)	111	—	—	(10,363,398)	(6,643,613)
Capitalization of financial expenses	(4,780,923)	—	(4,780,923)	(6,421,139)	—	—	—	(1)	(11,202,063)
Recoverable taxes	10,491,314	—	10,491,314	—	—	—	—	(10,491,314)	—
Investments accounted for using the equity method - Hidroaysen	30,938,736	—	30,938,736	(30,938,736)	—	—	—	—	—
Argentina Hyperinflation Effect	—	(213,442)	(213,442)	(212,245)	—	—	—	—	(425,687)
Other Deferred Taxes	2,251,698	—	2,251,698	2,604,411	111	—	—	127,917	4,984,137
Deferred Tax Assets (Liabilities)	(169,385,889)	1,048,394	(168,337,495)	(38,316,202)	(10,117)	(37,094,304)	(6,537,629)	(8,613,077)	(258,908,824)

F-82

Recovery of deferred tax assets will depend on whether sufficient tax profits will be obtained in the future. The Group believes that the future profit projections for its subsidiaries will allow these assets to be recovered.

As of December 31, 2019, the Group has not recognized deferred tax assets related to tax losses in the amount of ThCh$4,625,940 (ThCh$3,930,370 as of December 31, 2018) (see Note 3.p).

The Group has not recognized deferred tax liabilities for taxable temporary differences associated with investments in subsidiaries and joint ventures, as it is able to control the timing of the reversal of the temporary differences and considers that it is probable that such temporary differences will not reverse in the foreseeable future. As of December 31, 2019 and 2018, the aggregate of taxable temporary differences associated with investments in subsidiaries and joint ventures for which deferred tax liabilities have not been recognized totaled ThCh$1,323,714,721  and ThCh$896,532,229, respectively. Additionally, the Group has not recognized deferred tax assets for deductible temporary differences which as of December 31, 2019 and 2018, totaled ThCh$691,241,687 and ThCh$744,768,294, respectively, as it is not probable that sufficient future taxable profits exist to recover such temporary differences.

The Group entities are potentially subject to income tax audits by the Chilean tax regulator and are limited to three tax years after which tax audits over those years can no longer be performed. Tax audits by nature are often complex and can require several years to complete. The tax years potentially subject to examination are 2016 through 2018.

Given the range of possible interpretations of tax standards, the results of any future inspections carried out by Chilean tax authority for the years subject to audit can give rise to tax liabilities that cannot currently be quantified objectively. Nevertheless, management estimates that the liabilities, if any, that may arise from such tax audits, would not significantly impact the Group’s future results.

The effects of deferred tax on the components of other comprehensive income for the years ended December 31, 2019 and 2018, are as follows:

	For the years ended December 31,
	2019			2018			2017
Effects of Deferred Tax on the Components of	AmountBefore Tax	Income Tax Expense (Benefit)	Amount After Tax	AmountBefore Tax	Income Tax Expense (Benefit)	Amount After Tax	AmountBefore Tax	Income Tax Expense (Benefit)	Amount After Tax
Other Comprehensive Income	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Available-for-sale financial assets	(3,673)	992	(2,681)	(411)	111	(300)	1,840	(497)	1,343
Cash flow hedge	(139,174,121)	36,883,401	(102,290,720)	(221,906,855)	60,650,786	(161,256,069)	97,558,961	(25,701,599)	71,857,362
Share of other comprehensive income from associates and joint ventures accounted for using the equity method	—	—	—	—	—	—	(1,490)	—	(1,490)
Foreign currency translation	73,114,966	—	73,114,966	107,492,316	—	107,492,316	(3,686,549)	—	(3,686,549)
Actuarial gains(losses) on defined-benefit pension plans	(7,777,204)	2,099,845	(5,677,359)	37,881	(10,228)	27,653	1,716,875	(463,556)	1,253,319
Income tax related to components of other comprehensive income	(73,840,032)	38,984,238	(34,855,794)	(114,377,069)	60,640,669	(53,736,400)	95,589,637	(26,165,652)	69,423,985

The following table presents deferred taxes between the balance sheet and income taxes in other comprehensive income as of December 31, 2019 and 2018.

	For the years ended December 31,
	2019	2018	2017
Deferred taxes of components of other comprehensive income	ThCh$	ThCh$	ThCh$
Total increases (decreases) for deferred taxes of other comprehensive income from continuing operations	2,811,360	(10,117)	(464,053)
Income tax of changes in cash flow hedge transactions	36,172,878	60,650,786	(25,701,599)
Total income tax relating to components of other comprehensive income	38,984,238	60,640,669	(26,165,652)

In Chile, Law No. 20,780 was published in the Official Gazette on September 29, 2014. It changes the income tax system and other taxes, by replacing the current tax system in 2017 with two alternative tax systems: the attributed income system and partially integrated system.

This law gradually increases the rate of income tax on corporate income. Thus, it increased to 21% in 2014, to 22.5% in 2015 and to 24% in 2016. From 2017 taxpayers choosing the attributed income system are subject to a rate of 25%, while companies choosing the partially integrated system are subject to a rate of 25.5% in 2017 and 27% in 2018.

F-83

The law also states that corporations will automatically be subject to the partially integrated system unless a future Extraordinary Shareholders’ Meeting agrees to select the attributed income system.

On February 8, 2016, the Law No. 20,899 was published which, simplifying the income tax system. Its main modifications imposed the partially integrated system as mandatory for corporations, cancelling the previously available attributed income system option.

21.  OTHER FINANCIAL LIABILITIES.

The balances of other financial liabilities as of December 31, 2019 and 2018, are as follows:

	As of December 31,
	2019		2018
	Current	Non-current	Current	Non-current
Other financial liabilities	ThCh$	ThCh$	ThCh$	ThCh$
Interest –bearing borrowings	164,404,334	1,714,837,545	329,262,093	1,703,044,158
Hedging derivatives (*)	48,225,766	25,208,326	81,195,765	2,629,715
Non-hedging derivatives (**)	2,026,476	124,048	207,957	159,630
Total	214,656,576	1,740,169,919	410,665,815	1,705,833,503

(*)     See Note 23.2.a

(**)    See Note 23.2.b

21.1 Interest-bearing borrowings

The detail of current and non-current interest-bearing borrowings as of December 31, 2019 and 2018, is as follows:

	As of December 31,
	2019		2018
	Current	Non-current	Current	Non-current
Classes of Interest-bearing borrowings	ThCh$	ThCh$	ThCh$	ThCh$
Bank loans	113,247,263	135,297,019	70,790,775	229,020,029
Unsecured obligations	5	—	212,736,914	—
Unsecured Obligations with the public	45,315,051	1,531,974,852	43,568,129	1,461,713,954
Leases obligations	5,842,015	47,565,674	2,166,275	12,310,175
Total	164,404,334	1,714,837,545	329,262,093	1,703,044,158

F-84

Bank loans by currency and contractual maturity as of December 31, 2019 and 2018, are as follows:

Summary of bank loans by currency and maturity

					Current			Non-current
					Maturity			Maturity
Country	Currency	Effective Interest	Nominal Interest	Secured / Unsecured	One to three months	Three to twelve months	Total Current 12-31-2019	One to two years	Two to three years	Three to four years	Four to five  years	Over five years	Total Non-Current 12-31-2019
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	3.31%	3.31%	Unsecured	134,532	113,112,731	113,247,263	112,747,516	22,549,503	-	-	-	135,297,019
Chile	Ch$	6.00%	6.00%	Unsecured	5	-	5	-	-	-	-	-	-
				Total	134,537	113,112,731	113,247,268	112,747,516	22,549,503	-	-	-	135,297,019
					Current			Non-current
					Maturity			Maturity
Country	Currency	Effective  Interest	Nominal  Interest	Secured / Unsecured	One to three  months	Three to twelve months	Total Current 12-31-2018	One to two years	Two to three  years	Three to four  years	Four to five  years	Over five years	Total Non-Current 12-31-2018
		Rate	Rate		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	3.51%	3.51%	Unsecured	1,350,861	69,439,914	70,790,775	—	104,100,014	124,920,015	—	—	229,020,029
Chile	Ch$	4.71%	4.30%	Unsecured	6	212,736,908	212,736,914	—	—	—			—
				Total	1,350,867	282,176,822	283,527,689	—	104,100,014	124,920,015	—	—	229,020,029

Fair value measurement and hierarchy

The fair value of current and non-current bank borrowings as of December 31, 2019 and 2018 totaled ThCh$247,030,075 and ThCh509,822,541, respectively. The fair value measurement of borrowings has been categorized as Level 2 (see Note 3.h).

F-85

Identification of bank borrowings by company

										December 31, 2019
										Current			Non-current
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Amortization	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Total Non- Current ThCh$
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.036.000-k	Banco Santander (Overdraft line)	Chile	Ch$	6.00%	6.00%	At maturity	1	—	1	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-k	Banco Santander  (Overdraft line)	Chile	Ch$	6.00%	6.00%	At maturity	4	—	4	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.036.000-k	Banco Santander - Chile	Chile	Ch$	3.85%	3.17%	At maturity	—	—	0	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.004.000-5	Banco de Chile	Chile	Ch$	3.85%	3.17%	At maturity	—	—	0	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	Ch$	3.85%	3.17%	At maturity	—	—	0	—	—	—	—
96.920.110-0	Enel Green Power Chile Ltda.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	4.14%	4.14%	At maturity	—	—	0	—	—	—	—
96.920.110-0	Enel Green Power Chile Ltda.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	4.17%	4.17%	At maturity	134,532	112,747,516	112,882,048	—	—	—	—
96.920.110-0	Enel Green Power Chile Ltda.	Chile	Foreign	Inter-American Development Bank (BID)	U.S.	US$	1.50%	1.50%	At maturity		43,220	43,220	—	22,549,503	—	22,549,503
96.524.140-K	Empresa Eléctrica Panguipulli S.A.	Chile	97.018.000-1	Scotiabank Chile	Chile	US$	4.25%	4.25%	At maturity		321,995	321,995	112,747,516	—	—	112,747,516
									Total	134,537	113,112,731	113,247,268	112,747,516	22,549,503	—	135,297,019
										December 31, 2018
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Amortization	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Total Non- Current ThCh$
96.800.570-7	Enel Distribución Chile S.A.	Chile	97.006.000-6	Banco Santander (Overdraft line)	Chile	Ch$	6.00%	6.00%	At maturity	2	—	2	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander  (Overdraft line)	Chile	Ch$	6.00%	6.00%	At maturity	4	—	4	—	—	—	—
76.536.353-5	Enel Chile S.A	Chile	97.036.000-K	Banco Santander	Chile	Ch$	3.85%	3.17%	At maturity	—	65,829,996	65,829,996	—	—	—	—
76.536.353-5	Enel Chile S.A	Chile	97.004.000-5	Banco de Chile	Chile	Ch$	3.85%	3.17%	At maturity	—	73,453,456	73,453,456	—	—	—	—
76.536.353-5	Enel Chile S.A	Chile	97.018.001-1	Scotiabank Chile	Chile	Ch$	3.85%	3.17%	At maturity	—	73,453,456	73,453,456	—	—	—	—
96.920.110-0	Enel Green Power Chile Ltda	Chile	97.080.000-K	BBVA	Chile	US$	4.14%	4.14%	At maturity	814,628	69,400,009	70,214,637	—	—	—	—
96.920.110-0	Enel Green Power Chile Ltda	Chile	97.080.000-K	BBVA	Chile	US$	4.17%	4.17%	At maturity	158,913	—	158,913	—	104,100,014	—	104,100,014
96.920.110-0	Enel Green Power Chile Ltda	Chile	59.054.440-K	INTER-AMERICAN INVESTIMENT CORPORATION	U.S.	US$	1.50%	1.50%	At maturity	—	39,905	39,905	—	—	20,820,002	20,820,002
95.524.140-K	Empresa Electrica Panguipulli S.A	Chile	97.080.000-K	BBVA	Chile	US$	4.25%	4.25%	At maturity	377,320	—	377,320	—	—	104,100,013	104,100,013
									Total	1,350,867	282,176,822	283,527,689	—	104,100,014	124,920,015	229,020,029

F-86

21.2 Unsecured liabilities

The detail of Unsecured Liabilities by currency and maturity as of December 31, 2019 and 2018, is as follows:

Summary of public unsecured liabilities by currency and maturity

					Current			Non-Current
					Maturity			Maturity
		EffectiveInterest	Nominal Annual	Secured/	One to three months	Three to Twelve months	Total Current 12-31-2019	One to two years	Twoto three years	Three to four years	Four to fiveyears	Morethan five years	Total Non- Current 12/31/2019
Country	Currency	Rate	Rate	Unsecured	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.59%	6.49%	Unsecured	7,700,030	4,755,019	12,455,049	—	—	—	296,420,703	961,519,091	1,257,939,794
Chile	U.F.	6.00%	5.48%	Unsecured	—	32,860,002	32,860,002	31,624,776	31,624,776	31,624,776	31,624,776	147,535,954	274,035,058
				Total	7,700,030	37,615,021	45,315,051	31,624,776	31,624,776	31,624,776	328,045,479	1,109,055,045	1,531,974,852
					Current			Non-Current
					Maturity			Maturity
		EffectiveInterest	Nominal Annual	Secured/	One to three months	Three to Twelve months	Total Current 12-31-2018	One to two years	Twoto three years	Three to four years	Four to fiveyears	Morethan five years	Total Non- Current 12/31/2018
Country	Currency	Rate	Rate	Unsecured	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.59%	6.49%	Unsecured	7,144,997	4,281,038	11,426,035	—	—	—	—	1,164,595,519	1,164,595,519
Chile	U.F.	6.00%	5.48%	Unsecured	—	32,142,094	32,142,094	30,793,493	30,793,493	30,793,493	30,793,493	173,944,463	297,118,435
				Total	7,144,997	36,423,132	43,568,129	30,793,493	30,793,493	30,793,493	30,793,493	1,338,539,982	1,461,713,954

Summary of public unsecured liabilities by currency and maturity

										December 31, 2019
										Current			Non-Current
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-1	U.S.	US$	7.96%	7.88%	No	5,058,091	—	5,058,091	—	—	—	—	153,480,285	153,480,285
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Primera Emisión S-2	U.S.	US$	7.40%	7.33%	No	1,617,476	—	1,617,476	—	—	—	—	51,960,662	51,960,662
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Primera Emisión S-3	U.S.	US$	8.26%	8.13%	No	1,024,463	—	1,024,463	—	—	—	—	24,876,133	24,876,133
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Unica 24296	U.S.	US$	4.32%	4.25%	No	—	2,828,573	2,828,573	—	—	—	296,420,703	—	296,420,703
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander -317 Serie-H	Chile	UF	7.17%	6.20%	No	—	6,592,332	6,592,332	5,888,467	5,888,467	5,888,467	5,888,467	20,428,651	43,982,519
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander  522 Serie-M	Chile	UF	4.82%	4.75%	No	—	26,267,670	26,267,670	25,736,309	25,736,309	25,736,309	25,736,309	127,107,303	230,052,539
76.536.353-5	Enel Chile S.A.	Chile	Foreign	BNY Mellon - Unica	U.S.	US$	5.03%	4.88%	No	—	1,926,446	1,926,446					731,202,011	731,202,011
									Total Unsecured Bonds	7,700,030	37,615,021	45,315,051	31,624,776	31,624,776	31,624,776	328,045,479	1,109,055,045	1,531,974,852
										December 31, 2018
										Current			Non-Current
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Effective Interest Rate	Nominal Interest Rate	Secured	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon - Primera Emisión S-1	U.S.	US$	7.96%	7.88%	No	4,693,498	—	4,693,498	—	—	—	—	142,300,747	142,300,747
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Primera Emisión S-2	U.S.	US$	7.40%	7.33%	No	1,500,880	—	1,500,880	—	—	—	—	48,131,124	48,131,124
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Primera Emisión S-3	U.S.	US$	8.26%	8.13%	No	950,619	—	950,619	—	—	—	—	22,694,249	22,694,249
91.081.000-6	Enel Generación Chile S.A.	Chile	Foreign	BNY Mellon  - Unica 24296	U.S.	US$	4.32%	4.25%	No	—	2,493,452	2,493,452	—	—	—	—	274,469,150	274,469,150
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander -317 Serie-H	Chile	UF	7.17%	6.20%	No	—	6,513,162	6,513,162	5,733,684	5,733,684	5,733,684	5,733,684	25,386,928	48,321,664
91.081.000-6	Enel Generación Chile S.A.	Chile	97.036.000-K	Banco Santander  522 Serie-M	Chile	UF	4.82%	4.75%	No	—	25,628,932	25,628,932	25,059,809	25,059,809	25,059,809	25,059,809	148,557,535	248,796,771
76.536.353-5	Enel Chile S.A.	Chile	Foreign	BNY Mellon - Unica	U.S.	US$	5.03%	4.88%	No	—	1,787,586	1,787,586	—	—	—	—	677,000,249	677,000,249
									Total Unsecured Bonds	7,144,997	36,423,132	43,568,129	30,793,493	30,793,493	30,793,493	30,793,493	1,338,539,982	1,461,713,954

F-87

21.3 Secured liabilities

As of December 31, 2019 and 2018, there were no secured liabilities.

Fair value measurement and hierarchy

The fair value of current and non-current unsecured liabilities as of December 31, 2019 and 2018 totaled ThCh$1,941,481,412 and ThCh$1,685,679,241, respectively. The fair value measurement of these liabilities has been categorized as Level 2 (See Note 3.h). It is important to note that these financial assets are measured at amortized cost (See Note 3.g.4).

F-88

21.4 Detail of lease obligations 

								December 31, 2019
								Current			Non-Current ThCh$
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Nominal Interest Rate	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	Total Non- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	76.555.400-4	Transelec S.A.	Chile	US$	6.50%	606,973	1,879,324	2,486,297	2,647,907	2,820,020	5,312,211	—	—	10,780,138
91.081.000-6	Enel Generación Chile S.A.	Chile	10.579.624-2	Marcelo Alberto Amar Basulto	Chile	UF	2.06%	4,067	13,237	17,304	17,966	18,335	18,713	19,097	208,057	282,168
91.081.000-6	Enel Generación Chile S.A.	Chile	91.004.000-6	Productos Fernandez S.A.	Chile	UF	2.09%	12,399	24,861	37,260	33,755	34,460	35,182	35,917	410,646	549,960
91.081.000-6	Enel Generación Chile S.A.	Chile	61.216.000-7	Empresa De Ferrocarriles Del Estado	Chile	UF	1.07%	1,104	557	1,661	1,123	—	—	—	—	1,123
91.081.000-6	Enel Generación Chile S.A.	Chile	78.392.580-K	Agricola El Bagual Ltda.	Chile	UF	1.91%	1,152	—	1,152	564	573	581	—	—	1,718
91.081.000-6	Enel Generación Chile S.A.	Chile	99.527.200-8	Rentaequipos Tramaca S.A.	Chile	UF	0.83%	144,436	—	144,436	—	—	—	—	—	—
91.081.000-6	Enel Generación Chile S.A.	Chile	96.565.580-8	Compañía De Leasing Tattersall S A.	Chile	UF	0.83%	6,607	—	6,607	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.643.660-3	Inmobiliaria El Roble S.A.	Chile	UF	1.41%	12,589	41,263	53,852	48,574	—	—	—	—	48,574
96.800.570-7	Enel Distribución Chile S.A.	Chile	2.859.481-K	Nuria Ferrer Pares	Chile	UF	1.20%	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	2.478.836-9	Juana Ferrer Pares	Chile	UF	1.20%	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	3.800.735-1	Carmen Elvira Echavarry De La Sierra	Chile	UF	1.20%	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	5.742.701-9	Jorge Ferrer Pares	Chile	UF	1.20%	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	5.120.460-3	Carmen Ferrer Pares	Chile	UF	1.20%	4,244	7,621	11,865	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	70.015.730-K	Mutual De Seguros De Chile	Chile	UF	1.91%	13,990	45,274	59,264	61,373	62,545	63,741	64,959	111,258	363,876
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.596.523-3	Capital Investi	Chile	UF	1.91%	11,479	37,011	48,490	50,173	51,131	52,108	53,104	90,955	297,471
96.800.570-7	Enel Distribución Chile S.A.	Chile	77.651.230-3	Inversiones Tapihue Ltda	Chile	UF	1.20%	10,501	—	10,501	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.253.641-2	Bcycle Latam S.P.A	Chile	Ch$	6.24%	—	20,000	20,000	15,699	16,679	17,719	18,825	—	68,922
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.203.089-6	Rentas Inmobiliarias Amanecer S.A.	Chile	UF	1.56%	12,239	24,679	36,918	51,480	14,593	—	—	—	66,073
96.800.570-7	Enel Distribución Chile S.A.	Chile	61.219.000-3	Empresa De Transporte De Pasajeros Metro S.A	Chile	US$	5.99%	—	350,227	350,227	114,222	120,634	130,857	132,426	1,476,550	1,974,689
96.800.570-7	Enel Distribución Chile S.A.	Chile	85.208.700-5	Rentaequipos Leasing S.A.	Chile	UF	1.20%	774	—	774	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	Compañia De Leasing Tattersall S A.	Chile	UF	1.41%	1,628	5,363	6,991	4,544	—	—	—	—	4,544
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.013.489-9	Inversiones Don Issa Ltda	Chile	UF	1.67%	16,118	51,903	68,021	70,215	71,388	24,186	—	—	165,789
96.800.570-7	Enel Distribución Chile S.A.	Chile	76.164.095-K	Inmobilaria Mixto Renta Spa	Chile	UF	1.07%	16,530	—	16,530	—	—	—	—	—	—
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	Compañia De Leasing Tattersall S A.	Chile	UF	1.41%	278	3,392	3,670	652	—	—	—	—	652
96.800.570-7	Enel Distribución Chile S.A.	Chile	96.565.580-8	Compañia De Leasing Tattersall S A.	Chile	UF	1.41%	988	3,231	4,219	2,736	—	—	—	—	2,736
96.920.110-0	Enel Green Power Chile Ltda.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	76,055	—	76,055	43,584	44,691	45,827	46,991	1,156,664	1,337,757
96.920.110-0	Enel Green Power Chile Ltda.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	117,630	117,630	42,842	43,930	45,047	46,191	1,066,692	1,244,702
96.920.110-0	Enel Green Power Chile Ltda.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	29,696	—	29,696	16,622	17,044	17,477	17,921	439,871	508,935
96.920.110-0	Enel Green Power Chile Ltda.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	29,189	29,189	19,513	20,009	20,517	21,038	548,843	629,920
96.524.140-k	Empresa Eléctrica Panguipulli S.A.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	EUR	5.02%	—	260,072	260,072	167,261	175,655	184,471	193,729	2,532,578	3,253,694
96.524.140-k	Empresa Eléctrica Panguipulli S.A.	Chile	76.259.106-5	Inmobiliaria Terra Australis Tres S.A.	Chile	UF	6.39%	—	46,597	46,597	54,543	55,929	57,350	58,807	1,012,677	1,239,306
96.524.140-k	Empresa Eléctrica Panguipulli S.A.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	6.39%	—	98,189	98,189	70,885	72,686	74,533	76,427	1,881,835	2,176,366
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	36,519	36,519	27,274	27,967	28,677	29,406	723,912	837,236
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	26,329	26,329	19,661	20,161	20,673	21,198	521,858	603,551
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	30,727	30,727	22,949	23,532	24,130	24,743	609,121	704,475
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	27,615	27,615	20,619	21,143	21,680	22,231	547,270	632,943
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	3,738	3,738	2,793	2,864	2,937	3,011	74,129	85,734
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	47,317	47,317	44,688	45,824	46,988	48,182	1,190,338	1,376,020
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	31,087	—	31,087	18,256	18,720	19,195	19,683	517,037	592,891
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	29,105	—	29,105	17,619	18,066	18,525	18,996	467,606	540,812
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	628	—	628	383	393	403	413	10,169	11,761
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	1,331	1,331	683	700	718	736	20,591	23,428
76.412.562-2	Enel Green Power del Sur SPA.	Chile	76.400.311-K	Fundo Los Buenos Aires Spa	Chile	UF	2.54%	—	111,365	111,365	67,592	69,309	71,070	72,876	1,450,422	1,731,269
76.412.562-2	Enel Green Power del Sur SPA.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4.94%	7,914	—	7,914	2,949	3,095	3,248	3,408	99,995	112,695
76.412.562-2	Enel Green Power del Sur SPA.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4.94%	15,877	—	15,877	6,496	6,817	7,154	7,507	185,500	213,474
76.412.562-2	Enel Green Power del Sur SPA.	Chile	3.750.132-8	Juan Rioseco Garcia	Chile	UF	4.94%	3,961	—	3,961	1,474	1,547	1,624	1,704	49,994	56,343
76.412.562-2	Enel Green Power del Sur SPA.	Chile	4.595.479-K	Adriana Castro Parra	Chile	UF	4.94%	31,828	—	31,828	12,991	13,633	14,307	15,015	370,630	426,576
76.412.562-2	Enel Green Power del Sur SPA.	Chile	7.256.021-3	Alicia Freire Hermosilla	Chile	UF	4.31%	93,160	—	93,160	88,809	—	—	—	—	88,809
76.412.562-2	Enel Green Power del Sur SPA.	Chile	77.378.630-5	Agricola Santa Amalia	Chile	UF	4.94%	31,828	—	31,828	12,991	13,633	14,307	15,015	370,631	426,577
76.412.562-2	Enel Green Power del Sur SPA.	Chile	77.894.990-3	Orafti Chile S.A.	Chile	UF	4.94%	15,918	—	15,918	6,190	6,496	6,817	7,154	192,635	219,292
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	4.87%	—	472,736	472,736	227,365	238,428	250,031	262,197	4,335,384	5,313,405
76.412.562-2	Enel Green Power del Sur SPA.	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	4.94%	41,389	—	41,389	13,058	13,704	14,381	15,092	520,042	576,277
76.412.562-2	Enel Green Power del Sur SPA.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4.94%	5,605	—	5,605	2,141	2,247	2,359	2,475	66,716	75,938
76.412.562-2	Enel Green Power del Sur SPA.	Chile	78.201.750-0	Sociedad Agricola Parant	Chile	UF	4.94%	95,241	—	95,241	37,137	38,973	40,900	42,922	1,156,961	1,316,893
76.412.562-2	Enel Green Power del Sur SPA.	Chile	3.750.131-K	Federico Rioseco Garcia	Chile	UF	4.94%	7,935	—	7,935	3,095	3,248	3,408	3,577	96,415	109,743
76.179.024-2	Parque Eólico Tal  Tal SpA	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.36%	32,269	—	32,269	22,884	23,424	23,978	24,545	311,762	406,593
76.179.024-2	Parque Eólico Tal  Tal SpA	Chile	79.938.160-5	Soc. Serv. Com.. Multiservice F.L.	Chile	UF	2.94%	—	35,334	35,334	35,034	36,064	37,124	38,215	981,212	1,127,649
76.052.206-6	Parque Eólico Valle de los Vientos SpA	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.23%	48,681	—	48,681	37,594	38,433	39,291	40,168	258,481	413,967
76.126.507-5	Parque Eólico Talinay Oriente S.A.	Chile	76.248.317-3	Agricola Alto Talinay	Chile	EUR	4.61%	—	367,982	367,982	201,806	211,109	220,842	231,022	2,951,326	3,816,105
76.321.458-3	Almeyda Solar SPA	Chile	61.402.000-8	Ministerio De Bienes Nacionales	Chile	UF	2.54%	—	34,408	34,408	25,058	25,694	26,347	27,017	621,989	726,105
76.536.353-5	Enel Chile S.A.	Chile	78.822.300-5	Inversiones Cardinal S.A	Chile	UF	1.20%	9,281	24,801	34,082	—	—	—	—	—	—
76.536.353-5	Enel Chile S.A.	Chile	78.822.300-5	Inversiones Cardinal S.A	Chile	UF	1.20%	9,714	19,465	29,179	—	—	—	—	—	—
							Total Leasing	1,512,244	4,329,771	5,842,015	4,515,822	4,565,526	7,061,634	1,783,940	29,638,752	47,565,674
								December 31, 2018
								Current			Non-Current ThCh$
TaxpayerID Number	Company	Country	Taxpayer ID Number	Financial Institution	Country	Currency	Nominal Interest Rate	Less than 90 days ThCh$	More than 90 days ThCh$	Total Current ThCh$	One to two years ThCh$	Two to three years ThCh$	Three to four years ThCh$	Four to five years ThCh$	More than five years ThCh$	TotalNon- Current ThCh$
91.081.000-6	Enel Generación Chile S.A.	Chile	76.555.400-4	Transelec S.A.	Chile	US$	6.50%	528,847	1,637,428	2,166,275	2,307,082	2,457,043	2,616,750	4,929,300	—	12,310,175
							Total Leasing	528,847	1,637,428	2,166,275	2,307,082	2,457,043	2,616,750	4,929,300	—	12,310,175

