UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)

☐	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (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
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 . . . . . . . . . . . . . . . . . . .

FOR THE TRANSACTION PERIOD FORM                       TO                        

Commission file number: 1-13314

华能国际电力股份有限公司

HUANENG POWER INTERNATIONAL, INC.
(Exact name of Registrant as specified in its charter)

PEOPLE’S REPUBLIC OF CHINA
(Jurisdiction of incorporation or organization)

HUANENG BUILDING
6 FUXINGMENNEI STREET, XICHENG DISTRICT, BEIJING, PEOPLE’S REPUBLIC OF CHINA
(Address of principal executive offices)

Mr. Huang Chaoquan
HUANENG BUILDING,
6 FUXINGMENNEI STREET, XICHENG DISTRICT, BEIJING, PEOPLE’S REPUBLIC OF CHINA
Tel: +86 (10) 6322 6999 Fax: +86 (10) 6322 6888
(Name, Telephone, Email 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 Each Representing 40 Overseas Listed Shares	HNP	New York Stock Exchange
Overseas Listed Shares with Par Value of RMB1.00 Per Share		New York Stock Exchange*

*Not for trading, but only in connection with the registration of our American Depositary Shares

Securities registered or to be registered pursuant to Section 12(g) of the Act.

NONE

(Title of Class)

_____________________

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

NONE

(Title of Class)

_____________________

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:

Domestic A Shares with Par Value of RMB1.00 Per Share	10,997,709,919
Overseas Listed Shares with Par Value of RMB1.00 Per Share	4,700,383,440

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 ☒

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

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 (§232.405 of this chapter) 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 ☐

(Do not check if a smaller reporting 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 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 ☒

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes ☐ No ☐

TABLE OF CONTENTS

PART I				3
	ITEM 1	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS		3
	ITEM 2	OFFER STATISTICS AND EXPECTED TIMETABLE		3
	ITEM 3	KEY INFORMATION		3
		A.	Selected financial data	3
		B.	Capitalization and indebtedness	4
		C.	Reasons for the offer and use of proceeds	4
		D.	Risk factors	5
	ITEM 4	INFORMATION ON THE COMPANY		17
		A.	History and development of the Company	17
		B.	Business overview	18
		C.	Organizational structure	30
		D.	Property, plants and equipment	31
	ITEM 4A	UNRESOLVED STAFF COMMENTS		83
	ITEM 5	OPERATING AND FINANCIAL REVIEWS AND PROSPECTS		83
		A.	General	83
		B.	Operating results	85
		C.	Financial position	101
		D.	Liquidity and cash resources	102
		E.	Trend information	106
		F.	Employee benefits	107
		G.	Guarantees for loans and restricted assets	107
		H.	Off-balance sheet arrangements	108
		I.	Performance of significant investments and their prospects	108
		J.	Tabular disclosure of contractual obligations and commercial commitments	108
		K.	Impairment sensitivity analysis	109
		L.	Prospects for 2020	110
	ITEM 6	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES		111
		A.	Directors, members of the supervisory committee and senior management	111
		B.	Compensation for Directors, Supervisors and Executive Officers	114
		C.	Board practice	115
		D.	Employees	116
		E.	Share ownership	117
	ITEM 7	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS		117
		A.	Major shareholders	117
		B.	Related party transactions	119
		C.	Interests of experts and counsel	123
	ITEM 8	FINANCIAL INFORMATION		123
		A.	Consolidated statements and other financial information	123
		B.	Significant changes	124
	ITEM 9	THE OFFER AND LISTING		124
		A.	Offer and listing details and markets	124
	ITEM 10	ADDITIONAL INFORMATION		124
		A.	Share capital	124
		B.	Memorandum and articles of association	124
		C.	Material contracts	131
		D.	Exchange controls	131
		E.	Taxation	131
		F.	Dividends and paying agents	137
		G.	Statement by experts	137
		H.	Documents on display	137
		I.	Subsidiary information	137

	ITEM 11	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		137
	ITEM 12	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		142
		A.	Debt Securities	142
		B.	Warrants and Rights	142
		C.	Other Securities	142
		D.	American Depositary Shares	142
PART II				144
	ITEM 13	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		144
	ITEM 14	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS		144
	ITEM 15	CONTROLS AND PROCEDURES		144
	ITEM 16	RESERVED		144
	ITEM 16A	AUDIT COMMITTEE FINANCIAL EXPERT		144
	ITEM 16B	CODE OF ETHICS		145
	ITEM 16C	PRINCIPAL ACCOUNTANT FEES AND SERVICES		145
	ITEM 16D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES		146
	ITEM 16E	PURCHASES OF EQUITY SECURITY BY THE ISSUER AND AFFILIATED PURCHASERS		146
	ITEM 16F	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT		146
	ITEM 16G	CORPORATE GOVERNANCE		147
	ITEM 16H	MINE SAFETY DISCLOSURE		150
	ITEM 17	FINANCIAL STATEMENTS		150
	ITEM 18	FINANCIAL STATEMENTS		150
	ITEM 19	EXHIBITS		150

INTRODUCTION

We maintain our accounts in Renminbi Yuan (“Renminbi” or “RMB”), the lawful currency of the People’s Republic of China (the “PRC” or “China”). References herein to “US$” or “U.S. dollars” are to United States Dollars, references to “HK$” are to Hong Kong Dollars, and references to “S$” are to Singapore Dollars. References to ADRs and ADSs are to American Depositary Receipts and American Depositary Shares, respectively. Translations of amounts from Renminbi to U.S. Dollars are solely for the convenience of the reader. Unless otherwise indicated, any translations from Renminbi to U.S. Dollars or from U.S. Dollars to Renminbi were translated at the middle exchange rate announced by the People’s Bank of China (the “PBOC Rate”) on December 31, 2019 of US$1.00 to RMB 6.9762. No representation is made that the Renminbi or U.S. Dollar amounts referred to herein could have been or could be converted into U.S. Dollars or Renminbi, as the case may be, at the PBOC Rate or at all.

References to “A Shares” are to common tradable shares issued to PRC domestic shareholders.

References to the “central government” are to the national government of the PRC and its various ministries, agencies and commissions.

References to the “Company,” “we,” “our” and “us” include, unless the context requires otherwise, Huaneng Power International, Inc. and the operations of our power plants and our construction projects.

References to “HIPDC” are to Huaneng International Power Development Corporation and, unless the context requires otherwise, include the operations of the Company prior to the formation of the Company on June 30, 1994.

References to “Huaneng Group” are to China Huaneng Group Co., Ltd.

References to “local governments” in the PRC are to governments at all administrative levels below the central government, including provincial governments, governments of municipalities directly under the central government, municipal and city governments, county governments and township governments.

References to “our power plants” are to the power plants that are wholly owned by the Company or to the power plants in which the Company owns majority equity interests.

References to the “PRC Government” include the central government and local governments.

References to “provinces” include provinces, autonomous regions and municipalities directly under the central government.

References to “Singapore” are to the Republic of Singapore.

References to “tons” are to metric tons.

Previously, the Overseas Listed Foreign Shares were also referred to as the “Class N Ordinary Shares” or “N Shares.” Since January 21, 1998, the date on which the Overseas Listed Foreign Shares were listed on The Stock Exchange of Hong Kong Limited by way of introduction, the Overseas Listed Foreign Shares have been also referred to as “H Shares.”

GLOSSARY

actual generation	The total amount of electricity generated by a power plant over a given period of time.
auxiliary power	Electricity consumed by a power plant in the course of generation.
availability factor	For any period, the ratio (expressed as a percentage) of a power plant’s available hours to the total number of hours in such period.
available hours	For a power plant for any period, the total number of hours in such period less the total number of hours attributable to scheduled maintenance and planned overhauls as well as to forced outages, adjusted for partial capacity outage hours.
capacity factor	The ratio (expressed as a percentage) of the gross amount of electricity generated by a power plant in a given period to the product of (i) the number of hours in the given period multiplied by (ii) the power plant’s installed capacity.
demand	For an integrated power system, the amount of power demanded by consumers of energy at any point in time.
dispatch	The schedule of production for all the generating units on a power system, generally varying from moment to moment to match production with power requirements. As a verb, to dispatch a plant means to direct the plant to operate.
GW	Gigawatt. One million kilowatts.
GWh	Gigawatt-hour. One million kilowatt-hours. GWh is typically used as a measure for the annual energy production of large power plants.
installed capacity	The manufacturers’ rated power output of a generating unit or a power plant, usually denominated in MW.
kV	Kilovolt. One thousand volts.
kW	Kilowatt. One thousand watts.
kWh	Kilowatt-hour. The standard unit of energy used in the electric power industry. One kilowatt-hour is the amount of energy that would be produced by a generator producing one thousand watts for one hour.
MVA	Million volt-amperes. A unit of measure used to express the capacity of electrical transmission equipment such as transformers.
MW	Megawatt. One million watts. The installed capacity of power plants is generally expressed in MW.
MWh	Megawatt-hour. One thousand kilowatt-hours.
peak load	The maximum demand on a power plant or power system during a specific period of time.
planned generation	An annually determined target gross generation level for each of our operating power plants used as the basis for determining planned output.
total output	The actual amount of electricity sold by a power plant in a particular year, which equals total generation less auxiliary power.
transmission losses	Electric energy that is lost in transmission lines and therefore is unavailable for use.

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

Our consolidated data of financial position as of December 31, 2019 and 2018 and the consolidated statements of comprehensive income and cash flow data for each of the years in the three-year period ended December 31, 2019 are derived from the historical financial statements included herein. Our consolidated data of financial position as of December 31, 2017, 2016 and 2015 and consolidated statements of comprehensive income and cash flow data for each of the years in the two-year period ended December 31, 2016 are derived from the historical financial statements not included herein. The Selected Financial Data should be read in conjunction with the consolidated financial statements and “Item 5 Operating and Financial Reviews and Prospects.” The financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. The Selected Financial Data may not be indicative of future earnings, cash flows or financial position.

	Year Ended December 31,
	2015			2016			2017			2018			2019
	RMB in thousands, except per share data
Consolidated Statements of Comprehensive Income Data
Operating revenue		128,904,873			113,814,236			152,459,444			169,550,624			174,009,401
Tax and levies on operations		(1,157,760	)		(1,177,818	)		(1,376,312	)		(1,788,998	)		(1,832,975	)
Operating expenses		(98,604,187	)		(94,258,678	)		(141,899,742	)		(157,647,361	)		(159,798,695	)
Profit from operations		29,142,926			18,377,740			9,183,390			10,114,265			12,377,731
Interest income		160,723			147,063			198,906			234,604			264,554
Financial expenses, net		(7,970,070	)		(7,067,602	)		(9,604,645	)		(10,647,311	)		(10,973,140	)
Other investment income/(loss)		115,238			1,070,034			1,742,081			(278,669	)		228,026
Gain/(loss) on fair value changes of financial assets/liabilities		(16,742	)		(12,986	)		856,786			726,843			36,667
Share of profits less losses of associates and joint ventures		1,525,975			1,298,889			425,215			1,823,415			1,185,622
Profit before income tax expense		22,958,050			13,813,138			2,801,733			1,973,147			3,119,460
Income tax expense		(5,698,943	)		(3,465,151	)		(1,217,526	)		(643,173	)		(2,011,255	)
Net profit		17,259,107			10,347,987			1,584,207			1,329,974			1,108,205
Attributable to:
Equity holders of the Company		13,651,933			8,520,427			1,579,836			734,435			766,345
Non-controlling interests		3,607,174			1,827,560			4,371			595,539			341,860
Basic earnings per share		0.94			0.56			0.10			0.03			0.01
Diluted earnings per share		0.94			0.56			0.10			0.03			0.01

	As of December 31,
	2015		2016		2017		2018		2019
	RMB in thousands
Consolidated Financial Position Data
Current assets		33,565,403		36,966,616		48,537,710		61,799,069		60,781,401
Property, plant and equipment		219,673,070		223,061,809		284,328,093		282,061,272		285,622,907
Available-for-sale financial assets		5,077,863		3,406,032		1,604,993		—		—
Other equity instrument investments		—		—		—		2,083,419		779,218

	As of December 31,
	2015			2016			2017			2018			2019
	RMB in thousands
Investments in associates and joint ventures		19,745,192			19,632,113			19,517,623			19,553,964			20,783,259
Land use rights		8,313,766			8,456,347			11,264,785			11,450,034			-
Other non-current assets		6,070,312			6,067,937			9,635,850			21,085,769			18,605,005
Right-of-use assets		-			-			-			-			17,168,072
Power generation license		3,679,175			3,849,199			3,916,246			4,014,972			4,149,468
Deferred income tax assets		1,064,391			1,263,957			2,300,091			2,282,585			2,160,187
Goodwill		11,677,182			12,135,729			15,484,120			15,572,227			15,934,955
Total assets		308,866,354			314,839,739			396,589,511			419,903,311			428,250,063
Current liabilities		(123,836,633	)		(130,196,251	)		(155,950,488	)		(138,206,214	)		(141,620,410	)
Non-current liabilities		(83,336,032	)		(82,456,751	)		(133,024,419	)		(165,575,427	)		(156,250,607	)
Total liabilities		(207,172,665	)		(212,653,002	)		(288,974,907	)		(303,781,641	)		(297,871,017	)
Capital stock		(15,200,383	)		(15,200,383	)		(15,200,383	)		(15,698,093	)		(15,698,093	)
Net assets		(101,693,689	)		(102,186,737	)		(107,614,604	)		(116,121,670	)		(130,379,046	)

	Year Ended December 31,
	2015			2016			2017			2018			2019
	RMB in thousands, except per share data
Consolidated Cash Flow Data
Purchase of property, plant and equipment		(24,191,285	)		(20,144,903	)		(25,798,009	)		(20,613,314	)		(31,382,657	)
Net cash provided by operating activities		42,362,708			31,510,824			29,197,363			28,727,978			37,324,193
Net cash used in investing activities		(33,015,012	)		(17,649,646	)		(31,748,825	)		(20,375,882	)		(29,033,985	)
Net cash (used in)/generated from financing activities		(14,140,659	)		(13,601,850	)		4,013,180			(2,243,070	)		(11,328,183	)
Other Company Data
Dividend declared per share		0.47			0.29			0.10			0.10			0.135
Number of ordinary shares (‘000)		15,200,383			15,200,383			15,200,383			15,698,093			15,698,093

____________________________

(1) As a result of the adoption of IFRS 15, Revenue from contracts with customers, with effect from January 1, 2018, the Company and its subsidiaries have changed its accounting policies in respect of revenue recognition. In accordance with the transitional provisions of the standard, the changes in accounting policies were adopted by way of opening balance adjustments to equity as at January 1, 2018. The adoption of IFRS 15 did not have a material impact on the consolidated financial statements. Figures in years earlier than 2018 are stated in accordance with the policies applicable in those years.

(2) The Company and its subsidiaries adopted IFRS 9, Financial instruments, from January 1, 2018. As a result, the Company and its subsidiaries have changed its accounting policies in relation to financial instruments. As allowed by IFRS 9, the Company and its subsidiaries have not restated information relating to prior years. Differences in the carrying amounts of the financial assets resulting from the adoption of IFRS 9 were recognised in reserves at January 1, 2018. There was no difference in the carrying amounts of the financial liabilities. Prior to January 1, 2018, figures were stated in accordance with the policies applicable in those years.

(3) The Company and its subsidiaries adopted IFRS 16 using the modified retrospective method of adoption with the date of initial application of January 1, 2019. Under this method, a modified retrospective method is applied with the cumulative effect of initial adoption as an adjustment to the opening balance of retained earnings at January 1, 2019, and the comparative information was not restated.

B. Capitalization and indebtedness

Not applicable.

C. Reasons for the offer and use of proceeds

Not applicable.

D. Risk factors

Risks relating to our business and the PRC’s power industry

Government regulation of on-grid power tariffs and other aspects of the power industry may adversely affect our business

Similar to electric power companies in other countries, we are subject to governmental and electric grid regulations in virtually all aspects of our operations, including the amount and timing of electricity generations, the setting of on-grid tariffs, the performance of scheduled maintenance, and the compliance with power grid control and dispatch directives as well as environment protection regulations. There can be no assurance that these regulations will not change in the future in a manner which could adversely affect our business.

The on-grid tariffs for our planned output are subject to a review and approval process involving the National Development and Reform Commission (“NDRC”) and the relevant provincial government. Since April 2001, the PRC Government has been implementing an on-grid tariff-setting mechanism based on the operating terms of power plants as well as the average costs of comparable power plants. Pursuant to the NDRC circular issued in June 2004, the on-grid tariffs for our newly built power generating units commencing operation from June 2004 have been set on the basis of the average cost of comparable units adding tax and reasonable return in the regional grid. Any future reductions in our tariffs, or our inability to raise tariffs (for example, to cover any increased costs we may have to incur) as a result of the new on-grid tariff-setting mechanism, may adversely affect our revenue and profits.

In addition, the PRC Government started a program in 1999 to effect power sales through competitive bidding in some of the provinces where we operate our power plants. The on-grid tariffs for power sold through competitive bidding are generally lower than the pre-approved on-grid tariffs for planned output. In the more recent few years, power sales through competitive bidding only accounted for a portion of our overall power sales.

Nevertheless, the PRC Government is seeking to expand the program. Any increased power sales through competitive bidding may reduce our on-grid tariffs and may adversely affect our revenue and profits.

Furthermore, the PRC Government started in 2009 to promote the practice of direct power purchase by large power end-users. Pursuant to the circular jointly issued by NDRC, the State Electricity Regulatory Commission (“SERC”) and China National Energy Administration in June 2009, the direct transaction price shall include the direct transaction price, the grid transmitting price and the governmental fund and additional charges, of which the direct transaction price shall be freely determined through negotiation between the power generation company and the large power end-user. The price of direct power purchase shall be subject to the demand in the power market. Furthermore, the scale and mode of the transaction are also subject to the structure and level of development of local economy. In terms of power generation companies engaged in direct power purchase, direct power sales constitute a portion of the total power sales, thus affecting the on-grid power sales of the Company. For the past few years, the PRC Government continued the reform in the area of direct power purchase by large power end-users. In 2013, China National Energy Administration officially launched the direct power purchase program in seven provinces where we have power plants and the program has been steadily rolled out in other provinces. Although the direct power purchase may act as an alternative channel for our power sales, there is uncertainty as to the effect of the practice of direct power purchase over our operating results basing on the relatively lower tariffs generally for this portion.

The on-grid tariff-setting mechanism is evolving with the reforming of the PRC electric power industry. The PRC government announced a number of development and reform plans for the power market in 2016, covering areas including laws and regulations, comprehensive pilot plans, power transmission and distribution prices and supply side dynamics, the establishment of the power exchanges, rules and market administration committees, and opening up incremental distribution business. In 2017, the development and reform plans have been further expanded to the nationwide scale, with multiple issuances made by the PRC government governing power development plan, electricity transmission and distribution price, opening up of the electricity generation and consumption plans, supply side dynamics, electricity power stock and ancillary market development, electricity exchange rules, market supervision and clean energy consumption, etc. In 2018, the development and reform entered into an implementation stage, reflected in the areas of distribution price reform, establishment of the power  exchanges and ancillary market and the incremental distribution network reform, etc. In 2019, the development and reform entered into a “deep-water

zone” with long- and mid-term power exchange markets, power commodity exchange markets and ancillary service exchange markets established and relevant rules and policies adopted.

There is no assurance that government regulations on the industry will not change in a manner which could adversely affect our business and results of operations or the measures we take would effectively help us to adapt to the new changes and developments. See “Item 4 Information of the Company – B. Business Overview – Pricing Policy.”

If our power plants receive less dispatching than planned generation, the power plants will sell less electricity than planned

Our profitability depends, in part, upon each of our power plants generating electricity to meet or surpass the planned generation, which in turn will be subject to a local demand for electric power and dispatching to the grids by the dispatch centers of the local grid companies.

The dispatch of electric power generated by a power plant is controlled by the dispatch center of the applicable grid companies pursuant to a dispatch agreement with us and to governmental dispatch regulations. In each of the markets we operate, we compete against other power plants for power sales. No assurance can be given that the dispatch centers will dispatch the full amount of the planned generation of our power plants. A reduction by the dispatch center in the amount of electric power dispatched relative to a power plant’s planned generation could have an adverse effect on the profitability of our operations. We have not encountered such situation before.

In August 2007, the General Office of the State Council issued a notice, promoting the energy saving electricity dispatch policy, which provides dispatching priority to electricity generated from renewable resources over electricity generated from unrenewable resources. In 2013, the government made continuous effort to encourage energy-saving power distribution. In 2014, the NDRC issued Guidance on Strengthening and Improving the Operation of Power Management Regulation. In 2015, the NDRC and China National Energy Administration (“NEA”) jointly issued Guidelines on Improving Electric Power Operations and Deepening Clean Energy Generation confirming a system ensuring the full-priced purchasing of renewable energy, and requests furthering  the electric power differentiation system on coal-fired units. In 2016, the NDRC and China National Energy Administration issued Notice on Issuing the Measures for the Administration of the Guaranteed Buyout of Electricity Generated by Renewable Energy Resources, Directive on the Measures for the Administration of the Guaranteed Buyout of Electricity Generated by Solar, Wind Energy Resources and Provisionary, Measures for Priority Dispatch of Renewable Peaking Power Generation Units and Notice on Power Supply and Notice on the Measures on the Consumption of Renewable Energy in Tri-North Area. In 2017, NDRC and NEA issued Circular on Orderly Opening Up the Electricity Generation and Consumption Plans, Interim Measures for Guaranteeing the Safe Consumption of Nuclear Power, Pilot Rules on Inter-regional Spare Renewable Energy Electricity Power Stock Trading, Circular on the Establishment of Pilot Electricity Power Stock Exchange, Circular on Promoting Hydropower Consumption in Southwest China, and Solutions to Abandoning Hydro, Wind and Solar Energy, to promote the development of the power stock exchange and renewable power consumption. In 2018, NDRC and NEA issued the Circular on Promoting the Capability to Adjust the Power System and Plan for Consumption of Clean Energy (2018-2020) to further direct the development of the clean energy and push for the reform of the power market. The NEA also solicited for public opinions on the Circular on the Renewable Power Quota System, proposing a coordination between the power suppliers and users to take responsibilities under quota system. In 2019, NDRC and NEA issued the Notice on Regulating the Management of Priority Generation and Priority Purchase Plan to prioritize the purchase of the renewable energy power, the Notice on Establishing and Perfecting Renewable Energy Power Consumption Guarantee Mechanism to promote the consumption of the renewable energy power. NDRC also issued the Notice on Full Release of Power Generation and Utilization Plan for Operating Power Users to further open up the utilization plan of operating power users to promote the renewable energy power consumption.