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21.5 Hedged debt

The U.S. dollar denominated debt of the Group as of December 31, 2019 and 2018, that is designated as cash flow hedge to hedge the portion of revenue from its consolidated entities that is directly linked to variations in the U.S. dollar, as referenced in Note 3.g.5, was ThCh$1,585,140,233 and ThCh$1,192,973,584, respectively.

The following table details changes in “Reserve for cash flow hedges” as of December 31, 2019 and 2018, due to exchange differences of this debt:

	For the years ended December 31,
	2019	2018	2017
	ThCh$	ThCh$	ThCh$
Balance in hedging reserves (hedging income) at the beginning of the period, net	(127,508,852)	(27,168,007)	(52,747,645)
Foreign currency exchange differences recognized in equity, net	(77,347,380)	(101,790,308)	17,321,594
Foreign currency exchange differences recognized in profit and loss, net	15,042,823	12,478,369	8,258,044
Others (Tender Offer 33.57% April 2, 2018 on Enel Generacion Chile)	—	(11,028,906)	—
Balance in hedging reserves (hedging income) at the end of the period, net	(189,813,409)	(127,508,852)	(27,168,007)

21.6 Other information

As of December 31, 2019 and 2018, the Group has undrawn line of credits available for use amounting to ThCh$146,268,500 and ThCh$416,862,000, respectively.

21.7Future undiscounted debt flow

The following tables are the estimates of undiscounted flows by type of financial debt:

a) Bank loans guaranteed and unsecured

						Non-Current						Current			Non-Current
					Total Current	Maturity					Total Non-Current			Total Current	Maturity					Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019	One to Three Months	Three to twelve months	as of 12-31-2018	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	3.31%	2,542,588	120,375,278	122,917,866	118,121,339	22,859,559	-	-	-	140,980,898	1,985,915	75,074,314	77,060,229	110,909,917	106,335,361	21,112,380	-	-	238,357,658
Chile	Ch$	6.00%	5	-	5	-	-	-	-	-	-	1,798,705	215,920,510	217,719,215	-	-	-	-	-	-
Totals			2,542,593	120,375,278	122,917,871	118,121,339	22,859,559	-	-	-	140,980,898	3,784,620	290,994,824	294,779,444	110,909,917	106,335,361	21,112,380	-	-	238,357,658

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b) Guaranteed and unsecured obligations

						Non-Current							Current			Non-Current
			Maturity		Total Current	Maturity					Total Non-Current	Maturity			Total Current	Maturity					Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019		One to Three Months	Three to twelve months	as of 12-31-2018	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2018
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.49%	17,750,370	53,251,108	71,001,478	71,001,479	71,001,479	71,001,479	362,787,755	1,387,871,953	1,963,664,145		16,173,722	48,521,166	64,694,888	64,694,887	64,694,887	64,694,887	64,694,887	1,612,310,243	1,871,089,791
Chile	U.F.	5.48%	6,136,022	49,438,671	55,574,693	53,077,463	50,580,233	48,083,003	45,585,772	186,005,287	383,331,758		6,603,562	49,871,556	56,475,118	54,036,540	51,597,963	49,159,386	46,720,808	224,787,689	426,302,386
Totals			23,886,392	102,689,779	126,576,171	124,078,942	121,581,712	119,084,482	408,373,527	1,573,877,240	2,346,995,903		22,777,284	98,392,722	121,170,006	118,731,427	116,292,850	113,854,273	111,415,695	1,837,097,932	2,297,392,177

c) Lease obligations

						Non-Current						Current			Non-Current
					Total Current	Maturity					Total Non-Current			Total Current	Maturity						Total Non-Current
Country	Currency	Nominal Interest Rate	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019	One to Three Months	Three to twelve months	as of 12-31-2019	One to two years	Two to Three Years	Three to Four Years	Four to Five Years	More than Five Years	as of 12-31-2019
			ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Chile	US$	6.25%	859,011	2,802,479	3,661,490	3,570,048	3,554,711	5,731,772	258,317	2,063,704	15,178,552	760,090	2,278,842	3,038,932	3,034,977	3,030,765	3,026,279	5,044,764	-	14,136,785
Chile	Euros	4.82%	80,971	240,372	321,343	499,678	485,713	471,749	457,785	2,453,454	4,368,379	-	-	-	-	-	-	-	-	-
Chile	UF	2.68%	821,084	2,293,383	3,114,467	2,895,029	2,523,717	2,462,599	2,412,029	30,885,469	41,178,843	-	-	-	-	-	-	-	-	-
Chile	CH$	6.24%	1,180	23,113	24,293	17,847	16,967	16,087	15,207	-	66,108	-	-	-	-	-	-	-	-	-
Totals			1,762,246	5,359,347	7,121,593	6,982,602	6,581,108	8,682,207	3,143,338	35,402,627	60,791,882	760,090	2,278,842	3,038,932	3,034,977	3,030,765	3,026,279	5,044,764	-	14,136,785

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22.  RISK MANAGEMENT POLICY.

The Group’s companies are exposed to certain risks that are managed by systems that identify, measure, limit concentration of, and monitor these risks.

The main principles in the Group’s risk management policy include the following:

· Compliance with good corporate governance standards.

· Strict compliance with all the Group’s internal policies.

· Each business and corporate area determines:

i. The markets in which it can operate based on its knowledge and ability to ensure effective risk management;

ii. Criteria regarding counterparties and

iii. Authorized operators.

· Business and corporate areas establish their risk tolerance in a manner consistent with the defined strategy for each market in which they operate.

· All of the operations of the businesses and corporate areas are conducted within the limits approved for each case.

· Businesses, corporate areas, lines of business and companies design the risk management controls necessary to ensure that transactions in the markets are conducted in accordance with the Enel Chile’s policies, standards, and procedures.

22.1 Interest rate risk

The changes in interest rates affect the fair value of assets and liabilities bearing fixed interest rates, as well as the expected future cash flows of assets and liabilities subject to floating interest rates.

The objective of managing interest rate risk exposure is to achieve a balance in the debt structure to minimize the cost of debt with reduced volatility in profit or loss.

The comparative structure of the financial debt of the Group according to the fixed and / or protected interest rate on the gross debt, after derivatives contracted, is as follows:

Gross position:

	For the years ended December 31,
	2019	2018
	%	%
Fixed interest rate	98%	71%

(i) The change in the estimation between fixed and variable, is explained by the renegotiation between EGP del Sur and Enel Finance International NV. For more details see Note 12.d.ii.

Depending on the Group’s estimates and on the objectives of the debt structure, hedging transactions are performed by entering into derivatives contracts that mitigate interest rate risk.

22.2 Exchange rate risk

Exchange rate risks involve basically the following transactions:

· Debt taken on by the Group’s companies that is denominated in a currency other than that in which its cash flows are indexed.

· Payments to be made for the acquisition of project-related materials and for corporate insurance policies in a currency other than that in which its cash flows are indexed.

· Revenues in the Group companies directly linked to changes in currencies other than that of its cash flows.

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In order to mitigate foreign currency risk, the Group’s foreign currency risk management policy is based on cash flows and includes maintaining a balance between U.S. dollar flows and the levels of assets and liabilities denominated in this currency. The objective is to minimize the exposure to variability in cash flows that are attributable to foreign exchange risk.

The hedging instruments currently being used to comply with the policy are currency swaps and forward exchange contracts. In addition, the policy seeks to refinance debt in the functional currency of each of the Group’s companies.

22.3 Commodities risk

The Group has a risk exposure to price fluctuations in certain commodities, basically due to:

· Purchases of fuel used to generate electricity.

· Energy purchase/sale transactions that take place in local markets.

In order to reduce the risk in situations of extreme drought, the Group has designed a commercial policy that defines the levels of sales commitments in line with the capacity of its generating power plants in a dry year. It also includes risk mitigation terms in certain contracts with unregulated customers and with regulated customers subject to long-term tender processes, establishing indexation polynomials that allow for reducing commodities exposure risk.

Considering the operating conditions faced by the power generation market in Chile, with drought and highly volatile commodity prices on international markets, the Group is constantly analyzing whether it is in its best interest to use  hedging to lessen the impacts that these price swings have on its results.

As of December 31, 2019,  there were current transactions for 1,412 kTon of API2 to be settled in 2020,  1,059 kBbl of Brent to be settled in 2020, and 4.79 TBtu from HH to be settled in 2020.

As of December 31, 2018 there were current transactions for 432 kTon of API2 to be settled in 2019, 994 kBbl of Brent to be settled in 2019, 225 kTon of BCI7 to be settled in 2019 and 0.2 TBtu of HH to be settled in 2019 (figures considered net hedged position).

Depending on operating conditions, which are constantly being updated, these hedges may be modified or may cover other commodities.

22.4 Liquidity risk

The Group maintains a liquidity risk management policy that consists of entering into long-term committed banking facilities and temporary financial investments for amounts that cover the projected needs over a period of time that is determined based on the situation and expectations for debt and capital markets.

The projected needs mentioned above include maturities of financial debt, net of financial derivatives. For further details regarding the features and conditions of financial obligations and financial derivatives. See Notes 21 and 23.

As of December 31, 2019, the Group had a liquidity position  of ThCh$235,684,500 in cash and equivalents  and ThCh$146,268,500 in unconditionally available long-term credit lines. As of December 31, 2018 the Group’s liquidity is as follows:  cash and cash equivalents for ThCh$245,171,924 and unconditionally available long-term credit lines for ThCh$416,862,000.

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22.5 Credit risk

The Group closely monitors its credit risk, as described below:

Trade receivables:

The credit risk for receivables from the Group’s commercial activity has historically been very low, due to the short-term period of collections from customers, resulting in non-significant cumulative receivables amounts. This situation applies to both the electricity generation and distribution lines of business.

In the electricity generation and distribution lines of business, regulations allow the suspension of energy service to customers with outstanding payments, and the contracts have termination clauses for payment default. The Group monitors its credit risk on an ongoing basis and measures its maximum exposure to payment default risk, which, as stated above, is very limited.

In the case of our electricity distributionbusiness, the suspension of energy service to customers, is a right available to the business in case of breaches by our costumers, which is applied according to the current regulation, which facilitates the process of evaluation and control of credit risk, which by the way is limited.

Financial assets:

Cash surpluses are invested in the highest-rated local and foreign financial entities (with risk rating equivalent to investment grade where possible) with thresholds established for each entity.

In selecting banks to make investments, the Group considers those banks with investment grade ratings granted by main international rating agencies (Moody’s, S&P and Fitch).

Investments may be backed with treasury bonds from the countries in which the Group operates and/or with commercial papers issued by the highest rated banks; the latter are preferred, as they offer higher returns (always in line with current investment policies).

22.6 Risk measurement

The Group measures the Value at Risk (VaR) of its debt positions and financial derivatives in order to monitor the risk assumed by the Group, thereby reducing volatility in the income statement.

The portfolio of positions included for the purposes of the calculations of this value at risk include:

· Financial debt.

· Hedging derivatives for debt.

The VaR determined represents the potential variation in value of the portfolio of positions described above in one quarter with a 95% confidence level. To determine the VaR, we take into account the volatility of the risk variables affecting the value of the portfolio of positions including:

· U.S. dollarLIBOR interest rate.

· The exchange rates of the various currencies used in the calculation.

The calculation of VaR is based on generating possible future scenarios (at one quarter) of market values (both spot and term) for the risk variables based on the scenarios with observable inputs for a same period (quarter) during five years. The one-quarter 95%-confidence VaR number is calculated as the 5% percentile of the potential variations in the fair value of the portfolio in one quarter. Taking into account the assumptions described above, the one-quarter VaR was ThCh$237,095,044. This amount represents the potential increase of the debt and derivatives’ portfolio, thus these VaRs are inherently related, among other factors, to the portfolio’s value at each quarter’s end.

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23.  FINANCIAL INSTRUMENTS.

23.1 Financial instruments, classified by type and category

a) The detail of financial assets, classified by type and category, as of December 31, 2019 and 2018, is as follows:

		December 31, 2019
	Financial assets at fair value through profit and loss	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Equity instruments	—	—	127,854	—
Trade accounts receivable and other accounts receivable	—	576,740,203	—	—
Derivative instruments	1,618,318	—	1,323,556	277,702
Other financial assets	—	860,425	—	—
Total Current	1,618,318	577,600,628	1,451,410	277,702
Equity instruments	—	—	2,349,221	—
Trade accounts receivable and other accounts receivable	—	347,981,527	—	—
Derivative instruments	—	—	—	4,871,397
Other financial assets	—	2	—	—
Total Non-current	—	347,981,529	2,349,221	4,871,397
Total	1,618,318	925,582,157	3,800,631	5,149,099
		December 31, 2018
	Financial assets at fair value through profit and loss	Financial assets measured at amortized cost	Financial assets at fair value with changes in other comprehensive income	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Equity instruments	90,839	—	269,031	—
Trade accounts receivable and other accounts receivable	—	529,467,040	—	—
Derivative instruments	1,491,497	—	1,423,613	39,022,012
Other financial assets	—	880,268	—	—
Total Current	1,582,336	530,347,308	1,692,644	39,022,012
Equity instruments	—	—	2,352,894	—
Trade accounts receivable and other accounts receivable	—	60,527,843	—	—
Derivative instruments	36,086	—	—	4,191,543
Other financial assets	—	689,146	—	—
Total Non-current	36,086	61,216,989	2,352,894	4,191,543
Total	1,618,422	591,564,297	4,045,538	43,213,555

The book value of trade accounts receivable and payable approximates their fair value.

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b) The detail of financial liabilities, classified by type and category, as of December 31, 2019 and 2018, is as follows:

	December 31, 2019
	Financial liabilities held for trading	Loans and payables	Financial Liabilities at fair value with changes in other result	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	164,404,334	—	—
Trade accounts payable and other accounts payable	—	750,103,757	—	—
Derivative instruments	2,026,476	—	8,924,831	48,225,766
Total Current	2,026,476	914,508,091	8,924,831	48,225,766
Interest-bearing loans	—	1,714,837,545	—	—
Trade accounts payable and other accounts payable	—	840,623,569	—	—
Derivative instruments	124,048	—	—	25,208,326
Total Non-current	124,048	2,555,461,114	—	25,208,326
Total	2,150,524	3,469,969,205	8,924,831	73,434,092
	December 31, 2018
	Financial liabilities held for trading	Loans and payables	Financial Liabilities at fair value with changes in other result	Financial derivatives for hedging
	ThCh$	ThCh$	ThCh$	ThCh$
Interest-bearing loans	—	329,262,093	—	—
Trade accounts payable and other accounts payable	—	702,770,048	—	—
Derivative instruments	756,005	—	7,161,949	81,195,765
Total Current	756,005	1,032,032,141	—	81,195,765
Interest-bearing loans	—	1,703,044,158	—	—
Trade accounts payable and other accounts payable	—	449,777,982	—	—
Derivative instruments	159,630	—	—	2,629,715
Total Non-current	159,630	2,152,822,140	—	2,629,715
Total	915,635	3,184,854,281	—	83,825,480

23.2 Derivative instruments

The risk management policy of the Group uses primarily interest rate and foreign exchange rate derivatives to hedge its exposure to interest rate and foreign currency risks.

The Group classifies its derivatives as follows:

· Cash flow hedges: Those that hedge the cash flows of the underlying hedged item.

· Fair value hedges: Those that hedge the fair value of the underlying hedged item.

· Non-hedge derivatives: Financial derivatives that do not meet the requirements established by IFRS to be designated as hedge instruments are recorded at fair value with changes in net income (assets held for trading).

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a) Assets and liabilities for hedge derivative instruments

As of December 31, 2019 and 2018, financial derivative transactions qualifying as hedge instruments resulted in recognition of the following assets and liabilities in the consolidated statement of financial position:

	December 31, 2019
	Assets		Liabilities
	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	322,316	8,447	—	7,743,401
Cash flow hedge	322,316	8,447	—	7,743,401
Exchange rate hedge:	—	4,862,950	48,225,766	17,464,925
Cash flow hedge	—	4,862,950	48,225,766	17,464,925
Total	322,316	4,871,397	48,225,766	25,208,326
	December 31, 2018
	Assets		Liabilities
	Current	Non-current	Current	Non-current
	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	852,119	4,191,543
Cash flow hedge	852,119	4,191,543
Exchange rate hedge:	38,169,893	—	81,195,765	2,629,715
Cash flow hedge	38,169,893	—	81,195,765	2,629,715
Total	39,022,012	4,191,543	81,195,765	2,629,715

General information on hedge derivative instruments

Hedge derivative instruments and their corresponding hedged instruments are shown in the following table:

			Fair value of	Fair value of
Detail of	Description	Description	hedged item	hedged item	Type
hedging	of hedging	of hedge	12-31-2019	12-31-2018	of
instrument	instrument	item	ThCh$	ThCh$	risk hedged
SWAP	Interest rate	Others	(699,158)	—	Cash flow
SWAP	Exchange rate	Unsecured obligations (bonds)	(9,530,240)	(18,892,400)	Cash flow
SWAP	Interest rate	Loans with Related Companies	(6,991,184)	—	Cash flow
SWAP	Interest rate	Bank loans	—	5,043,662	Cash flow
SWAP	Interest rate	Bank loans	277,703	—	Cash flow
FORWARD	Exchange rate	Operational Income	(51,297,500)	(26,763,187)	Cash flow

(*)See note 22.2.

For the years ended December 31, 2019, 2018 and 2017 the Group did not recognize gains or losses for ineffective cash flow hedges.

The Group has not entered into any fair value hedges for any of the periods reported.

b)Financial derivative instrument assets and liabilities at fair value through profit or loss

As of December 31, 2019 and 2018, financial derivative transactions recorded at fair value through profit or loss, resulted in the recognition of the following assets and liabilities in the statement of financial position:

	December 31, 2019				December 31, 2018
	Current Assets	Current Liabilities (*)	Non-Current Assets	Non-Current Liabilities (*)	Current Assets	Current Liabilities (*)	Non-Current Assets	Non-Current Liabilities (*)
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Non-hedging derivative instrument	—	2,026,476	—	124,048	41,023	207,957	36,086	159,630
Total	—	2,026,476	—	124,048	41,023	207,957	36,086	159,630

These derivative instruments correspond to forward contracts entered into by the Group, whose purpose is to hedge the exchange rate risk related to future obligations arising from civil works contracts linked to the construction of the Los Cóndores Plant. Although these hedges have an economic substance, they do not qualify

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for hedge accounting because they do not strictly comply with the hedge accounting requirements established in IFRS 9 Financial Instruments.

c)Other information on derivatives:

The following tables present the fair value of hedging and non-hedging derivatives entered into by the Group as well as the remaining contractual maturities as of December 31, 2019 and 2018:

	December 31, 2019
		Notional Amount
	Fair value	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Total
Financial derivatives	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	(7,412,638)	112,311,000	112,311,000	299,496,000	—	—	524,118,000
Cash flow hedge	(7,412,638)	112,311,000	112,311,000	299,496,000	—	—	524,118,000
Exchange rate hedge:	(60,827,741)	490,799,070	40,581,708	—	—	517,637,686	1,049,018,464
Cash flow hedge	(60,827,741)	490,799,070	40,581,708	—	—	517,637,686	1,049,018,464
Derivatives not designated for hedge accounting	(2,150,524)	31,746,086	2,061,840	—	—	—	33,807,926
Total	(70,390,903)	634,856,156	154,954,548	299,496,000	—	517,637,686	1,606,944,390
	December 31, 2018
		Notional Amount
	Fair value	Less than 1 year	1-2 years	2-3 years	3-4 years	4-5 years	Total
Financial derivatives	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Interest rate hedge:	5,043,662	69,477,000	104,215,500	104,215,500	—	—	277,908,000
Cash flow hedge	5,043,662	69,477,000	104,215,500	104,215,500	—	—	277,908,000
Exchange rate hedge:	(45,655,587)	1,227,557,071	76,355,223	—	—	—	1,303,912,294
Cash flow hedge	(45,655,587)	1,227,557,071	76,355,223	—	—	—	1,303,912,294
Derivatives not designated for hedge accounting	(290,478)	34,525,045	29,457,793	1,913,220	—	—	65,896,058
Total	(40,902,403)	1,331,559,116	210,028,516	106,128,720	—	—	1,647,716,352

The hedging and non-hedging derivatives contractual maturities do not represent the Group’s total risk exposure, as the amounts presented in the above tables have been drawn up based on undiscounted contractual cash inflows and outflows for their settlement.