We cannot assure that such implementation will not result in any decrease in the amount of the power dispatched by any of our power plants.

The power industry reform may affect our business

The PRC Government in 2002 announced and started to implement measures to further reform the power industry, with the ultimate goal of creating a more open and fair power market. As part of the reform, five power

generation companies, including Huaneng Group, were created or restructured to take over all the power generation assets originally belonging to the State Power Corporation of China. In addition, two grid companies were created to take over the power transmission and distribution assets originally belonging to the State Power Corporation of China. An independent power supervisory commission, the SERC, was created to regulate the power industry. There might be further reforms, and it is uncertain how these reform measures and any further reforms will be implemented and impact our business. In December 2012, the PRC Government issued a notice to further reform the coal pricing mechanism, which mandated (1) the termination of all key coal purchase contracts between power generation companies and coal suppliers, and the abolition of national guidance of the railway transportation capacity plan, and (2) the cancellation of the dual-track coal pricing system, effective from January 1, 2013. For a detailed discussion of the reform, see “Item 4 Information on the Company – B. Business overview – Pricing policy.” There can be no assurance that such coal pricing reform will not adversely affect our results of operation. In 2013, the PRC Government continued the reform in power industry. In July 2013, China National Energy Administration issued the Notice on Direct Purchases between Power End-users and Power Generation Companies, which officially implemented the direct purchases programs by large end-users.

On March 15, 2015, the Opinions of CPC Central Committee and State Council Regarding Further Deepening Reform of the Electricity System was released, according to which the reform will be focused and directed to orderly liberalize the tariff of the competitive markets other than electricity transmission and distribution, gradually allow investment from private investors in power distribution and selling businesses, consistently open the power generation market other than those for non-profit purpose or under regulation, push for independent and regulated operation of the parties involved in electricity transactions, continue the study of regional power grid construction and the transmission and distribution system suitable for China, further strengthen government regulations for enhanced power coordination and planning, and further improve safe and efficient operation of electricity and reliable power supply. These reforms will have a profound impact on the business models of power generation enterprises and may intensify the competition which may adversely affect our business. In November 2015, the NDRC and China Energy Administration issued six official documents regarding electricity system reform, namely Opinions on Deepening Electricity Price Reform, Opinions on Furthering Electricity Market Development, Opinions on Establishing and Institutionalizing Electricity Purchasing Organizations, Opinions on Orderly Opening Up Electricity Generation and Consumption, Opinions on Deepening Electricity Sales Reform and Guidelines on Fortifying and Institutionalizing the Management of Coal-fired Power Plants, further confirming the direction of the newest round of reforms of the electricity system.

In 2016, the PRC Government implemented various measures to further reform the power industry on many fronts, including (i) seeking public comments on the proposed amendment to the electric power law of the People’s Republic of China, (ii) implementing structural reform pilot programs in nineteen provinces; (iii) establishing national electricity exchanges in Beijing and Guangzhou, (iii) setting up independent third party credit rating system for market players, (iv) promulgating rules governing the price and method of direct power purchase/competitive bidding programs as well as the market entrance and exit mechanism, and (v) furthering reform on the pricing mechanism for power transmission and distribution prices.

In 2017, The PRC Government issued various measures to further reform the power industry, including: (i) establishing the national power development plan covering the consumption share of the non-fossil fuel, heating system reform based on “coal to gas,” “coal to electricity” and renewable energy development, and new technology programs; (ii) speeding up the reform of electricity transmission and distribution price; (iii) orderly opening up the electricity generation and consumption plans; (vi) establishing the union of power exchanges and speeding up the electricity stock and ancillary service market development; (v) enhancing the development of the electricity power supply side reform; (vi) issuing the rules for monthly inter-region electricity power trade in South China; and (vii) furthering the development of the power-related credit system.

In 2018, NDRC and NEA issued Circular on Promoting the Capability to Adjust the Power System and Plan for Consumption of Clean Energy (2018-2020), Circular on the Renewable Power Quota System and Notice on Actively Promoting Market-oriented Power Exchange and Further Improving the Trading Mechanism to further promote the consumption of renewable energy and increase the utilization rate of the renewable energy. From 2018, users from coal, steel, non-ferrous metal and construction materials industries, among others, shall participate in the market-oriented power exchange process instead of applying the catalog price. Users are encouraged to negotiate with power generating enterprises to establish the “baseline with floating adjustment” pricing mechanism.

In 2019, NDRC and NEA, jointly and individually, issued multiple circulars, measures and notices to further facilitate the development and reform of the power market, including, among others, Notice on Establishing and Perfecting Renewable Energy Power Consumption Guarantee Mechanism and Guiding Opinions on Deepening the Reform of the On-grid Tariff Formation Mechanism for Coal-fired Power. Such circulars, measures and notices provide that (i) a renewable energy power consumption guarantee mechanism shall be established in 2020, (ii) the operating power users shall be given more discretion in pricing when negotiating with power generation entities, (iii) multiple measure on on-grid tariff formation mechanism shall be adopted, and (iv) the establishment power commodity exchange markets shall be sped up.

These reform actions will have a profound impact on the operations of power generation companies and may intensify competition, which may negatively impact our company.

We are effectively controlled by Huaneng Group and HIPDC, whose interests may differ from those of our other shareholders

Huaneng Group, directly or indirectly holds 45.58% of our total outstanding shares, and HIPDC directly holds 32.28% of our total outstanding shares. As Huaneng Group is HIPDC’s parent company, they may exert effective control over us acting in concert. Their interests may sometimes conflict with those of our other minority shareholders. There is no assurance that Huaneng Group and HIPDC will always vote their shares, or direct the directors nominated by them to act in a way that will benefit our other minority shareholders.

Disruption in coal supply and its transportation as well as increase in coal price may adversely affect the normal operation of our power plants

A substantial majority of our power plants are fueled by coal. The coal supply for our power plants is arranged through free negotiation between power companies, coal suppliers, and railway authorities. Thus, any material disruption in coal supply and its transportation may adversely affect our operations. To date, we have not experienced shutdowns or reduced electricity generation caused by inadequate coal supply or transportation services.

In addition, our results of operations are sensitive to the fluctuation of coal price. During the few years before 2016, the Chinese coal market was showing a surplus in production, resulting in a significantly decreased coal price. However, the policies of reducing overcapacity of the Chinese coal producers implemented in early 2016 led to a supply shortage with surging coal prices in the Chinese coal market. There is no assurance that the increase in coal prices will not continue in the future, and if the price increase does continue, there is no assurance that we will be able to adjust our power tariff to pass on the increase in the coal price in time. Although the government has established a coal-electricity price linkage mechanism to allow power generation companies to increase their power tariffs to cope with the increase in the coal price, the implementation of the mechanism involves uncertainties. For a detailed discussion of the coal-electricity price linkage mechanism, see “Item 4 Information on the Company – B. Business overview – Pricing policy.”

Power plant development, acquisition and construction are a complex and time-consuming process, the delay of which may negatively affect the implementation of our growth strategy

We develop, construct, manage and operate large power plants. Our success depends upon our ability to secure all required PRC Government approvals, power sales and dispatch agreements, construction contracts, fuel supply and transportation and electricity transmission arrangements. Delay or failure to secure any of these could increase cost or delay or prevent commercial operation of the affected power plant. Although each of our power plants in operation and the power plants under construction received all required PRC Government approvals in a timely fashion, no assurances can be given that all the future projects will receive approvals in a timely fashion or at all. In addition, due to national policies and related regulations promoting environment-friendly energy, the approval requirements and procedures for power plant are becoming increasingly stringent, which may negatively affect the approval process of our new projects.

We have generally acted as, and intend to continue to act as, the general contractor for the construction of our power plants. As with any major infrastructure construction effort, the construction of a power plant involves many risks, including shortages of equipment, material and labor, labor disturbances, accidents, inclement weather, unforeseen engineering, environmental, geological, delays and other problems and unanticipated cost increases, any

of which could give rise to delays or cost overruns. Construction delays may result in loss of revenues. Failure to complete construction according to specifications may result in liabilities, decrease power plant efficiency, increase operating costs and reduce earnings. Although the construction of each of our power plants was completed on or ahead of schedule and within its budget, no assurance can be given that construction of future projects will be completed on schedule or within budget.

In addition, from time to time, we may acquire existing power plants from HIPDC, Huaneng Group or other parties. The timing and the likelihood of the consummation of any such acquisitions will depend, among other things, on our ability to obtain financing and relevant PRC Government approvals and to negotiate relevant agreements for terms acceptable to us.

Substantial capital is required for investing in or acquiring new power plants and failure to obtain capital on reasonable commercial terms will increase our finance cost and cause delay in our expansion plans

An important component of our growth strategy is to develop new power plants and acquire operating power plants and related development rights from HIPDC, Huaneng Group or other companies on commercially reasonable terms. Our ability to arrange financing and the cost of such financing depend on numerous factors, including general economic and capital market conditions, credit availability from banks or other lenders, investor confidence in us and the continued success of our power plants. Although we have not been materially affected by inflation in the past, there is no assurance that we would not be affected in the future. The Chinese government is expected to implement active fiscal policies and sound monetary policies. The fiscal policies would be focused on reducing taxes and other fiscal levies with the view to addressing, in collaboration with the implementation of monetary polies, funding difficulties and prohibitive funding prices encountered by business enterprises. The sound monetary policies would be implemented to underscore overall economic stability, strengthen counter-cyclical monetary administration, optimize credit structure, and maintain reasonably adequate liquidity. Accordingly, it is expected that the market would have reasonably sufficient funding in 2020 and funding costs are expected to be consistent with decline. The interest bearing debts of the Company are mostly denominated in Renminbi, changes in benchmark lending interest rate published by the PBOC will have a direct impact on the Company’s cost of debt. Regarding our debts denominated in other currencies, it is less likely that the U.S. and other major economies would further increase interest rates due to expected slowdown of the global economy. As the debts denominated in other currencies represent a small percentage in our total debts, the change of interest rates of foreign currencies are not expected to have material effect on the Company. Though the finance costs are expected to be consistent with slight decline, we may not be able to carry out our expansion plans due to the failure to obtain financing or increased financing costs. Furthermore, although we have historically been able to obtain financing on terms acceptable to us, there can be no assurance that financing for future power plant developments and acquisitions will be available on terms acceptable to us or, in the event of an equity offering, that such offering will not result in substantial dilution to existing shareholders.

Operation of power plants involves many risks and we may not have enough insurance to cover the economic losses if any of our power plants’ ordinary operation is interrupted

The operation of power plants involves many risks and hazards, including breakdown, failure or substandard performance of equipment, improper installation or operation of equipment, labor disturbances, natural disasters, environmental hazards and industrial accidents. The occurrence of material operational problems, including but not limited to the above events, may adversely affect the profitability of a power plant.

Our power plants in the PRC currently maintain insurance coverage that is typical in the electric power industry in the PRC and in amounts that we believe to be adequate. Such insurance, however, may not provide adequate coverage in certain circumstances. In particular, in accordance with industry practice in the PRC, our power plants in the PRC do not generally maintain business interruption insurance, or any third party liability insurance other than that included in construction all-risks insurance or erection all-risks insurance to cover claims in respect of bodily injury or property or environment damage arising from accidents on our property or relating to our operation. Although each of our power plants has a good record of safe operation, there is no assurance that the afore-mentioned accidents will not occur in the future.

If the PRC Government adopts new and stricter environmental laws and additional capital expenditure is required for complying with such laws, the operation of our power plants may be adversely affected and we may be required to make more investment in compliance with these environmental laws

Most of our power plants, being coal-fired power plants, discharge pollutants into the environment. We are subject to central and local government environmental protection laws and regulations. The Environmental Protection Tax Law of People’s Republic of China came into effect in 2018 and impose base-level environmental protection tax for various polluting substances. In addition, such environmental protection laws and regulations also set up the goal for the overall control on the discharge volume of key polluting substances. These laws and regulations impose fines for violations of laws, regulations or decrees and provide for the possible closure by the central government or local government of any power plant which fails to comply with orders requiring it to cease or cure certain activities causing environmental damage. Also, the PRC Government requires thermal power plants to equip all units with desulphurization and denitrification facilities, and sets higher anti-dust standards. The Chinese government is working on a pollution prevention and control campaign, which shall subject us to a more stringent standards for our air pollution control, waste water pollution control and ecological environmental protection efforts. Such stringent standards, together with the environmental protection tax, will result in the increases in the environmental protection expenditure and operating costs of power plants and may have an adverse impact on our operating results.

We attach great importance to the environmental related matters of our existing power plants and our power plants under construction. We have implemented a system that is designed to control pollution caused by our power plants, including the establishment of an environmental protection administration system at each power plant, adoption of relevant control and evaluation procedures and the installation and maintenance of certain pollution control equipment. We also upgraded the ultra-low emission facilities on our coal-fired units. Currently, we have completed the ultra-low emission upgrade on coal-fired units of 84.35 million kW and stabilized the emission of main smoke and dust pollutants to an ultra-low level. We have also initiated the environment protection upgrade projects, covering wastewater emission and ash field management, for our plants in key regions. We believe our environmental protection systems and facilities for the power plants are adequate for us to comply with applicable central government and local government environmental protection laws and regulations. However, the PRC Government may impose new, stricter laws and regulations on environmental protection, which may adversely affect our operations.

The PRC is a party to the Framework Convention on Climate Change (“Climate Change Convention”), which is intended to limit or capture emissions of “greenhouse” gases, such as carbon dioxide. Ceilings on such emissions could limit the production of electricity from fossil fuels, particularly coal, or increase the costs of such production. At present, ceilings on the emissions of “greenhouse” gases have not been assigned to developing countries under the Climate Change Convention. Therefore, the Climate Change Convention would not have a major effect on us in the short term because the PRC as a developing country is not obligated to reduce its emissions of “greenhouse” gases at present, and the PRC Government has not adopted relevant control standards and policies. If the PRC were to agree to such ceilings, or otherwise reduce its reliance on coal-fired power plants, our business prospects could be adversely affected. In addition, pilot carbon emission trading programs have been conducted in certain regions and are expected to be gradually implemented throughout China. This may also adversely affect our business and financial prospects in the future.

In addition, according to a report issued by the PRC Ministry of Ecology and Environment, China is taking multiple measures to address the climate change challenges, including adjusting industrial structure, improving energy efficiency, optimizing energy structure, strengthening ecosystem adaptability, and promoting carbon trading markets. Particularly, China plans to launch the nationwide carbon trading market in 2020. The adoption of such measures, especially the establishment of the carbon trading markets, may increase the operating costs and expenses of our power plans, and therefore have negative impact on our operations and financial results.

Our business benefits from certain PRC Government tax incentives. Expiration of, or changes to, the incentives could adversely affect our operating results

Prior to January 1, 2008, according to the relevant income tax law, domestic enterprises were, in general, subject to statutory income tax of 33% (30% enterprise income tax and 3% local income tax). If these enterprises are located in certain specified locations or cities, or are specifically approved by State Administration of Taxation, a lower tax rate would be applied. Effective from January 1, 1999, in accordance with the practice notes on the PRC income tax laws applicable to foreign invested enterprises investing in energy and transportation infrastructure

businesses, a reduced enterprise income tax rate of 15% (after the approval of State Administration of Taxation) was applicable across the country. We applied this rule to all of our wholly owned operating power plants after obtaining the approval of State Administration of Taxation. In addition, certain power plants were exempted from enterprise income tax for two years starting from the first profit-making year, after offsetting all tax losses carried forward from the previous years (at most of five years), followed by a 50% reduction of the applicable tax rate for the next three years. The statutory income tax was assessed individually based on each of their results of operations.

On March 16, 2007, the Enterprise Income Tax Law of PRC, or the New Enterprise Income Tax Law, was enacted, and became effective on January 1, 2008 and was amended on February 24, 2017. The New Enterprise Income Tax Law imposes a uniform income tax rate of 25% for domestic enterprises and foreign invested enterprises. Therefore, our power plants subject to a 33% income tax rate prior to January 1, 2008 are subject to a lower tax rate of 25% starting on January 1, 2008. With regard to our power plants entitled to a reduced enterprise income tax rate of 15% prior to January 1, 2008, their effective tax rate gradually increased to 25% within a five-year transition period commencing on January 1, 2008. Accordingly, the effective tax rate of our wholly owned power plants has increased over time. In addition, although our power plants entitled to tax exemption and reduction under the income tax laws and regulations that are effective prior to the New Enterprise Income Tax Law will continue to enjoy such preferential treatments until the expiration of the same, newly established power plants will not be able to benefit from such tax incentives, unless they can satisfy specific qualifications, if any, provided by then effective laws and regulations on preferential tax treatment.

The increase of applicable income tax rate and elimination of the preferential tax treatment with regard to certain of our power plants may adversely affect our financial condition and results of operations. Moreover, our historical operating results may not be indicative of our operating results for future periods as a result of the expiration of the tax benefits currently available to us.

In addition, according to the New Enterprise Income Tax Law and its implementation rules, any dividends derived from the distributable profits accumulated from January 1, 2008 and paid to the shareholders who are non-resident enterprises in the PRC will be subject to the PRC withholding tax at the rate of 10%. The withholding tax will be exempted if such dividends are derived from the distributable profits accumulated before January 1, 2008. Under a notice issued by the State Administration of Taxation of the PRC on November 6, 2008, we are required to withhold PRC income tax at the rate of 10% on annual dividends paid for 2008 and later years payable to our H Share investors who are non-resident enterprises.

Fluctuations in exchange rates could have an adverse effect on our results of operations and your investment

As a power producer operating mainly in China, we collect most of our revenues in Renminbi and have to convert Renminbi into foreign currencies to (i) repay some of our borrowings which are denominated in foreign currencies, (ii) purchase foreign made equipment and parts for repairs and maintenance, (iii) purchase fuel from overseas suppliers, and (iv) pay out dividend to our overseas shareholders.

The value of the Renminbi against the U.S. dollar and other currencies may fluctuate and is affected by, among other things, changes in China’s political and economic conditions. The conversion of Renminbi into foreign currencies, including U.S. dollars, is based on rates set by the PBOC. On July 21, 2005, the PRC government introduced a floating exchange rate system to allow the value of Renminbi to fluctuate within a regulated band based on market supply and demand and by reference to a basket of foreign currencies. Renminbi appreciated by more than 20% against the U.S. dollar between July 2005 and July 2008. Between July 2008 and June 2010, this appreciation halted and the exchange rate between the Renminbi and the U.S. dollar remained within a narrow band. On June 19, 2010, the PBOC decided to further promote the reform of the Renminbi exchange rate formation mechanism, and improve the flexibility of Renminbi exchange rate. The Company and its subsidiaries (both domestic and overseas) have debts denominated in foreign currencies, fluctuations in the exchange rates of Renminbi and Singapore dollar into foreign currencies create exchange risk for the Company. With the internationalization process and RMB joining the SDR, RMB exchange rate may continue to fluctuate in the future. In August 2015, the PBOC further improved its midpoint rate determination mechanism, which led to a 2% depreciation of Renminbi against the U.S. dollar. With effect from October 1, 2016, RMB is determined to be a freely usable currency and will be included in the SDR basket as a fifth currency. In the fourth quarter of 2016, the RMB has depreciated significantly in the backdrop of a surging U.S. dollar and persistent capital outflows of China.

In 2017, the RMB has appreciated significantly in the backdrop of a weak U.S. dollar, robust Chinese economy in 2017 and stringent foreign exchange regulation. In the first quarter of 2018, the RMB continued to appreciate. However, the RMB depreciated significantly in the remaining quarters of 2018. However, it is difficult to predict how market forces or PRC or U.S. government policy may impact the exchange rate between the Renminbi and the U.S. dollar in the future. There remains significant international pressure on the PRC Government to further liberalize its currency policy, which could result in further fluctuations in the value of the Renminbi against the U.S. dollar. However, there is no assurance that there will not be a devaluation of Renminbi in the future. If there is such devaluation, our debt servicing cost will increase and the return to our overseas investors may decrease.

Our revenues from SinoSing Power Pte. Ltd. (“SinoSing Power”) and its subsidiaries are collected in Singapore dollars. However, commencing from 2008, the operating results of SinoSing Power and its subsidiaries were consolidated into our financial statements, which use Renminbi as the presentation currency. The situation of our Pakistan operation is similar after we consolidate our business in Pakistan since December 2018. As a result, we are exposed to foreign exchange fluctuations between Renminbi and the Singapore dollar or Pakistan Rupee. Appreciation of Renminbi against the Singapore dollar or Pakistan Rupee may cause an adverse impact on our operation results and foreign translation difference.

The audit reports included in this annual report are prepared by auditors who are not inspected by the Public Company Accounting Oversight Board and, as such, you are deprived of the benefits of such inspection

Auditors of companies that are registered with the U.S. Securities and Exchange Commission and traded publicly in the United States, including our independent registered public accounting firms, must be registered with the U.S. Public Company Accounting Oversight Board (United States) (the “PCAOB”) and are required by the laws of the United States to undergo regular inspections by the PCAOB to assess their compliance with the laws of the United States and professional standards. Because we have substantial operations within the People’s Republic of China and the PCAOB is currently unable to conduct inspections of the work of our auditors as it relates to those operations without the approval of the Chinese authorities, our auditors’ work related to our operations in China is not currently inspected by the PCAOB. In May 2013, PCAOB announced that it had entered into a Memorandum of Understanding on Enforcement Cooperation with the China Securities Regulatory Commission (“CSRC”) and the PRC Ministry of Finance, which establishes a cooperative framework between the parties for the production and exchange of audit documents relevant to investigations undertaken by PCAOB, the CSRC or the PRC Ministry of Finance in the United States and the PRC, respectively. PCAOB continues to be in discussions with the CSRC and the PRC Ministry of Finance to permit joint inspections in the PRC of audit firms that are registered with PCAOB and audit Chinese companies that trade on U.S. exchanges. This lack of PCAOB inspections of audit work performed in China prevents the PCAOB from regularly evaluating audit work of any auditors that was performed in China including that performed by our auditors. As a result, investors may be deprived of the full benefits of PCAOB inspections. Investors may lose confidence in our reported financial information and procedures and the quality of our financial statements.