23.3 Fair value hierarchy

Financial instruments recognized at fair value in the consolidated statement of financial position are classified, based on the hierarchy described in Note 3.h.

The following table presents financial assets and liabilities measured at fair value as of December 31, 2019 and 2018:

		Fair Value Measured at End ofReporting Period Using:
	12-31-2019	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets:
Financial derivatives designated as cash flow hedges	5,193,713	—	5,193,713	—
Financial derivatives not designated for hedge accounting	—	—	—	—
Commodity derivatives  not designated as cash flow hedges	1,573,704	—	1,573,704	—
Commodity derivatives designated as cash flow hedges	1,323,556	—	1,323,556
Available-for-sale financial assets, non-current	2,477,077	2,349,223	127,854	—
Total	10,568,050	2,349,223	8,218,827	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	73,434,092	—	73,434,092	—
Financial derivatives not designated for hedge accounting	2,150,524	—	2,150,524	—
Commodity derivatives not designated for hedge accounting	—	—	—	—
Commodity derivatives designated as cash flow hedges	8,924,831	—	8,924,831	—
Total	84,509,447	—	84,509,447	—

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		Fair Value Measured at End ofReporting Period Using:
	12-31-2018	Level 1	Level 2	Level 3
Financial Instruments Measured at Fair Value	ThCh$	ThCh$	ThCh$	ThCh$
Financial Assets:
Financial derivatives designated as cash flow hedges	43,213,555	—	43,213,555	—
Financial derivatives not designated for hedge accounting	77,109	—	77,109	—
Commodity derivatives  not designated as cash flow hedges	1,450,474	—	1,450,474	—
Commodity derivatives designated as cash flow hedges	1,423,613	—	1,423,613
Available-for-sale financial assets, non-current	359,870	—	359,870	—
Total	46,524,621	—	46,524,621	—
Financial Liabilities:
Financial derivatives designated as cash flow hedges	83,825,480	—	83,825,480	—
Financial derivatives not designated for hedge accounting	367,587	—	367,587	—
Commodity derivatives not designated for hedge accounting	548,048	—	548,048	—
Commodity derivatives designated as cash flow hedges	7,161,949	—	7,161,949	—
Total	91,903,064	—	91,903,064	—

24.  TRADE AND OTHER CURRENT AND NON-CURRENT PAYABLES.

The detail of Trade and Other Current Payables as of December 31, 2019 and 2018, is as follows:

	Current		Non-current
	12-31-2019	12-31-2018	12-31-2019	12-31-2018
Trade and Other Payables	ThCh$	ThCh$	ThCh$	ThCh$
Energy suppliers (1)	178,153,813	155,123,059	53,941,373	—
Fuel and gas suppliers	55,179,023	39,787,839	—	—
Payables for goods and services	183,848,556	155,054,466	487	6,766
Payables for assets acquisition	100,307,602	116,157,897	2,281,051	2,106,099
Subtotal Trade Payables	517,488,994	466,123,261	56,222,911	2,112,865
Other Payables
Dividends payable to third parties	41,582,444	52,059,048	—	—
Warranty deposits	360,863	365,857	—	—
Fines and complaints	—	165,102	—	—
Taxes payables other than income tax	44,506	1,742,603	—	—
Accounts payable to staff	33,090,217	30,686,679	—	—
Other payables	6,696,184	3,143,774	27,174	471,315
Subtotal Other Payables	81,774,214	88,163,063	27,174	471,315
Total	599,263,208	554,286,324	56,250,085	2,584,180

(1)  Corresponding to lags in payments for purchases of electric energy resulting from the methodology for calculating the “Stabilized Price to Regulated Customer” according to Law No 21,185 (see Note 11).

See Note 22.4 for the description of the liquidity risk management policy.

The detail of trade payables, both non-past due and past due as of December 31, 2019 and 2018, are presented in Appendix 3.

25.  PROVISIONS.

a) The breakdown of provisions as of December 31, 2019 and 2018, is as follows:

	Current		Non-current
	12-31-2019	12-31-2018	12-31-2019	12-31-2018
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Provision for legal proceedings	2,320,885	3,884,018	11,210,305	13,468,858
Decommissioning or restoration (1)	—	—	160,649,977	92,402,517
Other provisions	1,745,080	1,704,768	—	—
Total	4,065,965	5,588,786	171,860,282	105,871,375

(1) See Note 3.a

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The provisions for decommissioning originate from the fact that, considering the new environmental institutions in Chile, the scope of the rights and obligations associated with environmental licenses have been clarified in recent times. In light of the foregoing, the provisions have been adjusted to reflect the best estimate at the closing date of the financial statements.

The expected amount and timing of any cash disbursements related to the foregoing provisions is uncertain and depends on the resolution of specific issues related to each of them. For example, in the specific case of litigation, this depends on the final resolution of the corresponding legal claim. Management considers that the provisions recognized in the financial statements adequately cover the corresponding risks.

Changes in provisions as of December 31, 2019 and 2018, are as follows:

	Legal Proceedings	Decommissioning or Restoration	Environment and Other Provisions	Total
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Balance at January 1, 2019	17,352,876	92,402,517	1,704,768	111,460,161
Increase (decrease) in existing provisions (1)	3,749,833	62,688,286	40,168	66,478,287
Provisions used	(3,946,144)	(31,436)	(11)	(3,977,591)
Reversal of unused provision	(3,612,445)	—	—	(3,612,445)
Increase from adjustment to time value of money (2)	—	4,356,650	—	4,356,650
Foreign currency translation	(12,930)	1,233,960	155	1,221,185
Total changes in provisions	(3,821,686)	68,247,460	40,312	64,466,086
Balance at December 31, 2019	13,531,190	160,649,977	1,745,080	175,926,247
	Legal Proceedings	Decommissioning or Restoration	Environment and Other Provisions	Total
Provisions	ThCh$	ThCh$	ThCh$	ThCh$
Balance at January 1, 2018	17,433,976	64,486,647	2,138,385	84,059,008
Increase (decrease) in existing provisions (1)	1,842,257	23,395,295	(253,939)	24,983,613
Provisions used	(1,150,386)	—	(501,234)	(1,651,620)
Reversal of unused provision	(743,927)	—	—	(743,927)
Increase from adjustment to time value of money (2)	—	3,176,001	—	3,176,001
Foreign currency translation	(29,044)	1,344,574	321,556	1,637,086
Total changes in provisions	(81,100)	27,915,870	(433,617)	27,401,153
Balance at December 31, 2018	17,352,876	92,402,517	1,704,768	111,460,161

(1) The variation experienced by the dismantling or restoration provisions during the year ended December 31, 2019, is mainly due to the increase in disbursements expected from the early closure of the Tarapacá and Bocamina I plants, which is part of the Group's agreement with the Ministry of Energy for the progressive closure of coal-fired power plants (see Note 18.e.x); and to a lesser extent due to an increase in the present value of the provisions, for a low discount rates applied.

(2) Corresponding to financial update, see Note 34

26.  EMPLOYEE BENEFIT OBLIGATIONS.

26.1 General information:

The Group provides various post-employment benefits for all or some of their active or retired employees. These benefits are calculated and recorded in the financial statements according to the criteria described in Note 3.m.1, and include primarily the following:

Defined benefit plans:

· Complementary pension: The beneficiary is entitled to receive a monthly amount that supplements the pension obtained from the respective social security system.

· Employee severance indemnities: The beneficiary receives a certain number of contractual salaries upon retirement. Such benefit is subject to a minimum vesting service requirement period, which depending on the Group, varies within a range from 5 to 15 years.

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· Electricity: The beneficiary receives a monthly bonus to cover a portion of their billed residential electricity consumption.

· Health benefit: The beneficiary receives health coverage in addition to that to which they are entitled to under applicable social security system.

2.2 Details, changes and presentation in financial statements:

a)    The post-employment obligations associated with the defined benefits plan as of December 31, 2019 and 2018, are as follows:

	12-31-2019	12-31-2018
	ThCh$	ThCh$
Compensation for years of services	42,697,317	33,839,498
Supplementary Pension	17,853,600	16,993,409
Health Plans	3,090,670	2,979,630
Energy Supply Plans	2,521,903	2,790,127
Total post-employment obligations, net	66,163,490	56,602,664

b) The following amounts were recognized in the consolidated statement of comprehensive income for the years ended December 31, 2019 and 2018:

	For the years ended December 31,
Expense Recognized in the Statement of	2019	2018	2017
Comprehensive Income	ThCh$	ThCh$	ThCh$
Current service cost for defined benefits plan	1,928,868	1,920,262	2,091,205
Interest cost for defined benefits plan (1)	2,639,738	2,750,376	2,678,300
Past service cost	1,224,527	(39,060)	—
Expenses recognized in the Statement of Income	5,793,133	4,631,578	4,769,505
Gains (losses) from remeasurement of defined benefit plans	7,777,204	(37,881)	(1,716,875)
Total expense recognized in the Statement of Comprehensive Income	13,570,337	4,593,697	3,052,630

(1) See Note 34

c)    The balance and changes in post-employment defined benefit obligations as of and for the years ended December 31, 2019 and 2018, are as follows:

Actuarial Value of Post-employment Obligations	ThCh$
Balance at January 1, 2018	57,081,924
Current service cost	1,920,262
Net Interest cost	2,750,376
Actuarial (gains) losses from changes in financial assumptions	789,809
Actuarial (gains) losses from changes in experience adjustments	(827,690)
Foreign currency translation	124,929
Benefits paid	(5,469,357)
Past service	(39,060)
Defined benefit plan obligations from business combinations	602,816
Transfers of employees	(331,345)
Balance at December 31, 2018	56,602,664
Service cost	1,928,868
Interest cost	2,639,738
Actuarial (gains) losses from changes in financial assumptions	5,724,985
Actuarial (gains) losses from changes in experience adjustments	2,052,219
Foreign currency translation	9,786
Past service	1,224,527
Benefits paid	(4,068,988)
Transfer of employees	49,691
Closing balance December 31, 2019	66,163,490

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26.3 Other disclosures:

· Actuarial assumptions:

As of December 31, 2019 and 2018, the following assumptions were used in the actuarial calculation of defined benefits:

	12-31-2019	12-31-2018
Discount rates used	3.40%	4.70%
Expected rate of salary increases	3.80%	3.80%
Turnover rate	5.24%	4.40%
Mortality tables	CB-H-2014 / RV-M-2014	CB-H-2014 / RV-M-2014

· Sensitivity

As of December 31, 2019 and 2018, the sensitivity value of the actuarial liability for post-employment benefits to variations of 100 basis points in the discount rate assumes a decrease of ThCh$5,330,365 and ThCh$4,296,927, respectively, if the rate rises, and an increase of ThCh$5,829,095 and ThCh$4,773,734, respectively, if the rate falls.

· Future disbursements

According to the available estimate, the disbursements planned to meet the defined benefit plans for the 2020 period amount to ThCh$6,004,886.

· Term of commitments

The Group’s obligations have a weighted average length of 8.72 years, and the flow for benefits for the next ten years and more is expected to be as follows:

Years	ThCh$
1	6,004,886
2	5,304,228
3	5,264,382
4	4,304,571
5	5,181,657
6 to10	23,620,901

27.  EQUITY.

27.1 Equity attributable to the shareholders of Enel Chile

27.1.1 Subscribed and paid capital and number of shares

As of December 31, 2019 the capital of Enel Chile was ThCh$3,882,103,470 divided into 69,166,557,220 authorized shares. The capital of Enel Chile as of December 31, 2018 was ThCh$3,954,491,479 divided into 70,134,077,818 authorized shares. All the shares issued by Enel Chile are subscribed and paid in and can be traded on the Santiago Stock Exchange, the Chilean Electronic Stock Exchange and in the form of ADRs on the New York Stock Exchange (NYSE).

27.1.2 Treasury shares

As of December 31, 2019, there were no treasury shares. As of December 31, 2018, treasury shares were ThCh$72,388,009 divided into 967,520,598 shares, and were acquired as part of the merger process with Enel Green Power Latin América Ltda. (“EGPL”). The treasury shares issued were automatically cancelled because they were not sold within one year from their acquisition, in accordance with the provisions of Article 27 of the Chilean Corporations Law (Law No. 18,046).

27.1.3 Changes in the Capital Issued as a result of the Corporate Reorganization

As a result of the corporate reorganization (as described in Note 6), the Company increased its share capital through the voluntary Tender Offer of Shares on the shares of the subsidiary Enel Generación Chile (Enel

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Generación) and the merger with EGPL, whereby the renewable assets of Enel S.p.A. in Chile were merged into Enel Chile:

-Tender Offer over Enel Generación Shares:

During the Tender Offer period, which occurred between February 16 and March 22, 2018, the Company received acceptances and sale orders for a total of 2,582,336,287 shares of Enel Generación and 5,691,996 ADSs equivalent to 170,759,880 shares of Enel Generación. As a result, the Company increased its interest, becoming the holder of 2,753,096,167 shares issued by Enel Generación. In accordance with the terms and conditions set forth in the transaction, the shareholders of Enel Generación who agreed to sell their shares were allocated 40% of the established purchase price(Ch$590 per share) to subscribe for newly issued shares of Enel Chile, receiving for said 40% of the established purchase price, 2.87807 shares of Enel Chile for each share issued by Enel Generación sold in the Tender Offer. As a result, the shareholders of Enel Generación received Ch$1,624,326,738,530 in cash, divided into Ch$1,523,578,409,330 to domestic shareholders and Ch$100,748,329,200 to foreign shareholders. In turn, these shareholders subscribed for shares of Enel Chile for a total of Ch$649,730,695,412 equivalent to 7,923,600,070 shares.

-Preemptive Subscription Right:

The Chilean Corporations Law gives existing shareholders of a company a preemptive right to subscribe for shares issued in a capital increase, in proportion to their interest in the company.

Any shareholder existing at the date of Enel Chile’s capital increase was able to exercise such right by paying exclusively in cash for those shares.

As of March 16, 2018, the number of shares that exercised their preemptive subscription rights was 47,860,124 shares, paying Ch$82.00 for each share, and therefore the capital increased by Ch$3,924,530,168.

-Merger with Enel Green Power Latin America:

The corporate reorganization included the merger of EGPL with Enel Chile, a process that took place after the Tender Offer was declared successful, which took effect on April 2, 2018. As a result of this merger, Enel Chile’s share capital increased by Ch$1,071,727,278,668, divided into 13,069,844,862 shares, which were exchange for 827,205,371 shares of EGPL owned by Enel S.p.A., using an exchange ratio of 15.8 shares of Enel Chile for each share of EGPL.

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The changes in the number of shares of Enel Chile as a result of the corporate reorganization process described above are detailed below:

Number of outstanding shares of Enel Chile prior to the reorganization			49,092,772,762
	Number of shares	Ratio for exchange of shares	Number of shares
Public Tender Offer Shares of Enel Generation (1):
Purchased shares - national market	2,582,336,287	2.88	7,432,144,598
Purchased shares - ADS	170,759,880	2.88	491,455,473
Total Public Tender Offer for Shares	2,753,096,167		7,923,600,071
Enel Chile Preemtive right shares (2):
Shares paid for by shareholders	47,860,124		47,860,124
Total Preemtive Rights	47,860,124		47,860,124
Merger with EGPL (3):
Shares issued to Enel SpA	827,205,371	15.8	13,069,844,861
Total Merger with EGPL	827,205,371		13,069,844,861
Repurchase of shares (4):
Withdrawal Rights exercised by minority shareholders of Enel Chile	(967,520,598)		(967,520,598)
Total repurchase of shares	(967,520,598)		(967,520,598)
Number of issued shares in Enel Chile after merger			69,166,557,220
Total number of shares issued			70,134,077,818
Total number of treasury shares			(967,520,598)
Number of issued shares in Enel Chile after merger			69,166,557,220

(1) The total amount associated with the issuance of these new shares was ThCh$649,730,695.

(2) The payment made by minority shareholders of Enel Chile was ThCh$3,924,530.

(3) The valuation of the capital increase due to the merger was ThCh$1,071,727,279.

(4) The total amount paid for the share repurchase was ThCh$72,388,009.

27.2 Dividends

Dividend No.	Type of Dividend	Agreement date	Payment Date	Total Amount M$	Pesos per Share	Charged to Fiscal
4	Interim	12-20-2017	12-20-2017	37,134,944	0.75642	2017
5	Final	04-25-2018	04-25-2018	155,025,509	2.24134	2017
6	Interim	11-29-2018	11-29-2018	31,288,371	0.45236	2018
7	Final	04-29-2019	04-29-2019	185,737,592	2.68537	2018
8	Final	11-26-2019	11-26-2019	30,933,437	0.44723	2019

27.3 Foreign currency translation reserves

The following table sets forth foreign currency translation adjustments attributable to the shareholders of the Company for the years ended December 31, 2019, 2018 and 2017

	For the years ended December 31,
	2019	2018	2017
Reserves for Accumulated Currency Translation Differences	ThCh$	ThCh$	ThCh$
GasAtacama Chile S.A.	(3,292,629)	302,222	6,416,189
GNL Chile S.A.	1,022,047	900,483	560,194
Enel Green Power Chile Group	168,387,151	100,452,131	—
TOTAL	166,116,569	101,654,836	6,976,383

27.4 Restrictions on consolidated subsidiaries transferring funds to the parent

Certain of the Group’s subsidiaries must comply with financial ratio covenants which require them to have a minimum level of equity or other requirements that restrict the transferring of assets to the Company. The Group’s share of the restricted net assets as of December 31, 2019 and 2018 from its subsidiary Enel Generación Chile S.A. totaled ThCh$752,696,419 and ThCh$712,519,037, respectively.

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27.5 Other reserves

Other reserves within Equity attributable to Enel Chile for the years ended December 31, 2019 and 2018, are as follows:

	Balance at January 1, 2019	2019 Changes	Balance at December 31, 2019
Other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	101,654,836	64,461,733	166,116,569
Cash flow hedges	(191,870,545)	(99,135,975)	(291,006,520)
Financial assets at fair value of other comprehensive income	11,041	(2,657)	8,384
Other miscellaneous reserves	(2,285,467,896)	4,840,328	(2,280,627,568)
TOTAL	(2,375,672,564)	(29,836,571)	(2,405,509,135)
	Balance at January 1, 2018	2018 Changes	Balance at December 31, 2018
Other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	6,976,383	94,678,453	101,654,836
Cash flow hedges	(32,849,736)	(159,020,809)	(191,870,545)
Financial assets at fair value of other comprehensive income	11,284	(243)	11,041
Other miscellaneous reserves	(971,468,479)	(1,313,999,417)	(2,285,467,896)
TOTAL	(997,330,548)	(1,378,342,016)	(2,375,672,564)
	Balance at January 1, 2017	2017 Changes	Balance at December 31, 2017
Other reserves	ThCh$	ThCh$	ThCh$
Exchange differences on translation	9,222,933	(2,246,550)	6,976,383
Cash flow hedges	(76,218,470)	43,368,734	(32,849,736)
Available-for-sale financial assets	9,955	1,329	11,284
Other comprehensive income from non-current assets held for sale (*)	1,632,724	(1,632,724)	—
Other miscellaneous reserves (c)	(969,740,120)	(1,728,359)	(971,468,479)
TOTAL	(1,035,092,978)	37,762,430	(997,330,548)

(*) See note 5.

a) Exchange differences on translation: These reserves arise primarily from exchange differences relating to: (i) Translation of the financial statements of our subsidiaries from their functional currencies to our presentation currency (i.e. Chilean peso) (see Note 2.7.3).

b) Cash flow hedging reserves: These reserves represent the cumulative effective portion of gains and losses recognized in cash flow hedges (see Notes 3.g.5 and 3.h).

c) Other miscellaneous reserves:The main items and their effects are the following:

	For the years ended
	2019	2018	2017
Other Miscellaneous Reserves	ThCh$	ThCh$	ThCh$
Reserve for corporate reorganization (“Spin-Off”) (i)	(534,057,733)	(534,057,733)	(534,057,733)
Reserve for transition to IFRS (ii)	(457,221,836)	(457,221,836)	(457,221,836)
Reserve for subsidiaries transactions (iii)	12,502,494	12,502,494	12,502,494
Reserves for Tender Offer of Enel Generation “Reorganization of Renewable Assets” (iv)	(910,437,224)	(910,437,224)	—
Reserves “Reorganization of Renewable Assets” (v)	(407,354,462)	(407,354,462)	—
Hyperinflation Argentina (vi)	8,939,332	3,508,753	—
Other Miscellaneous Reserves (vii)	7,001,861	7,592,112	7,308,596
TOTAL	(2,280,627,568)	(2,285,467,896)	(971,468,479)

(i) Reserve for corporate restructuring (Spin-Off): Represents the effect generated by the corporate reorganization of Enersis S.A. (currently Enel Américas), effected in 2016, through which the company divided its business between Chile and other subsidiaries in South America. The new company was named Enersis Chile (currently Enel Chile), which was assigned the equity corresponding to the business related to Chile.

(ii) Reserve for transition to IFRS: In accordance with Official Bulletin No. 456 from the CMF, included in this line item is the monetary correction corresponding to the accumulated paid-up capital from the date of our transition to IFRS, January 1, 2004, to December 31, 2008.

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(iii) Reserve for subsidiaries transactions: Corresponds to the effect of acquisitions of equity interests in subsidiaries entities under common control.

(iv) Reserve Tender Offer for Enel Generación “Reorganization of Renewable Assets”: Represents the difference between the book value of the non-controlling interests acquired as part of the Tender Offer directed at the acquisition of all the shares issued by the subsidiary Enel Generación (see Note 6.i).

(v) Reserve “Reorganization of Renewable Assets”: Corresponds to the reserve constituted by the merger of Enel Green Power Latin America with Enel Chile, materialized on April 2, 2018. It represents the recognition of the resulting difference between the capital increase in Enel Chile (correspond to market value participation over Enel Green Power Chile and subsidiaries) and the carrying amount of Enel Green Power Latin America that became part of the share capital in the distributable net assets to the owners of Enel Chile, as a result of the merger (see Note 6. iii).

(vi) Hyperinflation Argentina: Corresponds to the effect calculated by the application of IAS 29 “Financial Information in Hyperinflationary Economies” on the subsidiary owned by the Enel Generación Group in Argentina (see Note 7).

(vii) Other miscellaneous reserves from transactions made in prior years.

27.6 Non-controlling Interests

The detail of non-controlling interests at December 31, 2019, 2018 and 2017, is as follows:

		Non-controlling Interests
		Equity			Profit (Loss)
	12-31-2019	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017
Companies	%	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile S.A.	0.91%	7,691,319	6,965,769	6,223,363	1,079,941	1,112,709	961,490
Enel Generación Chile S.A.	6.45%	126,700,973	127,136,175	784,999,394	12,667,880	42,883,953	167,465,216
Empresa Eléctrica Pehuenche S.A.	7.35%	10,079,858	10,310,215	9,963,472	6,241,062	6,885,422	5,649,253
Sociedad AgrÍcola de Cameros Ltda.	42.50%	1,837,612	2,342,160	2,596,764	(504,550)	(254,604)	(39,706)
Geotermica del Norte SA	15.41%	57,871,809	53,693,407	—	(264,158)	(187,989)	—
Empresa Nacional de Geotermia SA	49.00%	995,614	993,295	—	(74,963)	41,780	—
Parque Eolico Talinay Oriente SA	39.09%	57,586,860	51,702,606	—	868,127	662,374	—
Others		(178,379)	(208,365)	(205,346)	(73,726)	(5,825)	(984)
TOTAL		262,585,666	252,935,262	803,577,647	19,939,613	51,137,820	174,035,269

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28.  REVENUE AND OTHER OPERATING INCOME.