On December 7, 2018, the Securities and Exchange Commission, or the SEC, and the PCAOB issued a joint statement highlighting continued challenges faced by the U.S. regulators in their oversight of financial statement audits of U.S.-listed companies with significant operations in China. The joint statement reflects a heightened interest in an issue that has vexed U.S. regulators in recent years. Furthermore, in light of the ongoing trade discussions between the U.S. and China, the Trump administration and National Economic Council reportedly have considered a number of aggressive measures affecting U.S. and Chinese investments, which, among others, may involve more stringent supervision over auditors of China-based U.S. listed companies. In June 2019, a bipartisan group of lawmakers introduced bills in both houses of the U.S. Congress that would require the SEC to maintain a list of issuers for which the PCAOB is not able to inspect the working papers of an audit report issued by a foreign public accounting firm, even if it is affiliated with a “Big Four” accounting firm. Enactment of this proposed legislation or other efforts to increase U.S. regulatory access to audit information could cause investor uncertainty for affected issuers and cause trading volatility.

Our independent registered public accounting firm may be temporarily suspended from practicing before the SEC. If a delay in completion of our audit process occurs as a result, we could be unable to timely file certain reports with the SEC, which may lead to the delisting of our stock

On January 22, 2014, Judge Cameron Elliot, an SEC administrative law judge, issued an initial decision suspending the Chinese member firms of the “Big Four” accounting firms, including our independent registered public accounting firm, from, among other things, practicing before the SEC for six months. In February 2014, the initial decision was appealed. While under appeal and in February 2015, the Chinese member firms of “Big Four” accounting firms reached a settlement with the SEC. As part of the settlement, each of the Chinese member firms of “Big Four” accounting firms agreed to settlement terms that include a censure; undertakings to make a payment to the SEC; procedures and undertakings as to future requests for documents by the US SEC; and possible additional proceedings and remedies should those undertakings not be adhered to. Under the terms of the settlement, the underlying proceeding against the four PRC-based accounting firms was deemed dismissed with prejudice at the end of four years starting from the settlement date, which was February 6, 2019. We cannot predict if the SEC will further challenge the four PRC-based accounting firms’ compliance with U.S. law in connection with U.S. regulatory requests for audit work papers or if the results of such a challenge would result in the SEC imposing penalties such as suspensions. If additional challenges are imposed on the Chinese affiliates of the “Big Four” accounting firms, our ability to timely file future financial statements in compliance with the requirements of the Exchange Act may be adversely affected.

In the event that the SEC restarts the administrative proceedings, depending upon the final outcome, listed companies in the United States with major PRC operations may find it difficult or impossible to retain auditors in respect of their operations in the PRC, which could result in financial statements being determined to not be in compliance with the requirements of the Exchange Act, including possible delisting. Moreover, any negative news about any such future proceedings against these audit firms may cause investor uncertainty regarding China-based, U.S.-listed companies and the market price of our ADSs may be adversely affected.

If our independent registered public accounting firm was denied, even temporarily, the ability to practice before the SEC and we were unable to timely find another registered public accounting firm to audit and issue an opinion on our financial statements, our financial statements could be determined not to be in compliance with the requirements of the Exchange Act. A delinquency in our filings with the SEC may result in NYSE initiating delisting procedures, which could adversely harm our reputation and have other material adverse effects on our overall growth and prospect.

Forward-looking information may prove inaccurate

This document contains certain forward-looking statements and information relating to us that are based on the beliefs of our management as well as assumptions made by and information currently available to our management. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “going forward” and similar expressions, as they relate to us or our management, are intended to identify forward-looking statement. Such statements reflect the current views of our management with respect to future events and are subject to certain risks, uncertainties and assumptions, including the risk factors described in this document. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described herein as anticipated, believed, estimated or expected. We do not intend to update these forward-looking statements.

There can be no assurance that we will not be passive foreign investment company, or PFIC, for United States federal income tax purposes for any taxable year, which could subject United States investors in the ADSs or our H Shares to significant adverse United States income tax consequences

We will be a “passive foreign investment company,” or “PFIC,” if, in the case of any particular taxable year, either (a) 75% or more of our gross income for such year consists of certain types of “passive” income or (b) 50% or more of the value of our assets (generally determined on the basis of a quarterly average) during such year produce or are held for the production of passive income (the “asset test”). For United States federal income tax purposes, and based upon our income and assets, we do not believe that we were classified as a PFIC for the taxable year ended December 31, 2019, and do not anticipate becoming one in the foreseeable future.

While we do not expect to become a PFIC, because the value of our assets for purposes of the asset test may be determined by reference to the market price of the ADSs, fluctuations in the market price of the ADSs may cause us to become a PFIC for the current or subsequent taxable years. The determination of whether we will be or become a PFIC will also depend, in part, on the composition of our income and assets. Under circumstances where we determine not to deploy significant amounts of cash for active purposes, our risk of being a PFIC may substantially increase. Because there are uncertainties in the application of the relevant rules and PFIC status is a factual determination made annually after the close of each taxable year, there can be no assurance that we will not be a PFIC for the current taxable year or any future taxable year.

If we are a PFIC in any taxable year, a U.S. Holder (as defined in “Item 10. Additional Information—E. Taxation—United States federal income tax considerations”) may incur significantly increased United States income tax on gain recognized on the sale or other disposition of the ADSs or H Shares and on the receipt of distributions on the ADSs or H Shares to the extent such gain or distribution is treated as an “excess distribution” under the United States federal income tax rules and such holders may be subject to burdensome reporting requirements. Further, if we are a PFIC for any year during which a U.S. Holder holds the ADSs or our H Shares, we generally will continue to be treated as a PFIC for all succeeding years during which such U.S. Holder holds the ADSs or our H Shares. For more information see “Item 10. Additional Information—E. Taxation—United States federal income tax considerations—Passive Foreign Investment Company Considerations.”

The recent coronavirus pandemic outbreak could materially and adversely affect our business.

In the beginning of 2020, a novel strain of coronavirus (COVID-19) was reported to have surfaced in China and caused a pandemic outbreak. The outbreak of the coronavirus and other adverse public health developments have certain adverse impact for a period of time on the electricity growth nationwide, coal production and transportation and our normal operating activities, including disruptions from the temporary closure of offices, suspension of business travel or other disruptions on our normal working schedules, restrictions on our employees’ ability to travel, and other similar disruptions on our normal operation arrangements, which, in aggregate, may have material impacts on our business, financial condition and results of operations. We have taken measures in response to the outbreak, including the adoption of more stringent workplace sanitation measures, which may have negative impact on our results of operations and financial status. While such measures are expected to be temporary, the duration of the business disruption and related financial impact cannot be reasonably estimated at this time. The extent to which this outbreak impacts our results will depend on future developments, which are highly uncertain and cannot be predicted at this time, including new information which may emerge concerning the severity of this outbreak and the actions to contain this outbreak or treat its impact, among others. We will keep continuous attention on the change of situation and make timely response and adjustments in the future.

Risks relating to doing business in the PRC

China’s economic, political and social conditions as well as government policies could significantly affect our business

As of December 31, 2019, the majority of our business, assets and operations are located in China. The economy of China differs from the economies of most developed countries in many respects, including government involvement, control of foreign exchange, and allocation of resources.

The economy of China has been transitioning from a planned economy to a more market-oriented economy. After multiple years of strenuous and sustained economic restructuring reforms, China has become a leading player in the global economy and a major contributing force to the economic revival and growth worldwide. The PRC Government has implemented economic reform measures emphasizing utilization of market forces in the development of the economy of China and a higher level of autonomy for the private sector. Some of these measures will benefit the overall economy of China, but may have a negative effect on us for a short term. For example, our operating results and financial condition may be adversely affected by changes in power tariff for our power plants, cost of fuels, increasingly stringent environment protection policies, and changes in State policies affecting the power industry. Furthermore, due to the complicated international macro-political and economic situations, China’s economic growth is slowing down in recent years, which may lead to tougher competition environment and certain economic adjustment measures. If we cannot adjust our operating strategies accordingly, our business, financial status and operating results may be negatively and materially impacted.

In addition, the economy of China may be impacted by other factors beyond control of PRC Government.  There have also been concerns about the relationship between China and other countries, including the surrounding Asian countries, which may potentially have economic effects. In particular, there is significant uncertainty about the future relationship between the United States and China with respect to trade policies, treaties, government regulations and tariffs. Economic conditions in China are sensitive to global economic conditions, as well as changes in domestic economic and political policies and the expected or perceived overall economic growth rate in China. Any severe or prolonged slowdown in the global or Chinese economy may materially and adversely affect our business, results of operations and financial condition.

Interpretation of PRC laws and regulations involves significant uncertainties

The PRC legal system is based on written statutes and their interpretation by the Supreme People’s Court. Prior court decisions may be cited for reference but are not considered as binding precedents.

We are subject to certain PRC regulations governing PRC companies that are listed overseas. These regulations contain certain provisions that are required to be included in the articles of association of these PRC companies and are intended to regulate the internal affairs of these companies. As the PRC regulations are constantly evolving with the goal of better protecting shareholder’s interests, we may face greater uncertainties in the interpretation of PRC laws and regulations. Furthermore, the PRC regulations for protection of shareholder’s rights are different from those applicable in the United States and/or exchanges where we are listed. Therefore we made it our policy to adopt the strictest standards of any listing rules potentially applicable to us. Some of these standards are incorporated in our articles of association and bylaws with the view to providing most protection for the interests of our shareholders.

Risks relating to our operations in Singapore

Our operations in Singapore are subject to a number of risks, including, among others, risks relating to electricity pricing, dispatching, fuel supply, project development, capital expenditure, environmental regulations, government policies, and Singapore’s economic, political and social conditions. Any of these risks could materially and adversely affect our business, prospects, financial condition and results of operations.

Fluctuation in demand and intensified competition may adversely affect Tuas Power’s business and results of operations.

Our operations in Singapore depend on market demand and are subject to competition. Overall power system demand grew by 2.45% in 2019 over 2018. The future growth is highly dependent on a sustained recovery in the Singapore and global economies. The liberalization of Singapore’s power market and the further deregulation of its power industry have resulted in more intense competition among the power generation companies in Singapore. Tuas Power Group, or Tuas Power, one of our wholly owned business units, is one of the three largest power generation companies in Singapore. If Tuas Power is unable to compete successfully against other power generation companies in Singapore, its business, prospects, financial condition and results of operations may be adversely affected.

An electricity futures market was also established in 2015 through an incentive scheme by the authority to market makers (MM) in the futures market. This has attracted independent retailers which are expected to exert some price competition in the retail market. A Demand Response (DR) scheme has been established which could potentially introduce further price competition in the wholesale generation market in Singapore. Furthermore, the Singapore government recently announced plans to raise the adoption of solar energy to 350 MWp by 2020 and  at least 2,000 MWp by 2030, compared to around 300 MWp in third quarter 2019.

TP Utilities Pte Ltd (“TPU”), an entity in Tuas Power Group, sells utilities, such as steam, industrial water and demineralized water to industrial customers for their direct consumption. The time of potential customers of TPU to site their premises, if at all, is subject to microeconomic situations. The demand of the utilities by these customers may vary as well. Despite Tuas Power’s efforts to develop its facilities in stages and/or in modules to provide sufficient capacity matching the demand, and require customers to pay minimum capacity payment charges to mitigate the demand risk, its business and results of operations may be adversely affected by fluctuation in demand.

Regulatory changes of the vesting regime in Singapore could expose Tuas Power to electricity price volatility and adversely affect its business and results of operations

Tuas Power derives its revenue mainly from sale of electricity to the National Electricity Market of Singapore (the “NEMS”) through a bidding process and vesting contracts under which a significant portion of power sales is predetermined by the Energy Market Authority (“EMA”). The vesting contract regime in Singapore is targeted at mitigation of market power in the wholesale electricity spot market. The regime achieves this objective by assigning a quantity of vesting contracts to generation companies, thereby limiting their incentives to exercise whatever level of market power they may possess. Vesting contracts are a form of bilateral contract imposed/vested on the major power generation companies in Singapore. Vesting contract price is set by the EMA, which is Singapore’s power market regulator. Vesting contract price is set at the long run marginal cost of the most efficient base-loaded technology plant employed in Singapore and is reviewed every two years. On a quarterly basis, the EMA allows for vesting contract quantity to be adjusted to account for changes in demand (due to seasonality) and the vesting contract price to be adjusted to account for inflation and changes in fuel prices. Such a mechanism helps protect the profit margins of the power generation companies in the Singapore market, such as Tuas Power, to a large degree. The quantity of vesting contract allocated to the power generation company depends on the proportion of such power generation company’s capacity to the total licensed or planned generation capacity at the commencement of the vesting contracts regime. A portion of the volume under the Vesting Contract Scheme has also been allocated to the LNG Vesting Scheme - an incentive scheme where players who have committed to an initial tranche of LNG for Singapore are allocated electricity sale contracts. The volume allocated to the generation companies under the LNG vesting scheme is fixed for a period of 10 years until 2023. Following EMA’s review of the Vesting Contract Regime in 2016, it is determined that the vesting contract level shall be maintained at 25% until the end of the first half of 2018 and it shall be reduced to LNG vesting level by the second half of 2019. The vesting contract regime will be phased out by 2023 when the LNG vesting contract expires, which could lead to volatility in electricity prices and adversely affect our business, financial condition and results of operation.

In July 2018, EMA issued a determination paper to allow vesting contract holders with steam turbine generation plants, i.e., Tuas Power, Senoko Energy and YTL PowerSeraya, to retain their allocated vesting quantities irrespective of whether the steam turbine generation plants are retired. This will facilitate the three generation companies in making commercial decisions on whether and when to retire their steam turbine generation plants so as to reduce overhead costs and free up resources.

Since June 2019, EMA has been embarking on an industry consultation process on the implementation of a Forward Capacity Market (“FCM”). EMA indicates that it is planning to develop and implement a FCM, which shall function together with the current real-time wholesale spot energy market with ancillary services, to meet the objectives of (i) maintaining resource adequacy by providing adequate incentives to the existing and new generation capacity, and (ii) maximizing economic efficiency to minimise long-run costs to consumers. The targeted time of implementation is in the first quarter of 2021.

The fuel cost of Tuas Power is exposed to volatility of international fuel price and foreign currency risk

The fuel for Tuas Power consists of natural gas, coal, biomass, fuel oil and diesel oil. Since the procurement price of natural gas is closely linked to oil price and the procurement price of coal and biomass is linked to a coal index, the fuel cost of Tuas Power is exposed to the volatility of international oil and coal prices. The prices of oil changed in a very volatile manner during the last quarter of 2019. In anticipation of the IMO 2020, the high sulfur fuel oil price is generally on the downward trend. The price of coal was moving downward gradually over the months in 2019 which helped to reduce the total coal purchase for the TMUC plant. In addition, the commitments for the purchase of fuel are denominated in U.S. dollars, which further exposes Tuas Power to foreign currency risk. Any increase in fuel price and/or appreciation of the U.S. dollar against the Singapore dollar will translate into an increase in fuel cost for Tuas Power. Part of this increase can be passed through electricity sale contracts and utilities sale contracts, while fuel and foreign exchange hedging strategies done appropriately will mitigate the impact of such increase. No assurance can be given that such increase will not adversely affect results of its operation. Tuas Power is highly dependent upon the import of gas via pipelines from Indonesia. Any disruption of such supply would impact the normal operation of Tuas Power significantly. This risk has been mitigated through Tuas Power’s contract to buy LNG for its incremental needs, although there is no assurance that, in the event of fuel supply shortfall, Tuas Power’s operations will not be adversely affected.

Risks relating to our operations in Pakistan

Our operations in Pakistan are subject to a number of risks, including, among others, risks relating to enforcement of the existing agreements and governmental policies on tariff pricing and power dispatching. Any of these risks could materially and adversely affect the business, prospects, financial condition and results of operations of our Sahiwal Power Plant.

Any change to, or breach of, the current agreement with the NEPRA may have adverse impact on Sahiwal Power Plant’s business and result of operations.

Pursuant to the agreement entered into between Sahiwal Power Plant and the National Electric Power Regulatory Authority (the “NEPRA”) of Pakistan, power generated by Sahiwal Power Plant shall be sold to Central Power Purchasing Agency (the “CPPA”) of Pakistan at the upfront tariff rate pre-established according to the relevant pricing Decision of the Authority issued by the NEPRA and the abovementioned agreement between Sahiwal Power Plant and NEPRA. The upfront tariff, consisting of energy purchase price and capacity purchase price, to a large extent reflects the investment made, and costs incurred, by us for the construction and operation of Sahiwal Power Plant, and subject us to relatively low operating risks relating to Sahiwal Power Plant.

However, we cannot assure you that the NEPRA or the CPPA will not change such agreement in the future, or that the terms and conditions of such agreement will be duly followed or enforced. If current agreement with the NEPRA is changed or breached, the operation, financial status and financial and operating results of Sahiwa Power Plant may be materially and adversely impacted.

Any change to the current governmental policy on tariff pricing and power dispatching may have adverse impact on Sahiwal Power Plant’s business and results of operations.

By a Decision of the Authority released in January 2019, the NEPRA provided to Sahiwal Power Plant with the approved tariff structure and the pricing details as well as dispatch criteria, which were based on the current upfront tariff structure, pricing methods and power purchase regime as provided by the relevant governmental rules and policies. If any of such rules and policies is changed, the NEPRA or the CPPA may be forced to change, or even terminate, the current tariff pricing and dispatching regime applicable to our Sahiwal Power Plant, which may have material and adverse impact on its operation and financial performance.

ITEM 4  INFORMATION ON THE COMPANY

A. History and development of the Company

Our legal and commercial name is Huaneng Power International, Inc. Our head office is at Huaneng Building, 6 Fuxingmennei Street, Xicheng District, Beijing, People’s Republic of China and our telephone number is (8610) 63226999. We were established in June 1994 as a company limited by shares organized under the laws of the People’s Republic of China.

The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding us that filed electronically with the SEC, which can be accessed at http://www.sec.gov. Information about the Company and documents the Company submitted to the SEC are available on our website: http://www.hpi.com.cn/sites/english/Pages/default.aspx.

We completed our initial global public offering of 1,250,000,000 overseas listed foreign shares in October 1994, which were listed on the New York Stock Exchange (Stock Code: HNP) in the United States by issuing 31,250,000 ADSs. In January 1998, the foreign shares of the Company were listed on The Stock Exchange of Hong Kong Limited by way of introduction (Stock Code: 902). Subsequently, in March 1998, the Company successfully completed a global placing of 250,000,000 foreign shares along with a private placing of 400,000,000 domestic shares. In November 2001, the Company successfully completed the issuance of 350,000,000 A Shares (Stock Code: 600011) in the PRC, of which 250,000,000 domestic public shares were listed on the Shanghai Stock Exchange. In December 2010, the Company completed the non-public issuance of 1,500,000,000 A Shares and 500,000,000 H Shares. In November 2014, the Company completed the non-public issuance of 365,000,000 H Shares. In November 2015, the Company completed the non-public issuance of 780,000,000 H Shares. In October 2018, the Company completed the

non-public issuance of 497,709,919 A Shares. Currently, the total share capital of the Company amounts to approximately 15.7 billion shares.

As resolved at the second meeting of the 8th session of the board of the Company on October 13, 2014 and adopted at the third extraordinary general meeting of the Company, we entered into the Huaneng Group Interests Transfer Agreement with Huaneng Group, and the HIPDC Interests Transfer Agreement and the Chaohu Power Interests Transfer Agreement with HIPDC. Pursuant to these transfer agreements, we acquired from Huaneng Group 91.8% interests of Hainan Power, 75% interests of Yangluo Power, 53.45% interests of Suzhou Thermal Power, 97% interests of Dalongtan Hydropower and 100% interests of Hualiangting Hydropower at a total price of RMB7.338 billion, and acquire from HIPDC 60% interests of Chaohu Power, 100% interests of Ruijin Power, 100% interests of Anyuan Power, 100% interests of Jingmen Thermal Power and 100% interest of Yingcheng Thermal Power Interests at a total price of RMB1.938 billion. The total consideration is RMB9.647 billion after adjustment of the profits generated from the date of valuation to the acquisition date in accordance with the equity transfer agreements. The transaction was completed in January 2015.

On October 14, 2016, the Company signed the Agreement for the Transfer of Equity Interests in Certain Companies with Huaneng Group (the “Transfer Agreement”). Pursuant to the Transfer Agreement, the Company shall accept the transfer of (i) 80% equity interest of Huaneng Shandong Power Limited; (ii) 100% equity interest of Huaneng Jilin Power Limited; (iii) 100% equity interest of Huaneng Heilongjiang Power Limited; and (iv) 90% equity interest of Huaneng Henan Zhongyuan Gas Power Generation Co., Ltd. from Huaneng Group for the consideration of RMB15,501 million after certain adjustment of the profits generated from the date of valuation to the acquisition date in accordance with the equity transfer agreements. This transaction was considered and approved at the 21st meeting of the Eighth Session of the Board held on October 14, 2016, and was considered and approved at the 2016 Second Extraordinary General Meeting held on November 30, 2016. The acquisition was completed on January 1, 2017, and the total consideration has been settled in cash by December 31, 2017 after netting off with the receivables due from Huaneng Group.