The detail of revenues from ordinary activities and other revenues for the years ended December 31, 2019, 2018 and 2017, is as follows:

	For the years ended December 31,
	2019	2018	2017
Revenues	ThCh$	ThCh$	ThCh$
Energy sales	2,405,903,242	2,202,078,088	2,262,090,558
Generation	1,090,021,527	1,034,975,160	1,082,749,256
Regulated customers (1)	589,368,952	643,494,066	726,166,640
Non-regulated customers	475,208,116	357,725,928	285,623,737
Spot market sales	25,444,459	33,755,166	70,958,879
Distribution	1,315,881,715	1,167,102,928	1,179,341,302
Residential (1)	552,124,205	455,840,910	435,769,231
Business	450,108,855	378,092,990	386,608,105
Industrial	181,595,960	209,252,478	225,736,231
Other consumers (2)	132,052,695	123,916,550	131,227,735
Other sales	124,113,792	123,345,383	107,362,797
Natural gas sales	97,564,262	103,717,558	91,652,707
Sales of products and services	26,549,530	19,627,825	15,710,090
Revenue from other services	94,559,289	84,936,988	114,648,227
Tolls and transmission	31,232,252	20,311,403	39,812,005
Metering equipment leases	2,131,427	5,024,944	4,945,609
Public lighting	11,262,418	12,181,969	13,449,852
Engineering and consulting services	10,385,950	10,027,472	3,414,472
Services for construction of junctions	16,497,051	14,711,796	15,514,433
Works in specific facilities and networks	7,455,200	8,425,251	13,932,537
Income from work in progress	2,727,203	1,947,722	2,883,530
Other services	12,867,788	12,306,431	20,695,789
Total Revenues	2,624,576,323	2,410,360,459	2,484,101,582
Other Operating Income	ThCh$	ThCh$	ThCh$
Commodity derivatives	5,967,739	9,819,777	20,328,649
Income from early termination of electricity supply contracts (3)	121,117,605	—	—
Other income (4)	19,172,693	36,981,190	18,548,051
Total other income	146,258,037	46,800,967	38,876,700

(1) In 2019, this amount includes the  effect of ThCh$142,367,584 corresponding to the differences between the prices of the electricity supply contracts and the regulated prices, which will be invoiced in the future following the scheme established in Law 21,185 (see note 10). Of this amount, ThCh$87,906,446 correspond to revenues that the Group must transfer to final customers through its subsidiary Enel Distribución Chile.

(2) For the year ended December 31, 2019, it includes revenues from energy sales to municipalities of ThCh$45,768,456 (ThCh$36,878,861 and ThCh$36,165,698) for the years ended December 31, 2018 and 2017, respectively); government entities for ThCh$20,432,048 (ThCh$20,246,633 and ThCh$20,080,121 for the years ended  December 31, 2018 and 2017, respectively); companies in the agricultural sector for ThCh$9,100,691 (ThCh$6,173,077 and ThCh$5,811,319 for the years ended  December 31, 2018 and 2017, respectively); public services companies and telecommunications for ThCh$24,818,503 (ThCh$26,636,066 and ThCh$33,649,705 for the years ended  December 31, 2018 and 2017 respectively), educational area ThCh$9,367,933 (ThCh$12,470,709 and ThCh $ 14,015,433 for the years ended  December 31, 2018 and 2017, respectively), health services ThCh $ 18,975,909 (ThCh $ 19,629,502 and ThCh $18,290,164 for the years ended  December 31, 2018 and 2017, respectively) and others for ThCh $ 3,589,156 (ThCh $ 1,881,702 and ThCh $ 3,215,295 for the years ended  December 31, 2018 and 2017, respectively)

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(3) In February 2019, Anglo American Sur S.A. notified Enel Generación Chile of its decision to terminate in advance three electricity supply contracts, which both parties had signed in 2016. As stipulated in the exit and termination clauses of the respective contracts, the advance termination notice granted to Enel Generación Chile the right to receive an exit compensation, consisting of the payment of a cash amount by Anglo American Sur SA, determinable according to a predetermined calculation mechanism.

It is important to note that, between the date of notification of the anticipated term and the effective termination date of the contracts, there were no performance obligations pending delivery by Enel Generación Chile, since the original contracts established the start of supply in January of the year 2021. Based on the foregoing, (following the accounting criteria described in note 3.q),  revenue  of ThCh$121,117,605 was recognized.

Finally, on June 21, 2019, Enel Generación Chile made an unsuccessful transfer of the cash flows under  this agreement. As a result of the foregoing, the  derecognition of the account receivable from Anglo American Sur S.A. that existed at that date was offset against the exit compensation amount rather than there being an exchange of cash.

(4) For the year ended December 31, 2019, it includes facilities leases of ThCh$3,835,198 (ThCh$0 for the years ended  December 31, 2018 and 2017), recovery of revenues from customers with unregistered consumption of ThCh$2,746,764 (ThCh$2,847,740 and ThCh$1,968,203 for the years ended  December 31, 2018 and 2017, respectively), late payment cancellation revenues of ThCh$485,684 (ThCh$675,202 and ThCh$1,299,470 for the years ended  December 31, 2018 and 2017, respectively), Central Claims of Tarapacá for ThCh$4,380,934 (ThCh$21,987,899 and ThCh$0  for the years ended December 31, 2018 and 2017, respectively), and other revenue for ThCh$7,724,113 (ThCh$11,470,349 and ThCh$15,280,378 for the years ended  31 December 2018 and 2017, respectively).

29.  RAW MATERIALS AND CONSUMABLES USED.

The detail of raw materials and consumables used for the years ended December 31, 2019, 2018 and 2017, is as follows:

	For the years ended December 31,
	2019	2018	2017
Raw materials and consumables used	ThCh$	ThCh$	ThCh$
Energy purchases	(835,284,742)	(747,646,603)	(902,434,871)
Fuel consumption	(230,944,415)	(231,028,169)	(280,739,362)
Gas	(134,127,365)	(140,145,010)	(170,456,730)
Oil	(3,326,061)	(11,146,001)	(21,227,747)
Coal	(93,490,989)	(79,737,158)	(89,054,885)
Transportation costs	(196,848,788)	(166,875,801)	(155,879,249)
Gas sales costs	(74,998,608)	(80,477,713)	(75,662,185)
Other raw materials and consumables	(83,128,698)	(66,148,830)	(100,071,254)
Total	(1,421,205,251)	(1,292,177,116)	(1,514,786,921)

30.  EMPLOYEE BENEFITS EXPENSE.

Employee expenses for the years ended December 31, 2019, 2018 and 2017, are as follows:

	For the years ended December 31,
	2019	2018	2017
Employee Benefits Expense	ThCh$	ThCh$	ThCh$
Wages and salaries	(109,101,737)	(102,897,710)	(100,653,880)
Post-employment benefit obligations expense	(3,153,395)	(1,881,202)	(2,091,205)
Social security and other contributions	(14,334,587)	(13,405,944)	(13,150,402)
Other employee expenses	(3,015,237)	(4,945,478)	(5,608,290)
Total	(129,604,956)	(123,130,334)	(121,503,777)

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31.  DEPRECIATION, AMORTIZATION AND IMPAIRMENT LOSSES- PROPERTY, PLANT AND EQUIPMENT AND FINANCIAL ASSETS IN ACCORDANCE WITH IFRS 9

a) The detail of depreciation, amortization and impairment losses for the years ended December 31, 2019, 2018 and 2017, are as follows:

	For the years ended December 31,
	2019	2018	2017
	ThCh$	ThCh$	ThCh$
Depreciation	(224,724,380)	(202,971,892)	(145,873,065)
Amortization	(11,903,007)	(12,215,408)	(6,811,041)
Total	(236,627,387)	(215,187,300)	(152,684,106)

b) The detail of the items related to impairment for the years ended December 31, 2019, 2018 and 2017 is as follows:

	For the years ended December 31,
	Generation			Distribution			Other			Total
	2019	2018	2017	2019	2018	2017	2019	2018	2017	2019	2018	2017
(*) Impairment Losses	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Property, Plant and Equipment (see Note 18)	(280,020,263)	—	—	—	—	—	—	—	—	(280,020,263)	—	—
Investment Property (see Note 19)	—	—	—	—	—	—	(742,389)	(779,825)	—	(742,389)	(779,825)	—
Total Reversal of impairment losses (impairment losses) recognized in profit or loss	(280,020,263)	—	—	—	—	—	(742,389)	(779,825)	—	(280,762,652)	(779,825)	—
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9 (see Note 11.d)	(1,338,599)	(106,264)	55,494	(8,153,419)	(4,676,808)	(7,993,311)	(554,982)	—	—	(10,047,000)	(4,783,072)	(7,937,817)

32.  OTHER EXPENSES.

Other miscellaneous operating expenses for the years ended December 31, 2019, 2018 and 2017, are as follows:

	For the years ended December 31,
	2019	2018	2017
Other Expenses	ThCh$	ThCh$	ThCh$
Professional, outsourced and other services	(60,808,462)	(69,692,677)	(74,722,143)
Administrative expenses	(8,893,785)	(5,991,676)	(2,267,390)
Repairs and maintenance	(50,846,851)	(41,829,409)	(17,906,263)
Indemnities and fines	(1,243,376)	(455,825)	(776,011)
Taxes and charges	(6,802,176)	(4,415,819)	(5,105,235)
Insurance premiums	(19,200,681)	(15,794,761)	(13,277,718)
Leases and rental costs	(3,824,195)	(3,775,007)	(2,013,411)
Marketing, public relations and advertising	(3,274,693)	(2,440,070)	(2,501,027)
Write-off Property, Plant and Equipment (*)	(3,510,591)	—	(25,105,911)
Travel expenses	(3,991,349)	(2,436,407)	(3,426,179)
Environmental expenses	(9,886,690)	(9,664,683)	(7,769,230)
Other supplies and services	(11,860,291)	(10,713,687)	(6,953,556)
Total	(184,143,140)	(167,210,021)	(161,824,074)

(*)See explanation in Notes 18 e) xi) and vii) for the years 2019 and 2017, respectively

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33.  OTHER GAINS (LOSSES).

Other gains (losses) for the years ended December 31, 2019, 2018 and 2017, are as follows:

	For the years ended December 31,
	2019	2018	2017
Other Gains (Losses)	ThCh$	ThCh$	ThCh$
Gain on sale of Electrogas (*)	—	—	105,311,912
Gain on sale of Property, Plant and Equipment	1,530,689	3,024,549	7,779,531
Gain on sale of investment properties	262,512	385,830	149,753
Total	1,793,201	3,410,379	113,241,196

(*)See Note 5.

34.  FINANCIAL RESULTS.

Financial income and costs for the years ended December 31, 2019, 2018 and 2017, are as follows:

	For the years ended December 31,
	2019	2018	2017
Financial Income	ThCh$	ThCh$	ThCh$
Income from deposits and other financial instruments	8,973,606	9,612,575	8,377,023
Interests charged to customers in energy accounts and billing	8,057,203	7,140,984	8,556,587
Financial income by Law N°21,185 (1)	5,225,739
Other financial income	5,142,727	3,180,909	4,729,078
Total Financial Income	27,399,275	19,934,468	21,662,688

	For the years ended December 31,
	2019	2018	2017
Financial Costs	ThCh$	ThCh$	ThCh$
Financial Costs	(164,897,900)	(122,184,189)	(53,510,882)
Bank loans	(14,487,700)	(20,701,774)	(12,585)
Secured and unsecured obligations	(81,818,564)	(62,255,300)	(42,708,253)
Financial leasing	(1,815,170)	(739,069)	(811,172)
Valuation of financial derivatives	1,775,749	1,183,228	(1,067,820)
Financial provisions (2)	(4,356,650)	(3,176,001)	(2,347,087)
Post-employment benefit obligations (3)	(2,639,738)	(2,750,376)	(2,678,300)
Debt formalization expenses and other associated expenses	(4,710,012)	(9,373,412)	(836,174)
Capitalized borrowing costs	9,321,354	6,435,646	4,078,463
Financial cost related companies	(31,304,382)	(23,228,947)	(452,642)
Financial cost by Law N°21,185 (1)	(19,062,333)	—	—
Other financial costs	(15,800,454)	(7,578,184)	(6,675,312)
(Loss) gain from indexed assets and liabilities, net	(2,982,268)	(818,146)	916,666
Foreign currency exchange differences	(10,412,110)	(7,807,197)	8,516,874
Total Financial Costs	(178,292,278)	(130,809,532)	(44,077,342)
Total Financial Results	(150,893,003)	(110,875,064)	(22,414,654)

(1) Corresponding to financial costs and profits from the calculating methodology for “Stabilized Price to Regulated Customer” according to Law No 21,185 (see Note 11).

(2) See Note 25.

(3) See Note 26.

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The effects on financial results from the application of indexed assets and liabilities and exchange differences originated from the following

	For the years ended December 31,
	2019	2018	2017
Profit (losses) from Indexed Assets and Liabilities	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	36,797	—	—
Other non-financial assets	—	45,108	—
Trade and other receivables	1,410,408	1,197,498	155,158
Current tax assets and liabilities	2,557,465	3,424,644	1,654,538
Other financial liabilities (financial debt and derivative instruments)	(1,637,291)	(1,714,216)	(891,230)
Trade and other payables	16,939	15,145	(1,800)
Other non-financial liabilities	(1,688)	—	—
Sub total	2,382,630	2,968,179	916,666
Hyperinflation Result (1)	(5,364,898)	(3,786,325)	—
Gains from indexed assets and liabilities, net	(2,982,268)	(818,146)	916,666
	For the years ended December 31,
	2019	2018	2017
Foreign Currency Exchange Differences	ThCh$	ThCh$	ThCh$
Cash and cash equivalents	(937,177)	(415,962)	2,931,086
Other financial assets	2,052,540	5,733,173	10,895,862
Other non-financial assets	(1,712,690)	(534,401)	—
Trade and other receivables (2)	8,847,969	726,347	390,764
Current tax assets and liabilities	(1,633,471)	(1,903,963)	(188,270)
Other financial liabilities (financial debt and derivative instruments)	(8,147,939)	(5,726,246)	(4,358,937)
Trade and other payables (2)	(9,381,721)	(5,379,210)	(1,152,505)
Other non-financial liabilities	500,379	(306,935)	(1,126)
Total Foreign Currency Exchange Differences	(10,412,110)	(7,807,197)	8,516,874

(1) Corresponds to the financial effect from the application of IAS 29 Financial Reporting in Hyperinflationary Economies on the branch owned by Enel Generación Chile in Argentina (see Note 7)

(2) Contains the exchange effect for dollarization of trade accounts receivable and payable for amounts of ThCh$ 5,261,358 and ThCh$ (1,426,334) respectively, originated by the application of the methodology for calculating the “Stabilized Price to Regulated Customer”  according to Law No. 21,185 (see Note 11).

35.  INFORMATION BY SEGMENT

35.1 Basis of segmentation

The Group’s activities operate under a matrix management structure with dual and cross management responsibilities (based on businesses), and its subsidiaries are engaged in either the Generation Business or the Distribution Business.

The Group adopted a “bottom-up” approach to determine its reportable segments. The Generation and the Distribution reportable segments have been defined based on IFRS 8.9 and on the criteria described in IFRS 8.12.

Generation Business: The Generation Reportable Segment is comprised of a group of electricity companies that own electricity generating plants, whose energy is transmitted and distributed to end customers. The generation business is conducted in Chile by our subsidiaries Enel Generación Chile S.A., Empresa Eléctrica Pehuenche S.A. and our group engaged in the development and exploitation of renewable energies with wind energy subsidiaries: Parque Eólico Tal Tal S.p.A., Parque Eólico Valle de los Vientos S.p.A. and Parque Talinay Oriente S.A., geothermal subsidiaries: Geotérmica del Norte S.A. and Empresa Nacional de Geotermia S.A., wind and solar energy subsidiaries Enel Green Power del Sur SpA, and the subsidiary Empresa Eléctrica Panguipulli S.A. engaged in hydroelectric, solar and wind generation. The remainder are engaged in diverse projects: Diego de Almagro Matriz SpA, Almeyda Solar SpA.

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Distribution Business: The Distribution Reportable Segment is comprised of a group of electricity companies operating under a public utility concession, with service obligations and regulated tariffs for supplying regulated customers.

Each of the operating segments generates separate financial information, which is aggregated into one combined set of information for the Generation Business, and another set of combined information for the Distribution Business at the reportable segment level. In addition, in order to assist the decision maker process, the Planning & Control Department at the Parent Company level prepares internal reports containing combined information at the reportable segment level about the main key performance indicators (KPIs), such as: EBITDA, Gross Margin, Total Capex, Total Opex, Net income, Total Energy Generation, among others. The presentation of information under this business approach has been made taking into consideration that the KPIs are similar and comparable in all segments, in each of the following aspects:

(a) The nature of the activities: generation on one hand, and distribution on the other;

(b) The nature of the production processes: the Generation Business deals with the generation of electricity, while the Distribution Business does not generate electricity, but distributes electricity to end customers;

(c) The type or class of customer for their products and services: the Generation Business provides services mainly to unregulated customers, while the Distribution Business provides energy to regulated customers;

(d) The methods used to distribute their products or provide their services: generators generally sell the energy through energy auctions, while distributors provide energy in their concession area; and

(e) The nature of the regulatory environment (public utilities): the regulatory frameworks differs in the Generation Business and Distribution Business

The Company’s chief operating decision maker (CODM) in conjunction with the Chile country manager reviews on a monthly basis these internal reports and uses the KPI information to make decisions on the allocation of resources and the assessment of the performance of the operating segments for each reportable segment.

The information disclosed in the following tables is based on the financial information of the companies forming each segment. The accounting policies used to determine the segment information are the same as those used in the preparation of the Group’s consolidated financial statements.

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35.2 Generation, distribution and others

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2019	12-31-2018	12-31-2019	12-31-2018	12-31-2019	12-31-2018	12-31-2019	12-31-2018
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
ASSETS
CURRENT ASSETS	941,262,837	997,843,912	289,393,932	296,453,471	(212,444,109)	(297,349,611)	1,018,212,660	996,947,772
Cash and cash equivalents	26,391,853	155,591,949	2,331,365	4,969,412	206,961,282	84,610,563	235,684,500	245,171,924
Other current financial assets	489,658	39,507,485	64,220	62,226	756,717	733,462	1,310,595	40,303,173
Other current non-financial assets	8,908,239	14,074,044	8,868,077	5,648,807	16,858,247	2,683,237	34,634,563	22,406,088
Trade and other current receivables	230,670,997	254,374,451	260,840,410	218,310,327	19,943,923	5,485,289	511,455,330	478,170,067
Current accounts receivable from related companies	587,067,775	422,492,265	10,115,510	59,827,152	(529,001,152)	(428,148,357)	68,182,133	54,171,060
Inventories	34,705,515	48,221,915	3,150,943	3,528,174	1,815,792	5,211,554	39,672,250	56,961,643
Current tax assets	53,028,800	63,581,803	4,023,407	4,107,373	70,221,082	32,074,641	127,273,289	99,763,817
Non-current assets classified as held for sale	—	—	—	—	—	—	—	—
NON-CURRENT ASSETS	4,771,905,050	4,625,205,545	1,175,550,962	982,926,699	892,319,492	882,940,148	6,839,775,504	6,491,072,392
Other non-current financial assets	7,189,431	6,554,114	22,741	26,410	8,448	689,145	7,220,620	7,269,669
Other non-current non-financial assets	34,903,436	42,006,844	2,576,585	2,600,071	570,163	1,097	38,050,184	44,608,012
Trade and other non-current receivables	88,225,632	1,565,812	157,051,933	41,993,899	68,296,820	16,968,132	313,574,385	60,527,843
Non-Current accounts payable from related companies	80,926,788	—	—	—	(46,519,646)	—	34,407,142	—
Investments accounted for using the equity method	7,928,588	12,873,531	—	—	—	—	7,928,588	12,873,531
Intangible assets other than goodwill	76,077,944	68,776,401	51,360,795	41,963,796	4,839,854	4,632,196	132,278,593	115,372,393
Goodwill	33,135,272	32,500,603	2,240,478	2,240,478	881,977,224	880,303,644	917,352,974	915,044,725
Property, plant and equipment	4,422,575,593	4,442,872,809	961,392,557	893,246,804	(23,648,526)	(27,471,980)	5,360,319,624	5,308,647,633
Investment property	—	—	—	—	6,795,155	7,557,356	6,795,155	7,557,356
Deferred tax assets	20,942,366	18,055,431	905,873	855,241	—	260,558	21,848,239	19,171,230
TOTAL ASSETS	5,713,167,887	5,623,049,457	1,464,944,894	1,279,380,170	679,875,383	585,590,537	7,857,988,164	7,488,020,164

F-113

	Generation		Distribution		Holdings, eliminations and others		Total
	12-31-2019	12-31-2018	12-31-2019	12-31-2018	12-31-2019	12-31-2018	12-31-2019	12-31-2018
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
LIABILITIES AND EQUITY
CURRENT LIABILITIES	844,513,549	909,428,562	317,248,207	450,182,594	(120,461,904)	(142,147,004)	1,041,299,852	1,217,464,152
Other current financial liabilities	211,928,086	196,141,320	738,783	2	1,989,707	214,524,493	214,656,576	410,665,815
Trade and other current payables	300,957,548	317,337,886	200,472,938	156,939,551	97,832,722	80,008,887	599,263,208	554,286,324
Current accounts payable to related companies	296,861,070	337,986,306	87,507,312	258,410,862	(224,558,495)	(438,460,843)	159,809,887	157,936,325
Other current provisions	3,619,734	5,195,377	—	—	446,231	393,409	4,065,965	5,588,786
Current tax liabilities	17,717,789	12,563,801	34,718	5,114,119	243,326	—	17,995,833	17,677,920
Other current non-financial liabilities	13,429,322	40,203,872	28,494,456	29,718,060	3,584,605	1,387,050	45,508,383	71,308,982
NON-CURRENT LIABILITIES	1,899,077,568	1,846,575,202	301,769,861	63,065,351	868,557,231	686,751,678	3,069,404,660	2,596,392,231
Other non-current financial liabilities	998,974,951	1,028,833,254	2,993,326	—	738,201,642	677,000,249	1,740,169,919	1,705,833,503
Trade and other non-current payables	2,281,053	2,556,521	53,968,545	27,172	487	487	56,250,085	2,584,180
Non-current accounts payable to related companies	486,839,484	447,193,802	182,031,404	—	115,502,596	—	784,373,484	447,193,802
Other long-term provisions	160,006,401	91,898,262	11,853,881	13,973,113	—	—	171,860,282	105,871,375
Deferred tax liabilities	231,156,234	260,950,163	19,818,625	21,335,014	(1,690,218)	(4,205,123)	249,284,641	278,080,054
Non-current provisions for employee benefits	19,819,445	15,143,200	29,801,321	27,503,399	16,542,724	13,956,065	66,163,490	56,602,664
Other non-current non-financial liabilities	—	—	1,302,759	226,653	—	—	1,302,759	226,653
EQUITY	2,969,576,770	2,867,045,693	845,926,826	766,132,225	(68,219,944)	40,985,863	3,747,283,652	3,674,163,781
Equity attributable to Enel Chile	2,969,576,770	2,867,045,693	845,926,826	766,132,225	(68,219,944)	40,985,863	3,484,697,986	3,421,228,519
Issued capital	1,185,731,351	1,137,185,366	230,137,980	230,137,980	2,466,234,139	2,587,168,133	3,882,103,470	3,954,491,479
Retained earnings	1,735,720,458	1,626,928,911	933,560,288	852,296,368	(661,177,095)	(564,427,666)	2,008,103,651	1,914,797,613
Share Premium	85,511,492	85,511,492	354,220	354,220	(85,865,712)	(85,865,712)	—	—
Treasury shares	—	—	—	—	—	(72,388,009)	—	(72,388,009)
Other reserves	(37,386,531)	17,419,924	(318,125,662)	(316,656,343)	(1,787,411,276)	(1,823,500,883)	(2,405,509,135)	(2,375,672,564)
Non-controlling interests	—	—	—	—	—	—	262,585,666	252,935,262
Total Liabilities and Equity	5,713,167,887	5,623,049,457	1,464,944,894	1,279,380,170	679,875,383	585,590,537	7,857,988,164	7,488,020,164