On July 31, 2018, Shandong Power (a subsidiary of the Company) and Taishan Power entered into the Transfer Agreement, pursuant to which Shandong Power shall acquire from Taishan Power (i) 75% interests in the registered capital of Shandong Huaneng Liaocheng Thermal Power Company Limited (“Liaocheng Thermal Power”), (ii) 80% interests in the registered capital of Shandong Huaneng Laizhou Wind Power Generation Company Limited (“Laizhou Wind Power”), (iii) 80% interests in the registered capital of Shandong Huaneng Laiwu Thermal Power Company Limited (“Laiwu Thermal Power”), and (iv) 15% interests in the registered capital of Huaneng Laiwu Power Generation Limited (“Laiwu Power Generation”) at the consideration of RMB1,800,020,000. Upon completion of the Transfer, Liaocheng Thermal Power, Laizhou Wind Power and Laiwu Thermal Power became subsidiaries of Shandong Power.

On July 31, 2018, Huaneng Shandong Power Generation Co., Ltd. (“Shandong Power Generation”) and Huaneng Taishan Electric Power Co., Ltd. (“HTEP”), both of which were holding subsidiaries of the Company, entered into the Transfer Agreement on Certain Company Interests Between Huaneng Taishan Electric Power Co., Ltd. and Huaneng Shandong Power Generation Co., Ltd. In December 2018, as certain wind turbines of Laizhou Wind Power were demolished at the request of the local government, according to the provisions of the above agreement, Shandong Power Generation had transferred back 80% of the interests in Laizhou Wind Power to Huaneng Energy and Transportation Industrial Holdings Ltd., the designated third party of Taishan Power, in December 2019.

See “Item 5 Operating and Financial Reviews and Prospects – Liquidity and Cash Resources” for a description of our principal capital expenditures since the beginning of the last three financial years.

B. Business overview

We are one of the China’s largest independent power producers and we have been striving for innovations in technologies, structure, and management since its incorporation. We were the first to introduce a 600 MW supercritical generating unit into China and we also started operating the first domestically built single 1,000 MW ultra-supercritical coal-fired generating unit, and the first digitalized 1,000 MW ultra-supercritical coal-fired generating unit in China. We completed the construction of the first 1,000 MW generating unit in the world using sea water desulphurization facilities and the 660 MW high-efficiency ultra-supercritical coal-fired generating unit with the highest parameter in China. We completed the construction of the first double reheat ultra-supercritical coal-fired generating unit, and developed the technology for synergistic treatment of fuel gas of coal-fired power plants, which was successfully applied in various environmental protection renovation and newly-constructed projects. We completed the offshore wind power project with the largest generating capacity in Asia and was the first to realize mass production of the wind turbine of 5 MW in China. We also invested and operated the most advanced gas turbine with the largest generation capacity and heat supplying capacity in China. The technical and economic indicators as well as the overall manpower efficiency of the Company have been remaining at the forefront in China’s power industry.

As of December 31, 2019, we had controlling generating capacity of 106,924 MW, and total generating capacity of 93,676 MW on equity-ownership basis.

Operations in China

We are engaged in developing, constructing, operating and managing large scale coal-fired and gas turbine power plants, new energy power projects and related facilities, including ports, marine transportation and power distribution. Our domestic power plants are located in 26 provinces, autonomous regions and provincial-level municipalities. In 2019, the Company proactively adapted to the changes in the market and anticipated the dynamics of the reforms in national economy and power market system to promptly realign our operating strategy. Throughout the year, we maintained stable operation of safe and clean production, achieved notable results in improving quality and efficiency, made headway in optimizing the structure, and strengthened our corporate governance. As a result, we have satisfactorily achieved our annual business objectives and maintained our leading position in the industry.

In 2019, new generating units with a total installed capacity of 1,286 MW were put into operation. In 2019, our total domestic power generation from all operating power plants on a consolidated basis amounted to 405.006 billion kWh, representing an decrease of 5.91% from 2018. The annual average utilization hours of our domestic generating units reached 3,915 hours. Our fuel cost per unit of power sold by domestic power plants decreased by 5.77% from the previous year to RMB 223.22 per MWh.

We believe our significant capability in the development and construction of power projects, as exemplified in the completion of our projects under construction ahead of schedule, and our experience gained in the successful acquisitions of power assets in recent years will enable us to take full advantage of the opportunities presented in China’s power market.

With respect to the acquisition or development of any project, we will consider, among other factors, changes in power market conditions, and adhere to prudent commercial principles in the evaluation of the feasibility of the project. In addition to business development strategies, we will continue to enhance our profitability by further strengthening our cost control, especially in respect of fuel costs and construction costs, so as to hedge against fluctuations in fuel price and increase competitiveness in the power market.

Operations in Singapore

Tuas Power, one of our wholly owned business units, operates in Singapore and is engaged in the business of generation, wholesale and retail of power and other relating utilities. Tuas Power is comprised of Tuas Power Ltd (“TPL”), the investment holding company, and seven subsidiaries. Among these subsidiaries, Tuas Power Generation Pte. Ltd. (“TPG”) is the electricity generation company that owns 100% of Tuas Power Supply Pte Ltd (“TPS”), which is the retail arm of TPG. Separately, TPU, a wholly owned subsidiary of TPL is engaged in the business of production and supply of utilities to industrial customers at Tembusu, Jurong Island in Singapore, as well as the generation of electricity dispatched to the electricity wholesale market. We have consolidated Tuas Power’s results of operations since March 2008. The total assets and revenue of Singapore operations represented approximately 6.75% and 7.66%, respectively, of our consolidated total assets and revenue as of and for the year ended December 31, 2019. In 2019, the power generated by Tuas Power in Singapore accounted for 20.7% of the total power generated in Singapore, slightly lower than 2018.

Operations in Pakistan

We engaged in the business of generation, wholesale and retail of power and other relating utilities through our subsidiaries, Huaneng Shandong Ruyi (Pakistan) Energy (Private) Co., Ltd. (“Ruyi Pakistan Energy”) and Shandong Huatai Electric Power Operation & Maintenance (Private) Co., Ltd. (“Huatai Power”) and their subsidiaries. We have consolidated results of operations of Ruyi Pakistan Energy and Huatai Power since December 31, 2018. The total assets and revenue of Pakistan operations represented approximately 3.36% and 2.76%, respectively, of our consolidated total assets and revenue as of and for the year ended December 31, 2019.

Development of power plants

The process of identifying potential sites for power plants, obtaining government approvals, completing construction and commencing commercial operations is usually lengthy. However, because of our significant experience in developing and constructing power plants, we have been able to identify promising power plant projects in China and to obtain all required PRC Government approvals in a timely manner.

Opportunity identification and feasibility study

We initially identify an area in which additional electric power is needed by determining its existing installed capacity and projected demand for electric power. The initial assessment of a proposed power plant involves a preliminary feasibility study. The feasibility study examines the proposed power plant’s land use requirements, access to a power grid, fuel supply arrangements, availability of water, local requirements for permits and licenses and the ability of potential customers to afford the proposed power tariff. To determine projected demand, factors such as economic growth, population growth and industrial expansion are used. To gauge the expected supply of electricity, the capacities of existing plants and plants under construction or development are studied.

Approval process

Prior to July 2004, any project proposal and supporting documents for new power plants had to first be submitted to the NDRC for approval and then be submitted to the State Council. In July 2004, the State Council of the PRC reformed the fixed asset investment regulatory system in China. Under the new system, new projects in the electric power industry that do not use government funds will no longer be subject to the examination and approval procedure. Instead, they will only be subject to a confirmation and registration process. Coal-fired projects will be subject to confirmation by the NDRC. Wind power projects with installed capacity of 50 MW or above shall be subject to confirmation and registration with the relevant department of the central government, while wind power projects with an installed capacity lower than 50 MW shall be subject to confirmation and registration with relevant local government departments. Wind power projects confirmed by local government departments at provincial level shall also be filed with the NDRC and China National Energy Administration.

In November 2014, pursuant to the Catalogue of Investment Projects Approved by the Government (2014 Version) issued by the State Council, administrative approval power for certain activities in the energy sector has been delegated to a lower level. The administrative approval power for thermal power stations has been delegated to the provincial level (with coal-fired thermal power station projects being subject to national-level administrative approval based on state-promulgated constructions plans limited by total volume), the administrative approval power for heat power stations has been delegated to the local level (with condensing steam heat power station projects being subject to provincial-level administrative approval based on state-promulgated constructions plans limited by total volume), and the administrative approval power for wind power plants delegated to the local level subject to state-promulgated constructions plans limited by total volume as well as the scope as set out in the annual developmental guides. The Interim Measures for Supervision and Administration of Photovoltaic Power Station Projects issued by China National Energy Administration in 2013 requires that photovoltaic power station projects be regulated by on a filing-based system by the provincial-level energy supervisory departments in accordance with regulations related to investment projects issued by the State Council. The same administrative approval standard was again re-affirmed in December 2016 pursuant to the Catalogue of Investment Projects Approved by the Government (2016 Version) issued by the State Council.

Joint venture power projects are subject to additional governmental approvals. Approval by Ministry of Commerce is also required when foreign investment is involved.

From 2014, China National Energy Administration has placed the stringent control on coal-fired projects within the Beijing-Tianjin-Hebei region, the Yangtze River Delta Region and the Pearl River Delta Region. All new coal-fired generating projects, other than those involving co-generation, were prohibited from being approved. Multi coal-fired generating units may be reconstructed into large capacity units based on the principles of an equivalent replacement for coal but the reduction in replacement pollutant emission.

From 2016, to counter the issue of overcapacity in the coal-fired power sector, China National Energy Administration strengthened the approval of coal-fired projects nationwide, a number of new coal-fired generating

projects, other than those involving co-generation, were canceled, postponed or terminated. Considering the increasingly limited availability of prime locations and decreasing subsidies, China National Energy Administration also suspended approval of new wind power plants and photovoltaic power station projects in provinces with wind curtailment rate over 20% and solar curtailment rate over 5%. It is expected that the overcapacity countering policy will be continued in the future.

Permits and contracts

In developing a new power plant, we, like other players in the industry, are required to obtain permits before commencement of the project. Such permits include operating licenses and similar approvals related to plant site, land use, construction, and environment. To encourage the cooperation and support of the local governments of the localities of the power plants, it has been and will be our policy to seek investment in such power plants by the relevant local governments.

Power plant construction

We have generally acted as the general contractor for the construction of our power plants. Equipment procurement and installation, site preparation and civil works are subcontracted to subcontractors through a competitive bidding process. All of our power plants were completed on or ahead of schedule, enabling certain units to enter service and begin generating income earlier than the estimated in-service date.

Plant start-up and operation

We have historically operated and intend to continue to operate our power plants. Our power plants have established management structures based on well-developed management techniques. We select the superintendent for a new power plant from the senior management of our operating plants early in the construction phase of the new plant, invest in the training of operational personnel, adopt management techniques that improve efficiency and structure our plant bonus program to reward efficient and cost-effective operation of the plant in order to ensure the safety, stability and high availability factor of each power plant. Our senior management meets several times a year with the superintendents of the power plants as a group, fostering a team approach to operations, and conducts annual plant performance reviews with the appropriate superintendent, during which opportunities to enhance the power plant’s performance and profitability are evaluated.

After a coal-fired generating unit is constructed, the contractor tests its installation and systems. Following such tests, the contractor puts the unit through a continuous 168-hour trial run at full load. After successfully passing the continuous 168-hour test and obtaining approval from the local governments, the unit may commence its commercial operation. Trial run of a wind power project consists of two phases: (i) trial run of single wind power generating unit and (ii) trial run of the entire wind power project as a whole. After successfully passing the trial run, the wind power project may commence its commercial operation.