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	Generation			Distribution			Holdings, eliminations and others			Total
	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF COMPREHENSIVE INCOME
REVENUES AND OTHER OPERATING INCOME	1,726,611,508	1,580,653,088	1,634,937,087	1,412,871,738	1,263,224,072	1,326,658,860	(368,648,886)	(386,715,734)	(438,617,665)	2,770,834,360	2,457,161,426	2,522,978,282
Revenues	1,581,230,963	1,540,352,133	1,599,032,140	1,408,588,042	1,254,943,604	1,322,422,609	(365,242,682)	(384,935,278)	(437,353,167)	2,624,576,323	2,410,360,459	2,484,101,582
Energy sales	1,472,565,933	1,425,942,129	1,457,671,722	1,318,386,716	1,170,129,333	1,180,426,814	(385,049,407)	(393,993,374)	(376,007,978)	2,405,903,242	2,202,078,088	2,262,090,558
Other sales	97,870,470	103,779,801	94,452,287	9,365,186	16,411,425	12,741,568	16,878,136	3,154,157	168,942	124,113,792	123,345,383	107,362,797
Other services rendered	10,794,560	10,630,203	46,908,131	80,836,140	68,402,846	129,254,227	2,928,589	5,903,939	(61,514,131)	94,559,289	84,936,988	114,648,227
Other operating income	145,380,545	40,300,955	35,904,947	4,283,696	8,280,468	4,236,251	(3,406,204)	(1,780,456)	(1,264,498)	146,258,037	46,800,967	38,876,700
RAW MATERIALS AND CONSUMABLES USED	(678,187,609)	(709,506,221)	(903,978,006)	(1,114,936,281)	(972,499,918)	(1,055,708,050)	371,918,639	389,829,023	444,899,135	(1,421,205,251)	(1,292,177,116)	(1,514,786,921)
Energy purchases	(160,044,206)	(213,114,437)	(346,954,692)	(1,056,562,636)	(926,385,346)	(938,067,783)	381,322,099	391,853,181	382,587,604	(835,284,743)	(747,646,602)	(902,434,871)
Fuel consumption	(230,944,414)	(231,028,169)	(280,739,362)	—	—	—	—	—	—	(230,944,414)	(231,028,169)	(280,739,362)
Transportation expenses	(169,062,680)	(154,044,158)	(152,869,838)	(22,725,942)	(9,816,883)	(63,009,956)	(5,060,166)	(3,014,761)	60,000,545	(196,848,788)	(166,875,802)	(155,879,249)
Other miscellaneous supplies and services	(118,136,309)	(111,319,457)	(123,414,114)	(35,647,703)	(36,297,689)	(54,630,311)	(4,343,294)	990,603	2,310,986	(158,127,306)	(146,626,543)	(175,733,439)
CONTRIBUTION MARGIN	1,048,423,899	871,146,867	730,959,081	297,935,457	290,724,154	270,950,810	3,269,753	3,113,289	6,281,470	1,349,629,109	1,164,984,310	1,008,191,361
Other work performed by the entity and capitalized	8,887,421	8,663,737	7,226,484	8,723,440	6,667,947	6,630,130	—	1,379,279	532,373	17,610,861	16,710,963	14,388,987
Employee benefits expense	(62,871,525)	(61,991,737)	(54,222,470)	(34,828,194)	(32,598,818)	(38,449,551)	(31,905,237)	(28,539,779)	(28,831,756)	(129,604,956)	(123,130,334)	(121,503,777)
Other expenses	(120,522,841)	(104,190,567)	(102,821,020)	(70,678,241)	(64,179,201)	(61,942,592)	7,057,942	1,159,747	2,939,538	(184,143,140)	(167,210,021)	(161,824,074)
GROSS OPERATING INCOME	873,916,954	713,628,300	581,142,075	201,152,462	200,614,082	177,188,797	(21,577,542)	(22,887,464)	(19,078,375)	1,053,491,874	891,354,918	739,252,497
Depreciation and amortization expense	(196,623,025)	(179,901,682)	(117,337,553)	(40,705,580)	(36,677,957)	(36,685,324)	701,218	1,392,339	1,338,771	(236,627,387)	(215,187,300)	(152,684,106)
Impairment losses (reversal of impairment losses) recognized in profit or loss	(280,020,263)	—	—	—	—	—	(742,389)	(779,825)	—	(280,762,652)	(779,825)	—
Impairment gains and reversals of impairment losses (Impairment losses) determined in accordance with IFRS 9.	(1,338,599)	(106,264)	55,494	(8,153,419)	(4,676,808)	(7,993,311)	(554,982)	—	—	(10,047,000)	(4,783,072)	(7,937,817)
OPERATING INCOME	395,935,067	533,620,354	463,860,016	152,293,463	159,259,317	132,510,162	(22,173,695)	(22,274,950)	(17,739,604)	526,054,835	670,604,721	578,630,574
FINANCIAL RESULT	(101,324,905)	(86,621,659)	(36,610,248)	5,232,127	6,088,801	6,411,837	(54,800,225)	(30,342,206)	7,783,757	(150,893,003)	(110,875,064)	(22,414,654)
Financial income	15,241,046	8,727,356	5,273,672	22,742,687	11,166,433	12,894,635	(10,584,458)	40,679	3,494,381	27,399,275	19,934,468	21,662,688
Cash and cash equivalents	3,556,554	5,673,621	3,077,708	1,456,253	1,633,373	1,975,564	3,960,799	2,305,581	3,323,751	8,973,606	9,612,575	8,377,023
Other financial income	11,684,492	3,053,735	2,195,964	21,286,434	9,533,060	10,919,071	(14,545,257)	(2,264,902)	170,630	18,425,669	10,321,893	13,285,665
Financial costs	(111,219,566)	(82,878,715)	(50,851,829)	(19,061,123)	(6,724,490)	(7,094,366)	(34,617,211)	(32,580,984)	4,435,313	(164,897,900)	(122,184,189)	(53,510,882)
Bank borrowings	(11,813,855)	(9,269,535)	(261)	(40,508)	(5,374)	(12,299)	(2,633,337)	(11,426,865)	(25)	(14,487,700)	(20,701,774)	(12,585)
Secured and unsecured obligations	(45,714,879)	(43,965,839)	(42,708,253)	—	—	—	(36,103,685)	(18,289,461)	—	(81,818,564)	(62,255,300)	(42,708,253)
Other	(53,690,832)	(29,643,341)	(8,143,315)	(19,020,615)	(6,719,116)	(7,082,067)	4,119,811	(2,864,658)	4,435,338	(68,591,636)	(39,227,115)	(10,790,044)
Profit (loss) from indexed assets and liabilities	(5,157,076)	(2,480,291)	145,608	1,843,435	1,616,607	761,262	331,373	45,538	9,796	(2,982,268)	(818,146)	916,666
Foreign currency exchange differences	(189,309)	(9,990,009)	8,822,301	(292,872)	30,251	(149,694)	(9,929,929)	2,152,561	(155,733)	(10,412,110)	(7,807,197)	8,516,874
Share of profit of associates accounted for using the equity method	366,089	3,190,240	(2,696,904)	—	—	—	—	—	—	366,089	3,190,240	(2,696,904)
Other gains (losses)	1,683,246	3,434,503	113,088,869	12	—	157,458	109,943	(24,124)	(5,131)	1,793,201	3,410,379	113,241,196
Gain (loss) from other investments	152,557	409,954	105,462,769	12	—	4,026	109,943	(24,124)	(5,131)	262,512	385,830	105,461,664
Gain (loss) from the sale of property, plant and equipment	1,530,689	3,024,549	7,626,100	—	—	153,432	—	—	—	1,530,689	3,024,549	7,779,532
Income before tax	296,659,497	453,623,438	537,641,733	157,525,602	165,348,118	139,079,457	(76,863,977)	(52,641,280)	(9,960,978)	377,321,122	566,330,276	666,760,212
Income tax	(40,347,869)	(113,783,941)	(112,099,519)	(38,748,555)	(42,967,123)	(34,030,322)	17,868,520	3,268,545	2,787,540	(61,227,904)	(153,482,519)	(143,342,301)
Net income from continuing operations	256,311,628		188,153,449	118,777,047		57,935,774	(58,995,457)		649,411	316,093,218	412,847,757	523,417,911
Net income from discontinued operations	—		—	—		—	—		—	—	—	—
NET INCOME	256,311,628	339,839,497	425,542,214	118,777,047	122,380,995	105,049,135	(58,995,457)	(49,372,735)	(7,173,438)	316,093,218	412,847,757	523,417,911
Net income attributable to:	256,311,628	339,839,497	425,542,214	118,777,047	122,380,995	105,049,135	(58,995,457)	(49,372,735)	(7,173,438)	316,093,218	412,847,757	523,417,911
Shareholders of Enel Chile	—	—	—	—	—	—	—	—	—	296,153,605	361,709,937	349,382,642
Non-controlling interests	—	—	—	—	—	—	—	—	—	19,939,613	51,137,820	174,035,269
	Generation			Distribution			Holdings, eliminations and others			Total
	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017	12-31-2019	12-31-2018	12-31-2017
Line of Business	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
STATEMENT OF CASH FLOWS
Cash flows from (used in) operating activities	754,113,794	638,607,494	488,167,382	50,246,845	117,692,384	170,628,958	(60,648,920)	(20,774,356)	(23,182,620)	743,711,719	735,525,522	635,613,720
Cash flows from (used in) investing activities	(426,038,012)	(451,284,432)	(91,867,647)	(28,896,947)	(123,070,452)	(74,464,531)	143,403,148	(1,307,204,810)	19,866,401	(311,531,811)	(1,881,559,694)	(146,465,777)
Cash flows from (used in) financing activities	(453,927,358)	(249,051,150)	(301,835,211)	(23,901,991)	(32,268,227)	(76,923,085)	37,393,661	1,247,896,253	61,162,775	(440,435,688)	966,576,876	(317,595,521)

The holdings, eliminations and other column corresponds to transactions between companies in different lines of business, primarily purchases and sales of energy and services.

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36.  THIRD PARTY GUARANTEES, OTHER CONTINGENT ASSETS AND LIABILITIES, AND OTHER COMMITMENTS.

36.1 Direct guarantees.

As of December 31, 2019 and 2018, the Group had future energy purchase commitments amounting to ThCh$7,647,064 and ThCh$8,404,005, respectively.

36.2 Indirect guarantees.

			Debtor			Outstanding balance as of
Contract	Maturity	Creditor of Guarantee	Company	Relationship	Type of Guarantee	Currency	12-31-2019	12-31-2018
Bonds Series B  (1)	October 2028	Bondholders of Enel Américas’ Bonds	Enel Américas	Entities demerged from original debtor Enersis S.A. (codebtor Enel Chile S.A.)	Codebtor	UF	11,646,991	15,821,814
Credit Agreement	September 2019	Scotiabank Chile	Enel Green Power Chile Limitada	Subsidiary	Aval	USD	-	70,214,637
Credit Agreement	December 2020	Scotiabank Chile	Enel Green Power Chile Limitada	Subsidiary	Aval	USD	112,882,048	104,258,927
Credit Agreement	November 2022	Pto. GDN BID	Enel Green Power Chile Limitada	Subsidiary	Aval	USD	22,592,723	-
Credit Agreement	December 2021	Scotiabank Chile	Empresa Eléctrica Panguipulli S.A.	Subsidiary	Aval	USD	113,069,511	104,477,333
Credit Agreement	December 2027	Enel Finance International N.V.	Enel Green Power Chile Limitada	Subsidiary	Aval	USD	484,341,824	447,431,880

(1) As a result of the Enersis’ Spin-Off and in accordance with the bond indenture, all entities arising from the demerger are liable for the debt, regardless that the payment obligation remains in Enel Américas S.A.

36.3 Lawsuits and Arbitration Proceedings.

As of the date of these consolidated financial statements, the most relevant litigation involving the Company and its subsidiaries are as follows:

1. Enel Chile S.A.

1.1. Inversiones Tricahue S.A., a minority shareholder of Empresa Eléctrica Pehuenche S.A., requested in the 20th Civil Court of Santiago the appointment of an arbitrator, to hear and resolve the arbitration claim that Inversiones Tricahue S.A. seeks to bring against Empresa Eléctrica Pehuenche S.A., Enel Generación Chile S.A., Enel Chile S.A., and the directors of these three companies, for the alleged damages that the Pehuenche management allegedly inflicted on the minority shareholders, as a result of the Project Elqui reorganization plan and the development of Pehuenche’s electricity generation business.

Once the request for the appointment of an arbitrator was presented, the three defendant companies and their directors submitted numerous objections, all of which were rejected by a ruling dated June 25, 2018. Subsequently, Mr. Nelson Contador was designated as the arbitrator and accepted the appointment. The companies and their directors appealed the appointment of the arbitrator, a hearing on the appeal was held and the appeal is pending a ruling. In parallel, the appointed arbitrator issued a ruling that summoned the parties to a hearing to set the rules of procedure and fees of the arbitrator, which will occur on the tenth day after notification of the ruling to all of the parties, which as of December 31, 2019 had not yet occurred.

2. Enel Generación Chile S.A.

2.1. By means of ORD No. 5,705 dated May 23, 2016, the Superintendency of Electricity and Fuels, filed charges against GasAtacama Chile S.A. (which merged into Enel Generación Chile S.A. on October 1, 2019) for providing allegedly erroneous information to CDEC-SING with respect to the Minimum Technical parameters (MT) and Average Operating Time parameters (TMO) during the period between January 1, 2011 and October 29, 2015, GasAtacama Chile S.A. presented its objections, which were rejected by the Superintendency’s Resolution No. 014606 dated August 4, 2016, which imposed a fine of 120,000 UTM (ThCh$5,964,760). In opposition to the resolution of the Superintendency that applied the fine, GasAtacama Chile S.A. submitted a request for reconsideration before the Superintendency, which was rejected by the Superintendency through Resolution No. 15,908, dated November 2, 2016, which confirmed the fine

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imposed. In opposition to the resolution, GasAtacama Chile S.A. filed a claim of illegality before the Court of Appeals of Santiago, which on April 9, 2019, issued a ruling that reduced the fine 120,000 UTM (10.000 UTA) imposed to fine 500 UTA (ThCh$297,738). Both the Superintendency and GasAtacama Chile S.A.filed appeals before the Supreme Court against this ruling, which on January 15, 2020 rejected both appeals, confirmed the fine of 500 UTA (ThCh $ 297,738) and also declared, that there had been no delivery of false information to the coordinator of the CDEC-SING by GasAtacama Chile S.A. during the relevant period.

3. Enel Distribución Chile S.A.

3.1 Mrs. Evelyn del Carmen Molina González, on behalf of herself and her minor daughters Maite Alué Letelier Molina and Daniela Anaís Letelier Molina, filed a claim for compensation of damages against Chilectra S.A. (now Enel Distribución Chile S.A.) and its subcontractor Sociedad de Servicios Personales para el Área Eléctrica Limitada (“SSPAEL”) for a total amount of ThCh$2,000,000  (ThCh$1,000,000 for the and for the first plaintiff and  ThCh$500,000 of  each of the latter two plaintiffs) for punitive damages due to the death of their spouse and father, respectively, Mr. David Letelier Riveros (deceased), which occurred on May 25, 2013 as a result of the injuries sustained after receiving an electric shock and falling from the height of a public street lighting post on which he was working. A judgment was issued on November 7, 2017 which found SSPAEL  and Enel Distribución Chile (Chilectra) jointly liable to pay the sum of ThCh$90,000 for punitive damages to the plaintiffs , plus adjustments and costs. On November 24, 2017 Enel Distribución Chile filed an appeal against the judgment, raising the background to the Court of Appeals of Santiago, on December 4, 2017. On December 21, 2018 the judgment was confirmed by the Court of Appeals reducing the punitive damages to ThCh$70,000. On January 10, 2019 an appeal was  filed, which as of December 31, 2019 was pending resolution.

3.2 Mrs. Ximena Acevedo Herrera, Benjamín Jiménez Acevedo, Francisco Jiménez Acevedo, Nancy Garrido Muñoz, Juan Carlos Jiménez Rocuant, Carolina Jiménez Garrido and Natalia Jiménez Garrido filed a claim for compensation of damages against Ingeniería Eléctrica Azeta Ltda and Enel Distribución Chile S.A. for a total amount of ThCh$878,227   (ThCh$28,227) for lost profits and ThCh$850,000 for punitive damages) due to the death of their spouse, father, son, and brother, Mr. Juan Pablo Jiménez Garrido (deceased), which occurred on February 22, 2013 as a result of a head trauma caused by a bullet that was lodged in his brain. Enel Distribución Chile S.A. is a defendant in its capacity as the contractor of Azeta. The trial period is over. As of December  31, 2019,  notification to  the plaintiff of abandonment of the proceeding was still pending.

3.3 Mr. Víctor Hugo Coronado González and Mrs. Francia Magali Bustos Uribe, both on behalf of themselves and their minor daughter, Nicolson Rocío Coronado Bustos, and son, Víctor Ignacio Coronado Bustos, filed a claim for compensation of damages against Enel Distribución Chile S.A. for a total amount of ThCh$704,860 (ThCh$264,860 for loss of earnings and ThCh$440,000 for punitive damages) due to the accident that occurred on June 22, 2015 and affected Mr. Víctor Hugo Coronado González who received an electrical shock and suffered severe injuries. The trial period is over. A judgment of May 22, 2019 dismissed the lawsuit against Enel Distribución Chile S.A. On June 19, 2019, the plaintiffs filed an appeal, which as of December 31, 2019 was pending resolution.

3.4 By means of Exempt Resolution No. 21,036 dated November 3, 2017, the Superintendency of Electricity and Fuels confirmed the fine of 35,611 UTM (ThCh$1,767,125) imposed on Enel Distribución Chile S.A. when it ruled against the request for reconsideration filed on January 14, 2016 against Exempt Resolution No. 11,750 dated December 29, 2015 because it determined that, in the period 2013-2014, Enel Distribución Chile had repeatedly exceeded the continuity of supply indices established by law. In opposition to the aforementioned ruling, Enel Distribución Chile filed an appeal with the Court of Appeals of Santiago on November 28, 2017. On April 21, 2019, the expert witness presented a report, which on April 30, 2019 the Court of Appeals of Santiago considered. On June 21, 2019 the claim was ready to be heard by the court. On June 26, 2019, the Constitutional Court issued a ruling, which gives effect to the principle of inapplicability due to unconstitutionality presented by Enel Distribución Chile. On June 28, 2019, the Court of Appeals of Santiago took into account the ruling issued by the Constitutional Court and, on its merit, suspended the proceeding, through an official letter to the Constitutional Court issued on June 28, 2019. On November 7,

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2019, the Constitutional Court rejected the appeal for inapplicability due to unconstitutionality, resuming the litigation proceeding on November 22, 2019. As of December 31, 2019, the proceeding was in a waiting stage for the allegations of those involved to be heard.

3.5 By means of Exempt Resolution No. 24,805 dated July 20, 2018, the Superintendency of Electricy and Fuels confirmed the fine imposed on Enel Distribución Chile S.A. for 80,000 UTM (ThCh$3,969,840) when it ruled against the request for reconsideration filed against Exempt Resolution No. 21,788 dated December 29, 2017 because it determined that Enel Distribución Chile kept more than 100,000 customers without electricity supply for a period exceeding 20 hours, in relation to the power outage that occurred on July 15, 2017 (the snowstorm event). In opposition to the aforementioned ruling, Enel Distribución Chile filed an appeal with the Court of Appeals of Santiago on August 7, 2018. On March 7, 2019, Enel Distribución Chile asked the Court to appoint a new civil electrical engineer expert, who was appointed in a resolution dated March 15, 2019, was notified on July 3, 2019, and accepted the appointment and proposed his fees on August 16, 2019. The court gave notice to the parties, and on September 5, 2019 the parties responded and accepted the expert’s fees and payment method. On November 28, 2019, the hearing to recognize this was held and subsequently on December 20, 2019, certification of the end of the trial period was requested. As of December 31, 2019, the proceeding was in the decision stage.

3.6 By means of Exempt Resolution No. 24,821 dated July 23, 2018, the Superintendency of Electricity and Fuels confirmed the fine imposed on Enel Distribución Chile S.A. for 10,000 UTM, (ThCh$496,230), when it ruled against the request for reconsideration filed against Exempt Resolution No. 21790 dated December 29, 2017 because it determined that Enel Distribución Chile did not provide adequate and timely customer service during the power outage that occurred on July 15, 2017 (the snowstorm event), which resulted from not having adequate customer service and information systems. In opposition to the aforementioned resolution, Enel Distribución Chile filed an appeal with the Court of Appeals of Santiago on August 7, 2018. On February 1, 2019 Enel Distribución Chile presented a list of witnesses, and such evidence was received on February 8, 2019, when Enel Distribución Chile also requested a hearing for the appointment of an expert. The request was accepted and the Court hearing was set for February 13, 2019. On February 28, 2019, Enel Distribución Chile again requested that the Court designate an expert, following the non-appearance of the counterparty at the hearing to designate an expert. On March 7, 2019, an expert was appointed, who accepted the appointment and proposed his fees on March 17, 2019. The Court acknowledged the acceptance of the appointment in a resolution dated March 25, 2019. On September 6, 2019, Enel Distribución Chile recorded 50% of the expert’s fees, which the Court made effective on September 24, 2019. On November 27, 2019, the expert received made the corresponding payment. As of December 31, 2019, the proceeding was in the decision stage.

3.7 By means of Exempt Resolution No. 24,249 dated June 18, 2018, the Superintendency of Electricity and Fuels imposed a fine of 3,000 UTM (ThCh$ 148,869), on Enel Distribución Chile S.A. for a power failure that occurred on October 20, 2016, when the 110 Kv Cerro Navia-Lo Prado line was disconnected due to a mono-phase failure between phase A and the ground, which was caused by bird droppings that caused a short circuit between conductors of phase A and a crosshead in portal No. 1 from 110 Kv to the S/E Lo Prado substation. In opposition to this resolution, Enel Distribución Chile S.A. filed a motion for reconsideration, which was rejected by Exempt Resolution No. 29,080 dated May 8, 2019. In opposition to the aforementioned resolution, Enel Distribución Chile S.A. filed an appeal with the Court of Appeals of Santiago on August 7, 2018. On June 13, 2019, a resolution was issued that considered the appeal and requested a report from the Superintendency of Electricity and Fuels, which was served on the Superintendency of Electricity and Fuels on June 17, 2019. The Superintendency of Electricity and Fuels issued the report on July 1, 2019, and the claim was ready to be heard by the court on July 5, 2019. On July 17, 2019, the hearing of the case took place and a judgment was issued on July 22, 2019 which rejected the appeal and confirmed the fine imposed by the Superintendency of Electricity and Fuels. Enel Distribución Chile S.A. filed an appeal against that judgment on August 2, 2019. On November 13, 2019, the Supreme Court upheld the judgment on appeal, maintaining the fine imposed by the Superintendency of Electricity and Fuels, which as of December 31, 2019 was pending payment.

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3.8 By means of Exempt Resolution No. 24,870 dated July 25, 2018, the Superintendency of Electricity and Fuels imposed a fine of 6,000 UTM (ThCh$297,738) on Enel Distribución Chile S.A. for the accident that occurred on July 15, 2017 at the property Bombero Núñez Street, No. 40, in the Commune of Recoleta, where the company's underground distribution network would have been linked. In opposition to this resolution, Enel Distribución Chile filed a motion for reconsideration, which was rejected by Exempt Resolution No. 28320 dated March 21, 2019. On April 15, 2019, Enel Distribución Chile S.A. filed an appeal with the Court of Appeals of Santiago. On April 30, 2019, a resolution was issued that considered the appeal and requested a report from the Superintendency of Electricity and Fuels. On May 17, 2019, the Superintendency of Electricity and Fuels issued a report, and the claim was ready to be heard by the court on May 24, 2019. On June 10, 2019, Enel Distribución Chile S.A. requested that a trial period be opened, which was rejected by a resolution dated June 11, 2019, in respect of which Enel Distribución Chile filed a motion for reconsideration. On June 26, 2019, the court rejected the motion for reconsideration. A hearing of the case took place on September 27, 2019. On November 19, 2019, the Court of Appeals of Santiago issued a ruling rejecting the appeal filed, against which a further appeal was filed on November 30, 2019. On December 26, 2019, the allegations of the parties were heard before the Third Chamber of the Supreme Court and the parties are awaiting the Supreme Court’s ruling.

3.9 By means of Exempt Resolution No. 24,246 dated June 13, 2018, the Superintendency of Electricity and Fuels imposed a fine of 2,000 UTM (ThCh$ 99,246) on Enel Distribución Chile S.A. for operating its facilities in violation of current electrical regulations, by not maintaining its facilities in good condition, as evidenced by the electric shock produced in the insulator of portal No. 74 of the 110 Kv Cerro Navia-Lo Prado line, attributed to contamination from bird droppings, which affected the electricity supply of customers for more than 2 hours. In opposition to this resolution, Enel Distribución Chile filed a motion for reconsideration, which was rejected by Exempt Resolution No. 28,857 dated April 23, 2019. On May 14, 2019, an appeal was filed with the Court of Appeals of Santiago. On June 5, 2019, a resolution was issued that considered the appeal and requested a report from the Superintendency of Electricity and Fuels. On July 24, 2019, the Superintendency of Electricity and Fuels issued a report, and the claim was ready to be heard on August 20, 2019. On October 29, 2019, the allegations of the parties were heard and subsequently, on December 6, 2019, the Court of Appeals of Santiago issued a ruling rejecting the appeal filed.  On December 18, 2019, Enel Distribución Chile S.A. filed an appeal for a hearing and judgment with the Supreme Court.

In relation to the litigation proceedings described above, the Group had established provisions for ThCh$7,488,391 as of December 31, 2019 (see Note 25). Although there are other lawsuits that also have associated provisions but are not described in this note because they individually represent immaterial amounts, the management of the Company considers that the provisions recorded in the consolidated financial statements are adequate to cover the risks of litigation and therefore do not expect additional liabilities other than those already specified.

Given the characteristics of the risks covered by these provisions, it is not possible to determine a reasonable schedule of payment dates if there are any.

36.4 Financial restrictions.

A number of the Company’s debt agreements, and those of some of its subsidiaries, include routine obligations to comply with certain financial ratios, affirmative and negative covenants, as well as event of default and mandatory prepayment provisions.

1. Cross Default

Under Enel Chile’s bank loan agreement executed in June 2019 and maturing in June 2024, the cross payment default clause could be triggered by the default of another debt of the Company or of any of its Significant Subsidiaries (as defined contractually), provided that both the principal of the single debt giving rise to the cross default exceeds US$150million or its equivalent in other currencies and that the amount in default also exceeds US$150 million, or its equivalent. Additional conditions must be met, including the expiration of grace periods (if any), and a formal notice of intent to accelate the debt repayment must have been give by creditos

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representing over 50% of the amount owed or committed in the contract. As of December 31, 2019, these credit lines are undrawn.

For the SEC registered public bonds issued by the Company in the United States of America, commonly referred to as “Yankee bonds,” a cross default may be triggered by another debt of the Company on an individual level, or of any Significant Subsidiaries (as defined in the Indenture), for any amount overdue provided that the principal of the debt giving rise to the cross payment default exceeds US$150 million, or its equivalent in other currencies. Debt acceleration due to cross payment default does not occur automatically but has to be requested by the Trustee, or by holders of at least 25% of the specific series of Yankee bonds. Bankruptcy or insolvency of only Significant Subsidiaries may trigger a default of the Yankee bonds. As of December 31, 2019, the outstanding amount for the Yankee bonds maturing in 2028 was US$ 1 billion equivalent to ThCh$ 733,128,457.

In the bonds of Enel Generación Chile registered with SEC, commonly called “Yankee bonds”, the cross default for non-payment could be triggered by another debt of the same company, or of any of its Chilean subsidiaries, for any amount overdue, provided that the principal of the debt that gives rise to the cross default exceeds US$30 million, or its equivalent in other currencies. Debt acceleration due to a cross-default does not occur automatically, but must be demanded by the holders of at least 25% of the bonds of that certain series of Yankee bonds.

The Yankee bonds of Enel Generación Chile expire in 2024, 2027, 2037 and 2097, have similar contractual provisions as those detailed for Enel Chile. However, in the case of the Yankee bond maturing in 2024, the threshold that gives rise to cross default is US$50 million or its equivalent in other currencies. As of December 31, 2019, the amount owed for the Yankee bonds was US$ 717 million equivalent to ThCh$537,266,386.

Enel Generación Chile bonds issued in Chile state that cross default can be triggered only by the default of the issuer when the amount in default exceeds US$50 million or its equivalent in other currencies. Debt acceleration requires the agreement of at least 50% of the bondholders of that certain series. As of December 31, 2019, the outstanding amount of the Chilean bonds was ThCh$306,895,060.

The bank loan that Enel Green Power Chile executed in February 2017 for US$30 million states that the cross default is triggered by default of Enel Green Power Chile or any material subsidiary, as defined contractually. For the acceleration of this debt due to a cross default arising from another debt, the amount in default, either individually or in the aggregate, must exceed US$50 million, or its equivalent in other currency. As of December 31, 2019, the outstanding amount for this loan was ThCh$22,592,723.

2. Financial covenants

Financial covenants are contractual commitments with respect to minimum or maximum financial ratios that a company is obliged to meet at certain periods of time (quarterly, annually, etc.), and in certain cases only when certain conditions are met. Most of the financial covenants of the Company limit leverage and track the ability to generate cash flow that will service the companies’ indebtedness. Certain companies are also required to periodically certify these covenants. The types of covenants and their respective limits vary based on debt and contract type.

Enel Generación Chile bonds issued in Chile include the following financial covenants whose definitions and calculation formulas are established in the respective indentures:

Series H

· Consolidated Debt Ratio: The consolidated debt ratio, which is Financial Debt to Capitalization, must be less than or equal 0.64. Financial debt is the sum of Interest-bearing loans, current; Interest-bearing loans, non-current; Other financial liabilities, current; Other financial liabilities, non-current; and Other obligations guaranteed by the issuer or its subsidiaries; while Capitalization is the sum of Financial liabilities and Total Equity. As of December 31, 2019, the ratio was 0.30.

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· Consolidated Equity: A minimum equity of Ch$781,206 million must be maintained; this limit is adjusted at the end of each year as established in the indenture. Equity corresponds to Equity attributable to the shareholders of Enel Generación Chile. As of December 31, 2019, the equity of Enel Generación Chile was Ch$1,963,775 million.

· Financial Expense Coverage: A financial expense coverage ratio of at least 1.85 must be maintained. Financial expense coverage is the quotient between i) the gross margin plus financial income and dividends received from investments in associates, and ii) financial expenses; both items refer to the period of four consecutive quarters ending on the quarter being reported. For the year ended December 31, 2019, this ratio was 10.43.

· Net Asset Position with Related Companies: A net asset position with related companies of no more than US$500 million the equivalent amount in pesos, according to the exchange rate observed at the end of each quarter. The Net asset position with related companies is the difference between i) the sum of current accounts receivable from related parties of Current Assets and Accounts Receivable from Related Entities of Non-Current Assets and ii) the sum of Accounts Payable to Related Entities of Current Liabilities and Accounts Payable to Related Entities of Non-Current Liabilities. The corresponding amounts must be excluded from the above: i) transactions that have a duration of less than 180 days, and ii) transactions that refer to balances in checking accounts, documents and accounts of Enel Generación Chile or its subsidiaries that originate in the ordinary course of business of Enel Generación Chile or its subsidiaries. Likewise, transactions of affiliated companies of Enel Generación Chile and of affiliated companies of its subsidiaries should also be excluded,  as long as  the respective affiliated company Enel Chile S.A. has no participation, either directly or indirectly through a subsidiary or affiliated company of Enel Chile S.A., other than through Enel Generación Chile and its subsidiaries. As of December 31, 2019, using the exchange rate prevailing on that date, the Net asset position with related companies was a negative US$252.58 million, indicating that Enel Generación Chile is a net creditor of its related companies.

Series M

· Consolidated Debt Ratio: The consolidated debt ratio, which is Financial debt to Capitalization, must be less than or equal to 0.64. Financial debt is the sum of Interest-bearing loans, current; Interest-bearing loans, non-current; Other financial liabilities, current; and Other financial liabilities, non-current; while Capitalization is the sum of Financial liabilities, Equity attributable to the shareholders of the Company and Non-controlling interests. As of December 31, 2019, the debt ratio was 0.30.

· Consolidated Equity: Same as for Series H.

· Financial Expense Coverage Ratio: Same as for Series H.

Yankee bonds of Enel Generación Chile and the debt sign on January 2018 by Enel Chile are not subject to financial covenants.

As of December 31, 2019, the most restrictive financial covenant for Enel Generación Chile was Coverage ratio of Financial Expenses.

The other Group companies not mentioned in this Note, are not subject to compliance with financial covenants.

Finally, in most of the contracts, debt acceleration for non-compliance with these covenants does not occur automatically, but is subject to certain conditions, such as a grace period.

As of December 31, 2019, neither the Company nor any company of the Group was in default under their financial obligations summarized herein or other financial obligations whose defaults might trigger the acceleration of their financial commitments.

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37.  PERSONNEL FIGURES.

The Company’s personnel as of December 31, 2019 and 2018, is distributed as follows:

	December 31, 2019
Country	Managers and key executives	Professional and Technicians	Staff and others	Total
Chile	54	1,932	139	2,125
Argentina	—	6	17	23
Total	54	1,938	156	2,148
Average	56	1929	157	2142
	December 31, 2018
Country	Managersand key executives	Professionals and Technicians	Staff and others	Total
Chile	57	1,824	155	2,036
Argentina	—	7	19	26
Total	57	1,831	174	2,062
Average	53	1,874	169	2,096

38.  SANCTIONS.

The following Group companies  have received sanctions from administrative authorities:

1. Enel Generación Chile S.A.

As of December 31, 2019, the request for reconsideration of the sanction proceedings initiated by the Bío Bío Regional Health Ministry by Act 180566, which imposed a fine in the amount of 500 UTM (ThCh$24,812) for alleged infractions by Enel Generación Chile S.A of obligations and regulations related to waste disposal regulations in the Cantarrana landfill, is pending.

Two requests for reconsideration are pending with respect to the resolutions of the Tarapacá Regional Health Ministry, which, through inspection reports No. 011599 and 766, imposed fines in an amount of 500 UTM each (totaling ThCh$24,812).

A health summary in the amount of 500 UTM (ThCh$24,812) is pending resolution before the Coquimbo Regional Health Ministry.

Likewise, the Valparaíso Regional Health Ministry initiated sanction proceedings with respect to inspection report No. 1705213, for alleged breaches of obligations and regulations related to the Noise Exposure Protocols and other health surveillance regulations at the Quintero plant. The amount of this fine is 500 UTM (ThCh$24,812).

2. Enel Distribución Chile S.A.

By means of Exempt Resolution No. 21,789 dated December 29, 2017, the Superintendency of Electricity and Fuels imposed on Enel Distribución Chile S.A. fines equivalent to 20,000 UTM (ThCh$992,460) for delivering erroneous information to the supervisory body regarding the replacement of the supply, in relation to the power supply outage that occurred on July 15, 2017 (the snowstorm event). Enel Distribución Chile has filed a request for reconsideration against this fine which is pending of resolution.

By means of Exempt Resolution No. 13,630 dated May 23, 2016, the Superintendency of Electricity and Fuels imposed on Enel Distribution Chile S.A. a fine equivalent to 2,000 UTM (ThCh$99,246) for Enel Distribución Chile S.A.’s failure to fulfill its obligation to maintain its electrical installations in good condition to comply with the demands of quality and continuity of supply, with regard to the fire that affected the San Joaquin substation on May 19, 2015. Enel Distribución Chile has filed a request for reconsideration against this fine which is pending of resolution.

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By means of Exempt Resolution No. 27.005 dated December 28, 2018 (received on January 28, 2019) the Superintendency of Electricity and Fuels imposed on Enel Distribución Chile S.A. a fine equivalent to 16,911 UTM (ThCh$839,175) due to Enel Distribución Chile exceeding the standard established in the supply continuity index for the 2015-2016 period. Enel Distribución Chile has filed a request for reconsideration against this fine which is pending of resolution.

By means of Exempt Resolution No. 27,226 dated January 16, 2019, the Superintendency of Electricity and Fuels imposed on Enel Distribución Chile S.A. a fine equivalent to 5,500 UTM (ThCh$272,927) due to Enel Distribución Chile’s operation of its facilities in violation of the current electrical regulations, as it did not maintain its facilities in good condition, as evidenced by the failure to detect material fatigue at the Domínicos substation. Enel Distribución Chile has filed a request for reconsideration against this fine which is pending of resolution.

By means of Exempt Resolution No. 30,198 dated August 16, 2019, the Superintendency of Electricity and Fuels imposed on Enel Distribución Chile S.A. a fine equivalent to 1,000 UTM (ThCh$49,623) due to Enel Distribución Chile’s operation of its facilities in violation of the current electrical regulations, as it did not maintain its facilities in good condition, as evidenced by the supply interruption that occurred in the communes of Lampa and Til Til. Enel Distribución Chile has filed a request for reconsideration against this fine which is pending of resolution.

3. Enel Green Power Chile Ltda.

By means of Exempt Resolution No. 23787 dated May 14, 2018, the Superintendence of Electricity and Fuels imposed a fine of 1,000 UTM (ThCh$49,623) on Enel Green Power del Sur SpA for having violated an alleged duty of coordination during failures that occurred on May 7 and 13 and June 1, 2016 on the Los Buenos Aires-Nahuelbuta line, associated with the Los Buenos Aires wind plant, owned by Enel Green Power del Sur SpA. A request for reconsideration was filed against this resolution based on the fact that the alleged duty of of coordination did not exist, but the request for reconsideration was rejected. A claim of illegality against the resolution was filed before the Court of Appeals of Santiago, which rejected the appeal filed and confirmed the fine. The fine has been paid.

In relation to the sanctions described above, the Group has established provisions for ThCh$2,349,758 as of December 31, 2019 (see Note 25). Although there are other sanctions that also have associated provisions but are not described in this note since they individually represent immaterial amounts, the management of the Company considers that the provisions recorded are adequate to cover the risks resulting from sanctions, and therefore do not expect additional liabilities other than those already specified.

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39.  ENVIRONMENT.

Environmental expenses for the years ended December 31, 2019 and 2018 are as follows:

				12-31-2019						12-31-2018
Company Incurring the Cost	Name of project	Description	Project Status (Finished, In progress)	Total Disbursements	Amounts Capitalized	Expenses	Disbursement amount in the future	Estimated future disbursement date	Total Disbursements	Total Disbursement from the previous year
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	PEHUENCHE CENTRAL	Waste Management	In process	3,165	—	3,165	—	-	3,165	—
		Environmental Sanitation	In process	1,988	—	1,988	—	-	1,988	—
	Hydroelectric Central Environmental Expenditures	C.H. Pehuenche E E Pehuenche S.A. Suministro de equipos de medicion de caudales.	Finished	—	—	—	—	-	—	48,574
Empresa Electrica Pehuenche S.A.		Studies, monitoring, laboratory analysis, removal and final disposal of solid waste at hydroelectric power stations (HPS), thermoelectric power stations and combine cycle power stations.	Finished	—	—	—	—	-	—	62,560
	CURILLINQUE CENTRAL	Campaigns and Studies	In process	9,061	—	9,061	—	-	9,061	—
		Environmental Sanitation	In process	882	—	882	—	-	882	—
	LOMA ALTA CENTRAL	Environmental Sanitation	In process	882	—	882	—	-	882	—
	Removal of Asbestos from Underground Cables	Removal of flame retardant tape with asbestos from the underground network MT.	In process	—	—	—	—	-	—	383,914
	ENVIRONMENTAL MONITORING	Environmental monitoring with SK Ecología operation and maintenance CEMS	In process	576,519	—	576,519	—	-	576,519	797,543
	CEMS STANDARDIZATION	Standardization warehouses, environmental management, regularization environmental impact assessment (EIA)	In process	207,966	207,966	—	—	-	207,966	645,302
	HYDRAULIC POWER STATIONS	Waste Management e higienización	In process	2,315	—	2,315	—	-	2,315	11,567
Enel Generación Chile S.A.	CC.CC. ENVIRONMENTAL EXPENSES	The main expenses incurred are: Bocamina U1-2: Operation and maintenance monitoring of air and meteorological quality stations, Environmental audit, monitoring network 1 a year, Annual CEMS Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements , SGI Works (Objective NC, inspections, audits and inspection) ISO 14001, OHSAS certification, Operation and Maintenance Service CEMS.	In process	1,452,158	855,667	596,491	855,667	31/12/2020	2,307,825	2,102,056
	CC.TT. ENVIRONMENTAL EXPENSES	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In process	5,387,657	1,763,829	3,623,828	1,763,829	31/12/2020	7,151,486	2,867,523
	CC.HH. ENVIRONMENTAL EXPENSES	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric power plants (C.H.)	In process	339,103	—	339,103	420,877	31/12/2020	759,980	183,156
	C.H. Ralco	Plan Ralco: Reforestation according to Agreement with the Catholic University and Electrification of housing in Ayin Maipu	Finished	—	—	—	—	-	—	4,542,216
	QUINTERO CENTRAL	CEMS Central Quinteros	In process	458,001	110,923	347,078	37,983	31/12/2020	495,984	417,194
	CHANGE OF TRAD X CALPE NETWORK	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In process	1,476,780	1,476,780	—	—	-	1,476,780	1,382,504
		The service consists in the weeding and control of weeds in electric power substations in order to keep the enclosures free of weeds, ensuring a good operation of these facilities.	Finished	2,600	—	2,600	—	-	2,600	154,048
	VEGETATION CONTROL IN NETWORKS	Poda de arboles en cercanias de la red de media tensión	In process	—	—	—	—	-	—	6,292,641
		This activity contemplates the maintenance of the band of easement of high voltage lines between 34,5 y 500kv.	Finished	67,291	—	67,291	—	-	67,291	—
	VEGETATION CONTROL IN MT/BT	Mejora en la red tradicional por calpe (cable aluminio preensamblado)	In process	—	—	—	—	-	—	392,475
		Pruning of trees near the media network and low voltage.	Finished	3,507,502	—	3,507,502	—	-	3,507,502	—
	ENVIRONMENTAL PERMITS	Environmental Impact Statement: 1) New Lampa Sectioning Substation and 2) Ochagavia - Florida Line, Sanjon La Aguada Section	Finished	—	—	—	—	-	—	6,970
Enel Distribución Chile S.A.		The service consists of the maintenance of green areas with replacement of species and grass in Enel substation enclosures. SSEE tree maintenance and weed removal, debris and garbage, outside perimeter.	Finished	64,737	—	64,737	—	-	64,737	52,016
	ENVIRONMENTAL MANAGEMENT IN SSEE	The service consists of the maintenance of green areas with replacement of species and turf in Enel substations enclosures. The service consists in the weeding and control of weeds in electric power substations in order to keep the enclosures free of weeds, ensuring a good operation of these facilities.	Finished	19,706	—	19,706		-	19,706	46,907
		The removal and transfer to waste dump from a Substation was carried out.	Finished	21,719	—	21,719	—	-	21,719	—
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in Metropolitan Park.	Finished	2,337	—	2,337	—	-	2,337	6,634
	IMPROVEMENTS IN THE MT NETWORK	Network replacement for weardown MT protected cable	In process	170,077	170,077	—	—	-	170,077	176,142
	RESPEL MANAGEMENT	Dangerous waste management	Finished	103,847	—	103,847	—	-	103,847	1,780
	REPLACE TRIFAS TRANSFORMERS MEJ QUALITY BT	Replacement of transformers with chargeability problems	In process	1,168,343	1,168,343	—	—	-	1,168,343	2,642,064

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				12-31-2019						12-31-2018
Company Incurring the Cost	Name of project	Description	Project Status (Finished, In progress)	Total Disbursements	Amounts Capitalized	Expenses	Disbursement amount in the future	Estimated future disbursement date	Total Disbursements	Total Disbursement from the previous year
				ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
	REPLACEMENT TD DAE CONCENTRICA X TD. TRIF. RED CALPE	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In process	492,260	492,260	—	—	-	492,260	1,008,416
Enel Green Power del Sur Spa.		Waste Management	Finished	4,432	—	4,432	—	-	4,432	—
	Carrera Pinto	Environmental Sanitation	Finished	6,466	—	6,466	—	-	6,466	—
		Wastewater Treatment Plant	Finished	4,436	—	4,436	—	-	4,436	—
		Waste Management	Finished	10,954	—	10,954	—	-	10,954	—
	Finis Terrae	Environmental Sanitation	Finished	7,674	—	7,674	—	-	7,674	—
		Wastewater Treatment Plant	Finished	2,154	—	2,154	—	-	2,154	—
	La Silla	Environmental Sanitation	Finished	2,902	—	2,902	—	-	2,902	—
		Waste Management	Finished	1,509	—	1,509	—	-	1,509	—
		Campaigns and Studies	Finished	20,613	—	20,613	—	-	20,613	—
	Los Buenos Aires	Environmental Sanitation	Finished	3,989	—	3,989	—	-	3,989	—
		Wastewater Treatment Plant	Finished	882	—	882	—	-	882	—
Enel Green Power del Sur Spa.		Environment Materials	Finished	5,589	—	5,589	—	-	5,589	—
		Waste Management	Finished	5,098	—	5,098	—	-	5,098	—
	Pampa Norte	Environmental Sanitation	Finished	6,618	—	6,618	—	-	6,618	—
		Wastewater Treatment Plant	Finished	3,459	—	3,459	—	-	3,459	—
		Waste Management	Finished	2,281	—	2,281	—	-	2,281	—
		Campaigns and Studies	Finished	83,820	—	83,820	—	-	83,820	—
	Renaico	Environmental Sanitation	Finished	5,226	—	5,226	—	-	5,226	—
		Wastewater Treatment Plant	Finished	982	—	982	—	-	982	—
		Environment Materials	Finished	4,822	—	4,822	—	-	4,822	—
		Outsourced Services	Finished	53,970	—	53,970	—	-	53,970	—
		Waste Management	Finished	13,999	—	13,999	—	-	13,999	—
	Sierra Gorda	Campaigns and Studies	Finished	42,959	—	42,959	—	-	42,959	—
		Environmental Sanitation	Finished	3,300	—	3,300	—	-	3,300	—
		Wastewater Treatment Plant	Finished	127	—	127	—	-	127	—
		Waste Management	Finished	1,613	—	1,613	—	-	1,613	—
	Chañares	Campaigns and Studies	Finished	7,981	—	7,981	—	-	7,981	—
		Environmental Sanitation	Finished	5,262	—	5,262	—	-	5,262	—
		Wastewater Treatment Plant	Finished	5,591	—	5,591	—	-	5,591	—
		Waste Management	Finished	1,678	—	1,678	—	-	1,678	—
	Lalackama	Environmental Sanitation	Finished	7,091	—	7,091	—	-	7,091	—
Empresa Electrica Panguipulli S.A.		Wastewater Treatment Plant	Finished	3,273	—	3,273	—	-	3,273	—
	Pilmaiquen	Waste Management	Finished	1,450	—	1,450	—	-	1,450	—
		Environmental Sanitation	Finished	6,822	—	6,822	—	-	6,822	—
		Waste Management	Finished	785	—	785	—	-	785	—
	Pullinque	Campaigns and Studies	Finished	2,627	—	2,627	—	-	2,627	—
		Environmental Sanitation	Finished	4,129	—	4,129	—	-	4,129	—
		Environment Materials	Finished	394	—	394	—	-	394	—
	Talinay Poniente	Campaigns and Studies	Finished	46,026	—	46,026	—	-	46,026	—
		Waste Management	Finished	10,745	—	10,745	—	-	10,745	—
Parque Eolico Tal Tal SpA	Taltal	Campaigns and Studies	Finished	44,656	—	44,656	—	-	44,656	—
		Environmental Sanitation	Finished	2,476	—	2,476	—	-	2,476	—
		Wastewater Treatment Plant	Finished	2,515	—	2,515	—	-	2,515	—
		Waste Management	Finished	11,546	—	11,546	—	-	11,546	—
Parque Eolico Valle de Los Vientos SpA	Valle de los Vientos	Campaigns and Studies	Finished	20,216	—	20,216	—	-	20,216	—
		Environmental Sanitation	Finished	2,471	—	2,471	—	-	2,471	—
		Waste Management	Finished	11,865	—	11,865	—	-	11,865	—
Parque Eolico Talinay Oriente S.A.	Talinay Oriente	Campaigns and Studies	Finished	63,666	—	63,666	—	-	63,666	—
		Environmental Sanitation	Finished	9,419	—	9,419	—	-	9,419	—
		Wastewater Treatment Plant	Finished	1,738	—	1,738	—	-	1,738	—
		Waste Management	Finished	10,087	—	10,087	—	-	10,087	—
Almeyda Solar Spa	Diego de Almagro	Environmental Sanitation	Finished	5,216	—	5,216	—	-	5,216	—
		Wastewater Treatment Plant	Finished	6,040	—	6,040	—	-	6,040	—
		Total		16,132,535	6,245,845	9,886,690	3,078,356	-	19,210,891	12,494,852

F-125

						12-31-2018												12-31-2017
Company Incurring the Cost	Name	Project		Project Status (Finished, In progress)		Total Disbursements ThCh$		Amounts Capitalized ThCh$		Expenses ThCh$		Disbursement amount in the future ThCh$		Estimated future disbursement date ThCh$		Total Disbursements ThCh$		Total Disbursement from the previous year ThCh$
Empresa Electrica Pehuenche S.A.	Hydroelectric Central Environmental Expenditures	C.H. Pehuenche E E Pehuenche S.A. Supply of flow measurement equipment.	In progress		48,574		48,574		—		—		—		48,574		6,787
		Studies, monitoring, laboratory analysis, removal and final disposal of solid waste at hydroelectric power stations (HPS), thermoelectric power stations and combine cycle power stations.	In progress		62,560		—		62,560		—				62,560		—
Enel Distribución Chile S.A.	Vegetation Control In Redesat	It consists of cutting branches until the safety conditions to which the foliage must be left with respect to the drivers.	In progress		134,394		—		134,394		19,654				154,048		306,419
		Pruning of trees near the medium voltage network	In progress		5,790,042		2,472,768		3,317,274		502,599		31-03-2019		6,292,641
	Management Respel	Dangerous waste management	Finished		1,780		—		1,780		—		30-06-2018		1,780
	Environmental management in Ssee	The service consists of the maintenance of green areas with replacement of species and turf in Enel substations enclosures	Finished		15,383		—		15,383		36,633		31-12-2018		52,016
		The service consists in the weeding and control of weeds in electric power substations in order to keep the enclosures free of weeds, ensuring a good operation of these facilities.	In progress		46,339		—		46,339		568		31-03-2018		46,907
	ENVIRONMENTAL PERMITS	Environmental Impact Statement: 1) New Lampa Sectioning Substation and 2) Ochagavia - Florida Line, Sanjon La Aguada Section	In progress		1,767		1,767		—		5,203		31-03-2019		6,970
	VEGETATION CONTROL IN MT / BT NETWORKS	Improvement in the traditional network by calpe (pre-assembled aluminum cable)	In progress		19,416		19,416		—		373,059		31-03-2019		392,475
	IMPROVEMENTS IN THE MT NETWORK	Network replacement for weardown MT protected cable	In progress		158,086		158,086		-		18,056		31-03-2019		176,142
	CHANGE OF TRAD X CALPE NETWORK	Traditional network replacement by Calpe (Pre-assembled aluminum cable) BT	In progress		851,792		851,792		-		530,712		31-03-2019		1,382,504
	REPLACEMENT TD DAE CONCENTRICA X TD. TRIF. RED CALPE	Concentrical network replacement by Calpe (Pre-assembled aluminum cable) BT	In progress		712,455		712,455		—		295,961		31-03-2019		1,008,416
	REPLACE TRIFAS TRANSFORMERS MEJ QUALITY BT	Replacement of transformers with chargeability problems			1,288,155		1,288,155		—		1,353,909		31-03-2019		2,642,064
	ENVIRONMENTAL MANAGEMENT	Environmental Management of Reforestation in Cerro Chena and Metropolitan Park.			5,831		-		5,831		803		31-03-2019		6,634
	Removal of Asbestos from Underground Cables	Removal of flame retardant tape with asbestos from the underground network MT.	In progress		265,577		146,300		119,277		118,337		31-03-2019		383,914		203,724
GasAtacama Chile	Environmental monitoring	Environmental monitoring  with SK Ecología operation and maintenance CEMS.	In progress		797,543		—		797,543		—				797,543		1,463,204
	Standardization Cems	Normalización bodegas, gestión ambiental.	In progress		645,302		645,302		—		—				645,302		1,021,630
	Hydraulic power stations	Waste management and sanitation	In progress		11,567		-		11,567						11,567
Enel Generación Chile S.A.	ENVIRONMENTAL EXPENSES CC.TT.	The main expenses incurred are: Bocamina U1-2: Operation and maintenance monitoring of air and meteorological quality stations, Environmental audit, monitoring network 1 a year, Annual CEMS Validation, Biomass Protocol Service, Environmental Materials (magazine, books), Isokinetic Measurements , SGI Works (Objective NC, inspections, audits and inspection) ISO 14001, OHSAS certification, Operation and Maintenance Service CEMS.	In progress		2,102,056		—		2,102,056		—				2,102,056		1,252,355
		Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in thermoelectric plants (C.T.)	In progress		2,867,523		—		2,867,523		—				2,867,523		251,277
	ENVIRONMENTAL EXPENSES CC.HH.	Studies, monitoring, laboratory analysis, removal and final disposal of solid waste in hydroelectric power plants (C.H.)	In progress		183,156		—		183,156		—				183,156		870,281
	C.H. Ralco	Plan Ralco: Reforestation according to Agreement with the Catholic University and Electrification of housing in Ayin Maipu	In progress		4,542,216		4,542,216		—		—				4,542,216		5,075,137
	Central Quintero	CEMS Central Quinteros	In progress		417,194		417,194		—		—				417,194		1,290,133
		Total			20,968,708		11,304,025		9,664,683		3,255,494				24,224,202		11,740,947

F-126

40.  SUMMARIZED FINANCIAL INFORMATION OF SUBSIDIARIES.

As of December 31, 2019 and 2018, summarized financial information of our principal subsidiaries is as follows:

	December 31, 2019
	Type of Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile Group	Consolidated	289,393,933	1,175,550,962	1,464,944,895	317,248,208	301,769,861	845,926,826	1,464,944,895	1,412,871,737	(1,114,936,281)	297,935,456	201,152,462	152,293,464	5,232,127	157,525,602	(38,748,555)	118,777,047	(5,268,320)	113,508,727
Enel Generación Chile	Separate	583,721,624	2,934,658,635	3,518,380,259	449,869,095	1,081,712,205	1,986,798,959	3,518,380,259	1,566,647,603	(1,015,974,072)	550,673,531	438,227,197	273,796,017	(61,735,905)	378,925,840	(47,979,392)	330,946,448	(51,590,095)	279,356,353
Enel Distribución Chile	Separate	281,307,184	1,166,614,368	1,447,921,552	293,190,807	301,606,886	853,123,859	1,447,921,552	1,409,434,510	(1,113,958,943)	295,475,567	200,130,596	151,879,931	4,770,147	156,650,077	(38,583,882)	118,066,195	(5,258,044)	112,808,151
Empresa Eléctrica Pehuenche S.A.	Separate	40,913,391	172,823,608	213,736,999	32,304,951	44,330,262	137,101,786	213,736,999	147,472,130	(19,725,956)	127,746,174	121,631,813	114,117,571	2,230,250	116,442,545	(31,554,368)	84,888,177	—	84,888,177
Enel Green Power Chile Ltda.	Separate	93,176,241	728,572,966	821,749,207	148,584,958	26,709,820	646,454,429	821,749,207	17,470,331	(5,891)	17,464,440	2,941,543	1,770,750	(3,819,658)	4,271,982	789,773	5,061,755	47,305,179	52,366,934
Empresa Electrica Panguipulli S.A.	Separate	11,883,401	268,737,935	280,621,336	35,237,664	152,717,912	92,665,760	280,621,336	65,392,897	(10,089,283)	55,303,614	45,295,840	25,634,374	(7,544,701)	18,091,741	(3,984,287)	14,107,454	4,145,983	18,253,437
Geotermica del Norte S.A.	Separate	21,392,710	389,334,650	410,727,360	34,868,730	316,179	375,542,451	410,727,360	25,736,468	(4,666,032)	21,070,436	16,240,808	985,760	(2,431,778)	(1,446,018)	(268,161)	(1,714,179)	28,824,398	27,110,219
Parque Eolico Talinay Oriente S.A.	Separate	75,985,899	91,924,981	167,910,880	3,479,000	25,290,284	139,141,596	167,910,880	12,662,715	(891,215)	11,771,500	8,846,598	1,956,884	1,076,843	3,033,727	(812,645)	2,221,082	10,644,581	12,865,663
Enel Green Power del Sur	Separate	190,106,543	732,488,168	922,594,711	54,033,958	534,433,995	334,126,758	922,594,711	144,036,603	(25,778,573)	118,258,030	99,202,697	66,657,147	(23,438,689)	43,218,457	(9,496,203)	33,722,254	25,195,173	58,917,427
Enel Green Power Group	Consolidated	371,759,514	1,775,791,317	2,147,550,831	377,911,553	773,916,901	995,722,377	2,147,550,831	273,239,617	(26,298,083)	246,941,534	204,174,344	115,016,205	(42,962,825)	71,875,897	(16,890,333)	54,985,564	122,991,836	177,977,400
Enel Generación Chile Group	Consolidated	591,085,044	2,996,113,733	3,587,198,777	488,183,716	1,125,160,667	1,973,854,394	3,587,198,777	1,638,374,434	(834,936,802)	803,437,632	669,742,608	280,918,860	(58,362,079)	224,783,599	(23,457,536)	201,326,063	(55,986,126)	145,339,937
GasAtacama Chile S.A. Group	Consolidated	-	-	-	-	-	0		186194326	-54061747	132132579	110016642	-107102417	1143576	-103917448	56076224	-47841224	-4396031	(52,237,255)
	December 31, 2018
	Type of Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile Group	Consolidated	296,453,470	982,926,699	1,279,380,169	450,182,594	63,065,351	766,132,224	1,279,380,169	1,263,224,070	(972,499,916)	290,724,154	200,614,083	159,259,319	6,088,801	165,348,120	(42,967,123)	122,380,997	(600,422)	121,780,574
Enel Generación Chile	Separate	548,220,314	2,725,004,288	3,273,224,602	569,928,285	938,139,971	1,765,156,347	3,273,224,603	1,454,348,386	(1,051,644,602)	402,703,784	300,148,133	226,154,177	(49,980,539)	378,187,852	(42,255,124)	335,932,728	(101,720,204)	234,212,523
Enel Distribución Chile	Separate	288,632,068	975,441,251	1,264,073,319	424,550,547	62,721,352	776,801,421	1,264,073,320	1,259,689,827	(971,366,398)	288,323,429	199,676,810	159,625,438	5,418,883	165,044,321	(43,812,619)	121,231,702	(598,985)	120,632,717
Empresa Eléctrica Pehuenche S.A.	Separate	51,279,432	179,693,183	230,972,615	44,459,384	46,238,191	140,275,039	230,972,614	162,768,188	(21,539,174)	141,229,014	135,558,558	128,068,159	224,543	128,348,399	(34,669,191)	93,679,208	—	93,679,208
Enel Green Power Chile Ltda.	Separate	162,710,963	669,741,595	832,452,558	113,123,832	125,240,941	594,087,786	832,452,559	12,831,131	(15,655)	12,815,476	2,521,606	1,702,927	(5,337,680)	71,323,446	1,601,922	72,925,368	71,701,018	144,626,386
Empresa Electrica Panguipulli S.A.	Separate	16,052,462	255,481,676	271,534,138	59,681,465	131,671,924	80,180,749	271,534,138	45,097,744	(5,320,421)	39,777,323	32,476,777	18,680,884	(1,954,238)	16,726,646	(2,647,884)	14,078,762	(3,643,974)	10,434,788
Geotermica del Norte S.A.	Separate	21,765,295	347,871,452	369,636,747	20,910,840	293,675	348,432,232	369,636,747	17,023,794	(2,109,769)	14,914,025	13,168,978	2,001,882	(3,676,151)	(1,674,269)	454,355	(1,219,914)	45,243,420	44,023,506
Parque Eolico Talinay Oriente S.A.	Separate	63,831,605	87,493,829	151,325,434	6,173,259	18,876,242	126,275,934	151,325,435	10,058,036	(2,434,415)	7,623,621	5,310,400	1,014,857	1,312,902	2,327,759	(613,097)	1,714,661	16,552,523	18,267,184
Enel Green Power del Sur	Separate	129,849,852	655,431,547	785,281,399	44,078,091	467,399,245	273,804,063	785,281,399	94,473,391	(21,024,045)	73,449,346	60,053,812	37,537,228	(24,991,814)	12,545,413	(3,455,173)	9,090,240	34,497,623	43,587,863
Enel Green Power Group	Consolidated	344,469,181	1,628,444,820	1,972,914,001	334,639,971	768,719,376	869,554,654	1,972,914,001	183,008,879	(22,330,367)	160,678,512	131,378,740	69,236,957	(38,674,306)	30,471,438	(8,837,176)	21,634,262	173,923,954	195,558,216
Enel Generación Chile Group	Consolidated	672,467,353	2,996,760,726	3,669,228,079	593,881,208	1,077,855,824	1,997,491,047	3,669,228,079	1,529,364,081	(818,284,050)	711,080,031	582,249,559	464,383,396	(47,947,351)	423,152,001	(104,946,765)	318,205,236	(106,994,091)	211,211,145
GasAtacama Chile S.A. Group	Consolidated	154,726,337	601,914,918	756,641,255	61,155,091	94,466,222	601,019,942	756,641,255	271,433,789	(94,746,408)	176,687,381	146,123,452	109,465,013	1,808,644	115,039,230	(27,946,019)	87,093,211	(5,273,886)	81,819,325
	December 31, 2017
	Type of Financial	Current Assets	Non-Current Assets	Total Assets	Current Liabilities	Non-Current Liabilities	Equity	Total Equity and Liabilities	Revenues	Raw Materials and Consumables Used	Contribution Margin	Gross Operating Income	Operating Income	Financial Results	Income before Taxes	Income Taxes	Profit (Loss)	Other Comprehensive Income	Total Comprehensive Income
	Statements	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Enel Distribución Chile Group	Consolidated	261,378,069	893,633,580	1,155,011,649	408,687,866	61,965,918	684,357,865	1,155,011,649	1,333,027,456	(1,062,076,645)	270,950,811	177,188,798	132,510,164	6,411,839	139,079,732	(34,030,322)	105,049,408	1,515,176	106,564,584
Enel Generación Chile S.A.	Separate	590,543,532	2,602,962,586	3,193,506,118	489,875,667	891,083,155	1,812,547,296	3,193,506,118	1,629,277,585	(1,140,707,431)	488,570,154	364,131,027	285,498,271	(37,647,691)	528,254,308	(60,153,339)	468,100,969	72,617,351	540,718,320
Enel Distribucion Chile S.A.	Separate	257,229,219	887,681,380	1,144,910,599	393,273,852	61,523,557	690,113,190	1,144,910,599	1,330,023,450	(1,060,875,186)	269,148,264	176,635,873	133,340,940	5,252,070	138,806,087	(35,037,127)	103,768,960	1,543,151	105,312,110
Empresa Eléctrica Pehuenche S.A.	Separate	35,369,243	186,760,346	222,129,589	38,310,560	48,261,590	135,557,439	222,129,589	152,501,383	(36,289,330)	116,212,053	110,957,039	103,556,904	(395,231)	103,206,672	(26,346,081)	76,860,591	—	76,860,591
Enel Generación Chile Group	Consolidated	662,804,359	2,891,657,830	3,554,462,189	543,356,500	1,022,091,737	1,989,013,952	3,554,462,189	1,634,937,088	(903,978,007)	730,959,081	581,142,074	463,860,015	(36,610,248)	537,641,733	(112,099,519)	425,542,214	67,663,516	493,205,730
GasAtacama Chile S.A. Group	Consolidated	182,143,224	611,319,090	793,462,314	75,370,131	83,894,880	634,197,303	793,462,314	307,272,380	(170,752,796)	136,519,584	106,213,750	70,509,184	1,432,674	80,142,531	(25,417,139)	54,725,392	(3,338,115)	51,387,277

F-127

41.  SUBSEQUENT EVENTS.

On January 30, 2020, the World Health Organization (WHO) declared the outbreak of a novel coronavirus 2019, or COVID-19, “Public Health Emergency of International Concern.” On March 11, 2020, the WHO confirmed that the outbreak of the COVID-19 has risen to the level of a pandemic, which could significantly affect Chile, as well as our trading partners inside and outside the country.

On March 18, 2020, to deal with this international public health emergency of COVID-19, President Sebastián Piñera decreed a state of emergency establishing numerous containment measures, essentially aimed at restricting the free movement of people, which include curfews, selective mandatory quarantines in affected areas, prohibition of mass gatherings and the temporary closure of companies and businesses, among other measures.

In this context, our subsidiary Enel Distribución Chile announced some preventive measures, such as stopping reading meters and focusing activities in the field on operations essential for continuity of supply. Likewise, it announced extraordinary measures to support the most vulnerable families, consisting of the suspension of the cut in supply for non-payment and the offering of payment facilities in installments, without any initial payment and without interest, for those who have a debt with the company.

In parallel, the Chilean Congress has discussed various parliamentary initiatives whose objective is to preserve access to essential services, such as water, electricity, and telecommunications, which seek to support lower-income residential clients, vulnerable clients, microenterprises, and institutions that provide other essential services, such as health facilities. In the case of Enel Chile, the measures contemplated in the different projects of law basically refer to the temporary suspension of the ability of the distribution companies to cut the electricity supply due to late payment, and the rescheduling of the debts that are generated during the state of catastrophe, for the clients that require it.

In this sense, the Group has issued guidelines aimed at ensuring compliance with the measures introduced by the government and taken numerous steps to adopt the most suitable procedures to prevent and/or mitigate the effects of contagion by COVID-19 in the workplace, while ensuring business continuity. This has been possible due to:

· the use of telecommuting for all employees whose jobs can be done remotely, an approach introduced some years ago that required investments in digitalization, allows our people to work remotely at the same level of efficiency and effectiveness;

· the digitization of processes and infrastructure, that ensure the normal operation of our generation assets, the continuity of electricity service and the remote management of all activities relating to the market and our relationship with customers.

Based on the information currently available, in a scenario of continuous evolution, regarding the spread of infections and the containment measures taken by government of Chile, it is not possible at this time to quantify the effects that the COVID-19 pandemic could have in our business. However, because our Group has an integrated business model throughout the value chain, a solid financial structure and a level of digitization that allows us to guarantee the continuity of operational activities with the same level of service, as of the date of presentation of this report, there is no evidence of a significant impact of COVID-19 on the Group.

There have been no other subsequent events between January 1, 2020 and the issuance date of these financial statements.

F-128

APPENDIX 1 DETAILS OF ASSETS AND LIABILITIES IN FOREIGN CURRENCY:

This appendix forms an integral part of the Group’s consolidated financial statements. The detail of assets and liabilities denominated in foreign currency is as follows:

	12-31-2019
ASSETS	U.F.	Chilean Peso		U.S. dollar		Euro		Colombian Peso		Angentine Peso		Brazilian Real		Total
	ThCh$	ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$		ThCh$
CURRENT ASSETS
Cash and cash equivalents	-	209,818,277		18,115,385		654,319		-		7,096,519		-		235,684,500
Other current financial assets	707,749	280,529		322,317		-		-		-		-		1,310,595
Other current non-financial assets	-	34,098,847		535,716		-		-		-		-		34,634,563
Trade and other current receivables	-	500,407,168		10,964,072		84,090		-		-		-		511,455,330
Current accounts receivable from related parties	-	3,419,722		40,603,423		22,859,682		833,336		-		465,970		68,182,133
Inventories	53,034	34,959,079		4,212,534		447,603		-		-		-		39,672,250
Current tax assets	-	117,532,553		9,740,736		-		-		-		-		127,273,289
TOTAL CURRENT ASSETS	760,783	900,516,175		84,494,183		24,045,694		833,336		7,096,519		465,970		1,018,212,660
NON-CURRENT ASSETS
Other non-current financial assets	-	7,220,618		2		-		-		-		-		7,220,620
Other non-current non-financial assets	56,950	37,993,234		-		-		-		-		-		38,050,184
Trade and other non-current receivables	-	146,276,706		167,297,679		-		-		-		-		313,574,385
Non-current accounts receivable from related parties	-	-		34,407,142		-		-						34,407,142
Investments accounted for using the equity method	-	7,928,588		-		-		-		-		-		7,928,588
Intangible assets other than goodwill	-	86,594,286		45,684,307		-		-		-		-		132,278,593
Goodwill	-	909,078,058		8,274,916		-		-		-		-		917,352,974
Property, plant and equipment	35,346,435	3,678,912,343		1,638,296,993		7,763,853		-		-		-		5,360,319,624
Investment property	-	6,795,155		-		-		-		-		-		6,795,155
Deferred tax assets	-	6,530,201		15,318,038		-		-		-		-		21,848,239
TOTAL NON CURRENT ASSETS	35,403,385	4,887,329,189		1,909,279,077		7,763,853		-		-		-		6,839,775,504
TOTAL ASSETS	36,164,168	5,787,845,364	-	1,993,773,260	-	31,809,547	-	833,336	-	7,096,519	-	465,970	-	7,857,988,164

0
	12-31-2018
	UF	Chilean Peso	U.S. dollar	Euro	Colombian Peso	Angentine Peso	Brazilian Real	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT ASSETS
Cash and cash equivalents	-	222,434,412	16,575,872	103,847	-	6,057,793	-	245,171,924
Other current financial assets	689,145	644,618	38,969,410	-	-	-	-	40,303,173
Other current non-financial assets	816,871	17,838,717	2,832,782	-	-	917,718	-	22,406,088
Trade and other current receivables	-	474,941,686	3,193,959	3,905	-	30,517	-	478,170,067
Current accounts receivable from related parties	-	20,673,951	6,997,861	26,475,919	-	-	23,329	54,171,060
Inventories	-	52,510,509	4,451,134	-	-	-	-	56,961,643
Current tax assets	-	99,614,294	3,678	-	-	145,845	-	99,763,817
TOTAL CURRENT ASSETS	1,506,016	888,658,187	73,024,696	26,583,671	-	7,151,873	23,329	996,947,772
NON-CURRENT ASSETS
Other non-current financial assets	689,145	2,352,896	4,227,628	-	-	-	-	7,269,669
Other non-current non-financial assets	-	44,390,009	-	-	-	218,003	-	44,608,012
Trade and other non-current receivables	10,005,806	33,425,943	17,074,839	-	-	21,255	-	60,527,843
Non-current accounts receivable from related parties	-	-	-	-	-	-	-	-
Investments accounted for using the equity method	-	9,520,350	3,052,983	-	-	300,198	-	12,873,531
Intangible assets other than goodwill	-	70,247,490	44,865,424	-	-	259,479	-	115,372,393
Goodwill	-	907,404,478	7,640,247	-	-	-	-	915,044,725
Property, plant and equipment	-	3,769,310,697	1,523,774,815	-	-	15,562,121	-	5,308,647,633
Investment property	-	7,557,356		-	-	-	-	7,557,356
Deferred tax assets	-	1,115,799	18,055,431	-	-	-	-	19,171,230
TOTAL NON CURRENT ASSETS	10,694,951	4,845,325,018	1,618,691,367	-	-	16,361,056	-	6,491,072,392
TOTAL ASSETS	12,200,967	5,733,983,205	1,691,716,063	26,583,671	-	23,512,929	23,329	7,488,020,164

F-129

			12-31-2019
LIABILITIES	U.F.	Chilean Peso	U.S. dollar	Euro	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	35,217,441	20,005	178,791,077	628,053	-	214,656,576
Trade and other current payables	5,215,585	523,504,426	66,209,531	4,333,666	-	599,263,208
Current accounts payable to related parties	-	38,133,907	11,910,024	109,765,956	-	159,809,887
Other current provisions	-	4,065,965	-	-	-	4,065,965
Current tax liabilities	-	17,940,784	55,049	-	-	17,995,833
Other current non-financial liabilities	254,084	38,929,298	2,933,274	3,391,727	-	45,508,383
TOTAL CURRENT LIABILITIES	40,687,110	622,594,385	259,898,955	118,119,402	-	1,041,299,852
NON-CURRENT LIABILITIES
Other non-current financial liabilities	301,707,185	68,922	1,431,324,011	7,069,801	-	1,740,169,919
Trade and other non-current payables	-	27,661	56,222,424	-	-	56,250,085
Non-current accounts receivable to related parties	-	-	486,839,483	297,534,001	-	784,373,484
Other long-term provisions	-	155,315,044	16,545,238	-	-	171,860,282
Deferred tax liabilities	-	161,017,178	88,267,463	-	-	249,284,641
Non-current provisions for employee benefits	-	65,531,375	632,115	-	-	66,163,490
Other non-current non-financial liabilities	-	1,302,759	-	-	-	1,302,759
TOTAL NON-CURRENT LIABILITIES	301,707,185	383,262,939	2,079,830,734	304,603,802	-	3,069,404,660
TOTAL LIABILITIES	342,394,295	1,005,857,324	2,339,729,689	422,723,204	-	4,110,704,512

			12-31-2018
LIABILITIES	U.F.	Chilean Peso	U.S. dollar	Euro	Argentine Peso	Total
	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
CURRENT LIABILITIES
Other current financial liabilities	32,142,094	212,736,911	165,786,810	-	-	410,665,815
Trade and other current payables	3,598,849	503,689,338	44,138,753	2,347,924	511,460	554,286,324
Current accounts payable to related parties	-	74,991,622	324,743	82,619,960	-	157,936,325
Other current provisions	-	5,551,609	12,510	-	24,667	5,588,786
Current tax liabilities	-	17,243,717	22,626	-	411,577	17,677,920
Other current non-financial liabilities	-	68,532,059	2,766,862	-	10,061	71,308,982
TOTAL CURRENT LIABILITIES	35,740,943	882,745,256	213,052,304	84,967,884	957,765	1,217,464,152
NON-CURRENT LIABILITIES
Other non-current financial liabilities	297,118,435	-	1,408,715,068	-	-	1,705,833,503
Trade and other non-current payables	-	2,553,056	31,124	-	-	2,584,180
Non-current accounts receivable to related parties	-	-	447,193,802	-	-	447,193,802
Other long-term provisions	-	93,478,990	12,392,385	-	-	105,871,375
Deferred tax liabilities	-	203,349,899	74,730,155	-	-	278,080,054
Non-current provisions for employee benefits	-	56,070,439	532,225	-	-	56,602,664
Other non-current non-financial liabilities	-	226,653	-	-	-	226,653
TOTAL NON-CURRENT LIABILITIES	297,118,435	355,679,037	1,943,594,759	-	-	2,596,392,231
TOTAL LIABILITIES	332,859,378	1,238,424,293	2,156,647,063	84,967,884	957,765	3,813,856,383

F-130

APPENDIX 2 ADDITIONAL INFORMATION OFICIO CIRCULAR (OFFICIAL BULLETIN) No. 715 OF FEBRUARY 3, 2012:

This appendix forms an integral part of these consolidated financial statements.

a)    Portfolio stratification

· Trade and other receivables by aging:

	As of December 31, 2019
	Current Portfolio	1-30 days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current	TotalNon- Current
Trade and Other Receivables	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	393,746,637	32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	47,236,887	500,040,783	191,966,929
Impairment provision	(3,148,393)	(357,214)	(484,022)	(587,103)	(677,088)	(845,948)	(804,567)	(1,413,915)	(1,114,081)	(34,055,770)	(43,488,101)	—
Accounts receivable for leasing, gross	13,158,795	—	—	—	—	—	—	—	—	—	13,158,795	117,873,340
Impairment provision	(2,036,917)	—	—	—	—	—	—	—	—	—	(2,036,917)	—
Other receivables, gross	43,836,460	—	—	—	—	—	—	—	—	9,883,938	53,720,398	3,734,116
Impairment provision	(55,690)	—	—	—	—	—	—	—	—	(9,883,938)	(9,939,628)	—
Total	445,500,892	32,102,797	7,445,293	4,113,180	2,320,709	1,908,418	2,233,138	1,253,184	1,396,602	13,181,117	511,455,330	313,574,385
	As of December 31, 2018
	Current Portfolio	1-30 days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current	TotalNon- Current
Trade and Other Receivables	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Trade receivables, gross	360,967,952	26,520,834	8,065,762	3,947,386	2,096,447	1,400,998	1,945,691	1,528,489	2,863,502	47,716,556	457,053,617	2,046,845
Allowance for doubtful accounts	(1,309,684)	(244,773)	(260,401)	(317,546)	(419,163)	(523,349)	(584,135)	(634,104)	(2,085,824)	(32,747,456)	(39,126,435)	—
Other receivables, gross	60,242,885	—	—	—	—	—	—	—	—	10,353,445	70,596,330	58,480,998
Allowance for doubtful accounts	—	—	—	—	—	—	—	—	—	(10,353,445)	(10,353,445)	—
Total	419,901,153	26,276,061	7,805,361	3,629,840	1,677,284	877,649	1,361,556	894,385	777,678	14,969,100	478,170,067	60,527,843

F-131

· By type of portfolio:

	December 31, 2019						December 31, 2018
	Non-renegotiatedPortfolio		RenegotiatedPortfolio		Total Gross Portfolio		Non-renegotiatedPortfolio		RenegotiatedPortfolio		Total Gross Portfolio
	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount	Number of	Gross Amount
Aging of balances	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$	Customers	ThCh$
Current	1,340,828	469,633,677	36,952	116,079,889	1,377,780	585,713,566	1,370,536	353,865,825	42,898	9,101,666	1,413,434	362,967,491
1 to 30 days	433,225	30,871,310	21,280	1,588,701	454,505	32,460,011	390,536	25,894,683	19,304	626,151	409,840	26,520,834
31 to 60 days	106,521	7,630,607	8,018	298,708	114,539	7,929,315	83,029	7,864,638	6,649	201,124	89,678	8,065,762
61 to 90 days	17,349	4,363,345	2,080	336,938	19,429	4,700,283	14,466	3,827,182	2,014	120,204	16,480	3,947,386
91 to 120 days	11,084	2,852,961	1,661	144,836	12,745	2,997,797	7,515	2,007,221	1,182	89,226	8,697	2,096,447
121 to 150 days	5,819	2,510,766	1,256	243,600	7,075	2,754,366	4,393	1,266,995	892	134,003	5,285	1,400,998
151 to 180 days	3,962	2,863,659	544	174,046	4,506	3,037,705	3,007	1,697,721	459	247,970	3,466	1,945,691
181 to 210 days	3,647	2,571,731	377	95,368	4,024	2,667,099	2,805	1,446,409	311	82,080	3,116	1,528,489
211 to 250 days	2,677	2,421,028	342	89,655	3,019	2,510,683	3,237	2,772,883	311	90,619	3,548	2,863,502
More than 251 days	114,518	46,531,813	6,517	705,074	121,035	47,236,887	20,876	47,255,348	5,769	508,514	26,645	47,763,862
Total	2,039,630	572,250,897	79,027	119,756,815	2,118,657	692,007,712	1,900,400	447,898,905	79,789	11,201,557	1,980,189	459,100,462

b) Portfolio in default and in legal collection process

	As of December 31,
	2019		2018
	Numberof	Amount	Numberof	Amount
Portfolio in Default and in Legal Collection Process	Customers	ThCh$	Customers	ThCh$
Notes receivable in default	1,888	258,073	1,876	258,372
Notes receivable in legal collection process (*)	1,287	6,313,513	2,238	10,450,383
Total	3,175	6,571,586	4,114	10,708,755

(*)Legal collections are included in the portfolio in arrears.

c)    Provisions and write-offs

	As of December 31,
	2019	2018
Provisions and Write-offs	ThCh$	ThCh$
Provision for non-renegotiated portfolio	4,403,135	2,318,330
Provision for renegotiated portfolio	5,643,865	2,461,643
Recoveries of the period	—	3,099
Total	10,047,000	4,783,072

d)    Number and value of operations

	December 31, 2019		December 31, 2018
	Totaldetail by type of operation	Totaldetail by type of operation	Totaldetail by type of operation	Totaldetail by type of operation
Number and Value of Operations	LastQuarter	Year-to-date	Last Quarter	Year-to-date
Impairment provisions and recoveries:
Number of operations	52,870	88,750	7,357	19,810
Value of operations, in ThCh$	2,451,690	10,047,000	1,596,443	4,783,072

F-132

APPENDIX 2.1 SUPPLEMENTARY INFORMATION ON TRADE RECEIVABLES:

This appendix forms an integral part of these consolidated financial statements.

a)Portfolio stratification

· Trade receivables by aging:

		December 31, 2019
	Current Portfolio		1-30days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	More than 365 days	Total Current Gross Portfolio	TotalNon- Current Gross Portfolio
Type of Portfolio	ThCh$		ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION
Non-renegotiated portfolio	199,019,252		2,888,824	224 ,770	705,885	404,757	116,371	787,421	187,920	592,987	1,354,217	6,240,193	212,522,597	86,403,772
- Large customers	193,125,348		2,763,610	43,392	551,201	290,439	13,672	574,794	78,802	487,520	846,079	4,944,351	203,719,208	86,403,772
- Institutional customers	—		—	—	—	—	—	—	—	—	—	—	—	—
- Others	5,893,904		125,214	181,378	154,684	114,318	102,699	212,627	109,118	105,467	508,138	1,295,842	8,803,389	—
Allowance for impairment	(10,907)		(260)	(200)	(142)	(103)	(93)	(258)	(154)	(98)	(577)	(2,901,975)	(2,914,767)	—
Unbilled services	142,968,302		—	—	—	—	—	—	—	—	—	—	142,968,302	—
Billed services	56,050,950		2,888,824	224,770	705,885	404,757	116,371	787,421	187,920	592,987	1,354,217	6,240,193	69,554,295	86,403,772
DISTRIBUTION
Non-renegotiated portfolio	194,727,385		29,571,187	7,704,545	3,994,398	2,593,040	2,637,995	2,250,284	2,479,179	1,917,696	3,635,526	36,006,951	287,518,186	105,563,157
- Mass-market customers	144,845,823		21,084,861	5,054,606	1,889,878	1,672,041	1,384,133	1,257,238	922,539	789,642	2,097,222	24,433,032	205,431,015	103,267,572
- Large customers	44,406,790		6,202,698	1,154,539	421,771	95,168	271,785	448,510	209,272	206,091	775,558	5,784,217	59,976,399	7,086
- Institutional customers	5,474,772		2,283,628	1,495,400	1,682,749	825,831	982,077	544,536	1,347,368	921,963	762,746	5,789,702	22,110,772	2,288,499
Allowance for impairment	(3,137,486)		(356,954)	(483,822)	(586,961)	(676,985)	(845,855)	(804,309)	(1,413,761)	(1,113,983)	(2,476,763)	(28,676,455)	(40,573,334)	—
Unbilled services	141,740,569		—	—	—	—	—	—	—	—	—	—	141,740,569	—
Billed services	52,986,816		29,571,187	7,704,545	3,994,398	2,593,040	2,637,995	2,250,284	2,479,179	1,917,696	3,635,526	36,006,951	145,777,617	105,563,157
Total Gross Portfolio	393,746,637		32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	4,989,743	42,247,144	500,040,783	191,966,929
Total allowance for impairment	(3,148,393)		(357,214)	(484,022)	(587,103)	(677,088)	(845,948)	(804,567)	(1,413,915)	(1,114,081)	(2,477,340)	(31,578,430)	(43,488,101)	—
Total Net Portfolio	390,598,244		32,102,797	7,445,293	4,113,180	2,320,709	1,908,418	2,233,138	1,253,184	1,396,602	2,512,403	10,668,714	456,552,682	191,966,929

	December 31, 2018
	Current Portfolio	1-30days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	More than 365 days	Total Current Gross Portfolio	TotalNon- Current Gross Portfolio
Type of Portfolio	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION
Non-renegotiated portfolio	206,893,035	1,155,988	1,453,308	708,552	203,487	7,836	39,787	483,751	153,929	1,300,506	5,415,159	217,815,338	21,255
- Large customers	198,424,050	671,037	248,135	140,571	224	7,274	39,001	43,681	56,046	787,999	5,047,281	205,465,299	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—	—
- Others	8,468,985	484,951	1,205,173	567,981	203,263	562	786	440,070	97,883	512,507	367,878	12,350,039	21,255
Allowance for impairment	(21,736)	—	—	—	—	—	—	—	—	—	(1,505,948)	(1,527,684)	—
Unbilled services	165,128,644	—	—	—	—	—	—	—	—	—	—	165,128,644	—
Billed services	41,764,391	1,155,988	1,453,308	708,552	203,487	7,836	39,787	483,751	153,929	1,300,506	5,415,159	52,686,694	21,255
DISTRIBUTION
Non-renegotiated portfolio	154,074,917	25,364,846	6,612,454	3,238,834	1,892,960	1,393,162	1,905,904	1,044,738	2,709,573	4,596,217	36,404,674	239,238,279	2,025,590
- Mass-market customers	108,952,722	16,661,831	3,571,670	1,427,141	1,076,288	850,571	715,174	531,508	2,195,894	1,759,264	23,737,029	161,479,092	2,000,955
- Large customers	38,529,866	6,924,749	1,662,569	1,225,278	102,522	475	918,487	124,385	164,424	1,619,025	6,326,539	57,598,319	24,635
- Institutional customers	6,592,329	1,778,266	1,378,215	586,415	714,150	542,116	272,243	388,845	349,255	1,217,928	6,341,106	20,160,868	—
Allowance for impairment	(1,287,948)	(244,773)	(260,401)	(317,546)	(419,163)	(523,349)	(584,135)	(634,104)	(2,085,824)	(2,255,798)	(28,985,710)	(37,598,751)	—
Unbilled services	92,576,381	—	—	—	—	—	—	—	—	—	—	92,576,381	—
Billed services	61,498,536	25,364,846	6,612,454	3,238,834	1,892,960	1,393,162	1,905,904	1,044,738	2,709,573	4,596,217	36,404,674	146,661,898	2,025,590
Total Gross Portfolio	360,967,952	26,520,834	8,065,762	3,947,386	2,096,447	1,400,998	1,945,691	1,528,489	2,863,502	5,896,723	41,819,833	457,053,617	2,046,845
Total allowance for impairment	(1,309,684)	(244,773)	(260,401)	(317,546)	(419,163)	(523,349)	(584,135)	(634,104)	(2,085,824)	(2,255,798)	(30,491,658)	(39,126,435)	—
Total Net Portfolio	359,658,268	26,276,061	7,805,361	3,629,840	1,677,284	877,649	1,361,556	894,385	777,678	3,640,925	11,328,175	417,927,182	2,046,845

F-133

Since not all of our commercial databases in our Group’s subsidiaries distinguish whether the final electricity service consumer is a natural or legal person, the main management segmentation used by all the consolidated entities to monitor and follow up on trade receivables is the following:

· Mass-market customers

· Large customers

· Institutional customers

· By type of portfolio:

	December 31, 2019
	Current Portfolio	1-30days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current Gross Portfolio	TotalNon- Current Gross Portfolio
Type of Portfolio	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION
Non-renegotiated portfolio	199,019,252	2,888,824	224,770	705,885	404,757	116,371	787,421	187,920	592,987	7,594,410	212,522,597	86,403,772
- Large customers	193,125,348	2,763,610	43,392	551,201	290,439	13,672	574,794	78,802	487,520	5,790,430	203,719,208	86,403,772
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	5,893,904	125,214	181,378	154,684	114,318	102,699	212,627	109,118	105,467	1,803,980	8,803,389	—
Renegotiated portfolio	—	—	—	—	—	—	—	—	—	—	—	—
- Large customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	—	—	—	—	—	—	—	—	—	—	—	—
DISTRIBUTION
Non-renegotiated portfolio	184,125,135	27,982,486	7,405,837	3,657,460	2,448,204	2,394,395	2,076,238	2,383,811	1,828,041	38,937,403	273,239,010	85,518
- Mass-market customers	136,847,474	20,324,155	4,780,197	1,556,017	1,527,205	1,162,547	1,083,203	827,171	699,987	26,043,745	194,851,701	85,518
- Large customers	44,252,680	6,148,385	1,130,250	421,771	95,168	271,785	448,510	209,272	206,091	4,961,884	58,145,796	—
- Institutional customers	3,024,981	1,509,946	1,495,390	1,679,672	825,831	960,063	544,525	1,347,368	921,963	7,931,774	20,241,513	—
Renegotiated portfolio	10,602,250	1,588,701	298,708	336,938	144,836	243,600	174,046	95,368	89,655	705,074	14,279,176	105,477,639
- Mass-market customers	7,998,348	760,707	274,411	333,861	144,836	221,586	174,035	95,368	89,655	486,509	10,579,316	103,182,054
- Large Customers	154,110	54,312	24,288	—	—	—	—	—	—	46,775	279,485	7,086
- Institutional Customers	2,449,792	773,682	9	3,077	—	22,014	11	—	—	171,790	3,420,375	2,288,499
Total Gross Portfolio	393,746,637	32,460,011	7,929,315	4,700,283	2,997,797	2,754,366	3,037,705	2,667,099	2,510,683	47,236,887	500,040,783	191,966,929

	December 31, 2018
	Current Portfolio	1-30days	31-60 days	61-90 days	91-120 days	121-150 days	151-180 days	181-210 days	211-250 days	More than 251 days	Total Current Gross Portfolio	TotalNon- Current Gross Portfolio
Type of Portfolio	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
GENERATION
Non-renegotiated portfolio	206,862,868	1,155,988	1,453,308	708,552	203,487	7,836	39,787	483,751	153,929	6,715,665	217,785,171	—
- Large customers	198,424,050	671,037	248,135	140,571	224	7,274	39,001	43,681	56,046	5,835,279	205,465,298	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	8,438,818	484,951	1,205,173	567,981	203,263	562	786	440,070	97,883	880,386	12,319,873	—
Renegotiated portfolio	30,167	—	—	—	—	—	—	—	—	—	30,167	21,255
- Large customers	—	—	—	—	—	—	—	—	—	—	—	—
- Institutional customers	—	—	—	—	—	—	—	—	—	—	—	—
- Others	30,167	—	—	—	—	—	—	—	—	—	30,167	21,255
DISTRIBUTION
Non-renegotiated portfolio	146,934,065	24,738,695	6,411,330	3,118,630	1,803,734	1,259,159	1,657,934	962,658	2,618,954	40,492,377	229,997,536	116,198
- Mass-market customers	101,990,338	16,096,927	3,374,622	1,306,937	987,071	716,568	577,969	449,428	2,105,275	25,035,379	152,640,514	116,198
- Large customers	38,401,049	6,873,601	1,662,570	1,225,278	102,522	475	918,487	124,385	164,424	7,898,789	57,371,580	—
- Institutional customers	6,542,678	1,768,167	1,374,138	586,415	714,141	542,116	161,478	388,845	349,255	7,558,209	19,985,442	—
Renegotiated portfolio	7,140,852	626,151	201,124	120,204	89,226	134,003	247,970	82,080	90,619	508,514	9,240,743	1,909,392
- Mass-market customers	6,962,383	564,903	197,048	120,204	89,217	134,003	137,205	82,080	90,619	460,914	8,838,576	1,884,757
- Large Customers	128,817	51,148	—	—	—	—	—	—	—	46,775	226,740	24,635
- Institutional Customers	49,652	10,100	4,076	—	9	—	110,765	—	—	825	175,427	—
Total Gross Portfolio	360,967,952	26,520,834	8,065,762	3,947,386	2,096,447	1,400,998	1,945,691	1,528,489	2,863,502	47,716,556	457,053,617	2,046,845

F-134

APPENDIX 2.2 ESTIMATED SALES AND PURCHASES OF ENERGY AND CAPACITY:

This appendix forms an integral part of these consolidated financial statements.

	12-31-2019		12-31-2018
	Energy and Capacity	Tolls	Energy and Capacity	Tolls
STATEMENT OF FINANCIAL POSITION	ThCh$	ThCh$	ThCh$	ThCh$
Trade and other current receivables	310,301,370	13,929,209	209,288,934	46,336,070
Total Estimated Assets	310,301,370	13,929,209	209,288,934	46,336,070
Trade and other current payables	125,130,599	20,059,576	106,633,306	37,530,511
Total Estimated Liabilities	125,130,599	20,059,576	106,633,306	37,530,511

	12-31-2019		12-31-2018
	Energy and Capacity	Tolls	Energy and Capacity	Tolls
INCOME STATEMENT	ThCh$	ThCh$	ThCh$	ThCh$
Energy Sales	310,301,370	13,929,209	209,288,934	46,336,070
Energy Purchases	125,130,599	20,059,576	106,633,306	37,530,511

F-135

APPENDIX 3 DETAILS OF DUE DATES OF PAYMENTS TO SUPPLIERS:

This appendix forms an integral part of these consolidated financial statements.

	December 31, 2019				December 31, 2018
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers with Current Payments	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Up to 30 days	101,666,302	148,397,518	121,111,092	371,174,912	45,355,153	230,133,777	78,973,248	354,462,178
From 31 to 60 days	5,579,618	71,069,622	219,965	76,869,205	4,284,025	19,179,502	71,745,150	95,208,677
From 61 to 90 days	9,045,950	1,118,102	11,177,955	21,342,007	16,452,406	—	—	16,452,406
From 91 to 120 days	—	—	—	—	—	—	—	—
From 121 to 365 days	48,102,870	—	—	48,102,870	—	—	—	—
More than 365 days	—	487	56,222,424	56,222,911	—	6,766	2,106,099	2,112,865
Total	164,394,740	220,585,729	188,731,436	573,711,905	66,091,584	249,320,045	152,824,497	468,236,126

	December 31, 2019				December 31, 2018
	Goods	Services	Other	Total	Goods	Services	Other	Total
Suppliers details	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$	ThCh$
Suppliers for energy purchase	-	63,364,701	168,730,485	232,095,186	-	155,123,059	-	155,123,059
Suppliers for fuel and gas purchases	-	55,179,023	-	55,179,023	39,787,839	-	-	39,787,839
Accounts payable for goods and services	81,807,039	102,042,005	-	183,849,044	-	94,196,986	60,864,246	155,061,232
Accounts payable for asset purchases	82,587,701	-	20,000,951	102,588,652	26,303,745	-	91,960,251	118,263,996
Total	164,394,740	220,585,729	188,731,436	573,711,905	66,091,584	249,320,045	152,824,497	468,236,126

F-136