Development of power plants in Singapore

The Singapore electricity industry had traditionally been vertically integrated and owned by the government. Since 1995, steps have been taken to liberalize the power industry, including the incorporation of the Public Utilities Board (PUB) in 1995, establishment of Singapore Electricity Pool (SEP) in 1998, formation of Energy Market Authority (EMA) in 2001, and the evolvement of the SEP into the New Electricity Market of Singapore (NEMS) in 2003. The EMA is a statutory body responsible for the economic, technical and competition regulation of the gas and electricity industry in Singapore. In carrying out its functions as the regulator of the power sector, EMA is empowered under the Electricity Act to issue and enforce licenses, codes of practices and performance standards. Energy Market Company Pte Ltd. (the "EMC") is the market company licensed to operate the wholesale market, or the NEMS.

In Singapore, a company is required to hold a generation license issued by the EMA if it generates electricity by means of one or more generating units with capacity of 10 MW or above. If connected to the power grid, the generating unit(s) must be registered with the EMC and will have to compete with other power generation companies to secure dispatch in the NEMS.

To ensure adequate electricity supply in Singapore, the EMA targets a minimum reserve margin (the excess of generating capacity over peak electricity demand) of 30% based on a loss of load probability (a measure of the probability that a system demand will exceed capacity during a given period, often expressed as the estimated number of days over a year) of three days per year. The 30% required reserve margin is to cater for scheduled maintenance as well as forced outages of generating units in the system. If the reserve margin falls below the required 30% due to demand growth and/or plant retirements, it would be an indication that new generation investments in generation units are needed to maintain system security.

The EMA intends to keep the increase and decrease in generating capacity commercially driven as far as practicable. As a precaution against the risk of insufficient generating capacity in the system, the EMA has planned to  implement a competitive auction-based mechanism, i.e. FCM, to maintain the reserve margin at no less than the required 30% by providing adequate incentives to existing generation capacity and new investment. FCM also aims to facilitate orderly entry and exit of the generation capacity by taking into account of the FCM auction outcomes, up to 4 years in advance. EMA has targeted to implement the proposed schemeby first quarter of 2021.

By most measures of market power, the Singapore market is highly concentrated, as the three largest power generation companies account for approximately 60% of total power capacity. Since December 2002, EMA has imposed a licensed capacity cap (in MW) on these three power generation companies to prevent them from increasing their market dominance/power. Following a review of the vesting contract regime in 2016, EMA imposed a 25% cap on capacity market share to all generation licensees to prevent structural increases in market concentration/power. With regard to the three largest power generation companies, the cap imposed by EMA is the higher of either the 25% capacity market share cap or their respective licensed capacity cap, until the expiry of their respective generation license. This provides an option for the three largest power generation companies to increase their generation capacities beyond their current generation license up to 25% capacity market share cap.

New entrants as well as existing competitors have invested in new generating capacity or repowering of existing plants to take advantage of the LNG Vesting Scheme. This will impact the market negatively as these new capacities compete for market share as well as to avoid the gas take-or-pay penalties arising out of an oversupplied market.

EMA issued a Singapore Electricity Market Outlook (“SEMO”) 2019, which provides a long-term outlook of the energy market, such as the projected supply and demand conditions to facilitate power generation investment decisions. Based on the data provided by EMA, annual system demand and system peak demand are projected to grow at a CAGR of 1.5 – 2.1% over the next 10 years (2020 to 2030), while a net reduction of about 2,800 MW of generation capacity, through retirement or mothballing plans, is projected over the next 2 years (2020 to 2021).

We have developed the Tembusu Multi-Utilities Complex (the "TMUC") in Singapore. The TMUC was developed in two phases. Phase 1 consists of 1 x 450 t/h coal-biomass co-fired circulated fluidized bed boiler, 2 x 200 t/h diesel/natural gas-fired boilers and 1 x 101MW steam turbine-generator, and other components of the plant. Phase 2 consists of 1 x 450 t/h coal-biomass co-fired circulated fluidized bed boiler, 1 x 200 t/h diesel/natural gas-fired boiler and 1 x 32.5MW steam turbine-generator, and other components of the plant. Phase 1 and Phase 2 commenced commercial operations in March 2013 and June 2014 respectively. The first train of 62.5 m³/h wastewater treatment facility commenced commercial operation in September 2015. TPL owns 100% equity interest in this project.

TPL collaborated with ST Marine Pte. Ltd. (ST Marine), an affiliate of Singapore Temasek Holdings, to participate in the tender for Singapore’s Public Utilities Board (PUB)’s fifth desalination plant project under a Develop-Build-Own-Operate (BDOO) scheme on July 6, 2017. The capacity of the desalination plant is 30 MIGD (137,000 cubic meter per day). The desalination plant is located at Tembusu Jurong Island, adjacent to TMUC in order to achieve synergy. TPL and ST Marine incorporated a concession company, TP-STM Water Resources Pte. Ltd. (TP-STM Water Resources), on November 1, 2017 and executed the Water Purchase Agreement (WPA) with PUB on November 6, 2017. TPL owns 60% equity interests in TP-STM Water Resources. The construction of the desalination plant commenced in August 2018. The project commercial operation date (PCOD) is scheduled for June 2020. The term of concession is 25 years from the PCOD.

Pricing policy

Pricing policy in China

Prior to April 2001, the on-grid tariffs for our planned output were designed to enable us to recover all operating and debt servicing costs and to earn a fixed rate of return. Since April 2001, however, the PRC Government has gradually implemented a new on-grid tariff-setting mechanism based on the operating terms of power plants as well as the average costs of comparable power plants.

On July 3, 2003, the State Council approved the tariff reform plan and made it clear that the long-term objective of the reform is to establish a standardized and transparent tariff-setting mechanism.

Pursuant to the NDRC circular issued in June 2004, on-grid tariffs for newly built power generating units commencing operation from June 2004 should be set on the basis of the average cost of comparable units adding tax and reasonable return in the regional grid. It provides challenges and incentives for power generation companies to control costs for building new generating units.

On March 28, 2005, the NDRC issued the Interim Measures on Regulation of On-grid Tariff, the Interim Measures on Regulation of Transmission and Distribution Tariff, and the Interim Measures on Regulation of End-user Tariff, or collectively the “Interim Measures,” to provide guidance for the reform of tariff-setting mechanism in the transition period. Under the Interim Measures, the tariff is classified into on-grid tariff, transmission and distribution tariff and end-user tariff. Transmission and distribution tariff will be instituted by the government. The end-user tariff will be based on on-grid tariff and transmission and distribution tariff. The government is responsible for regulating and supervising power tariffs based on the principles of promoting efficiency, encouraging investment and improving affordability.

In December 2004, the NDRC proposed and the State Council approved the establishment of a linkage mechanism between coal and power prices, pursuant to which, the NDRC may adjust power tariffs if the change of the average coal price reaches 5% within a period of six months compared with the preceding same period. The change in a period, if less than 5%, will be carried forward to the future periods until the accumulated amounts reach 5%. With a goal to encourage power generation companies to reduce cost and improve efficiency, only around 70% of coal price increases will be allowed to pass to end-users through an increase of power tariffs, and power generation companies will bear the remaining 30%. In May 2005, the NDRC activated the coal-electricity price linkage mechanism for the first time to increase on-grid tariffs and end-user tariffs in the northeastern region, central region, eastern region, northwestern region and southern region. We accordingly increased the on-grid tariffs of our power plants in the northeastern region, central region, eastern region and northwestern region on May 1, 2005 and in the southern region on July 15, 2005. In June 2006, the coal-electricity price linkage mechanism was reactivated by the NDRC to increase on-grid tariffs and end-user tariffs in the northeastern region, central region, eastern region, northwestern region and southern region. We accordingly increased the on-grid tariffs of most of our power plants in the same regions on June 30, 2006.

In May 2007, NDRC and the State Environment Protection Administration jointly promulgated Interim Administrative Measures on Electricity Price of Coal-fired Generating Units installed with Desulphurization Facilities and the Operations of Such Facilities, which provided that a premium for desulphurization may be charged on the price of the electricity generated by generating units installed with desulphurization facilities on and from the date on which such desulphurization facilities are tested and accepted by a relevant environment protection regulator. Such pricing policy is also applicable to the old generating units which are installed with desulphurization facilities. The new measures are more stringent on the regulation of the coal-fired power plants with desulphurization facilities, setting forth the categories under which the price including a desulphurization premium will be offset or otherwise penalized based on the ratio of utilization of the relevant desulphurization facilities on an annual basis. As of December 31, 2013, all of our existing coal-fired generating units have installed and operated the desulphurization facilities and enjoyed the desulphurization premium.

In June 2008, NDRC issued Notice of Raising the Power Tariff, pursuant to which, the power tariff in provincial grids nationwide was increased by an average of RMB0.025 per kWh. In August 2008, NDRC issued Notice of Raising the On-grid Tariffs of the Thermal Power Plants, pursuant to which, the on-grid tariff of thermal power plants, including plants fueled by coal, oil, gas and co-generation, was increased by an average of RMB0.02 per kWh.

On February 25, 2009, NDRC, SERC and China National Energy Administration jointly promulgated the Notice regarding Cleaning up the Concessional Tariff Scheme, pursuant to which, (i) the concessional tariff scheme at the local level is banned, and (ii) certain measures, such as direct purchase by large end-users and adopting peak and off-peak power pricing policy, will be carried out to reduce enterprises’ power cost. In addition, the notice emphasizes the supervision and inspection over the setting of power tariffs. For wind power plants located in a specific wind source area, a unified wind power tariff shall be applied. On October 11, 2009, in order to promote a fair market condition and the optimization of electric power resources, NDRC, SERC and China National Energy Administration jointly promulgated the Circular on Regulating the Administration of Electric Power Transaction Tariff to regulate the tariff-setting mechanism for the on-grid tariff, transmission and distribution tariff and end-user tariff and clean up the local preferential power tariffs provided to high energy consumption companies. Pursuant to a notice issued by NDRC, with effect from November 20, 2009, certain adjustments on the on-grid tariffs have been made in various regions of China in order to resolve the inconsistencies in tariffs, rationalize the tariff structure and promote the development of renewable energy.

In 2010, the PRC Government started to implement the direct power purchase policy. As of December 31, 2013, some of the provinces where we operate power plants are approved by the NDRC to implement the direct power purchase by large power end-users. In addition, during 2010 SERC issued several circulars and notices to regulate the trans-provincial and interregional transaction of power and/or power generation right, in which the power purchase price shall be freely determined by negotiation through the market pricing mechanism. In December 2012, SERC issued another circular to further regulate the trans-provincial and interregional transaction of power and/or power generation right.

In May 2011, NDRC issued a notice, increasing the on-grid tariffs of thermal power plants to partially compensate the increased costs incurred by thermal power plants resulting from increases in coal prices. Different adjustments on tariffs were made in different provinces. In November 2011, PRC Government made further nationwide adjustments on power tariffs, including an average of RMB0.026 per kWh increase in on-grid tariff for thermal power plants. In December 2012, NDRC issued a notice, which provided that, from January 1, 2013, NDRC would provide an RMB0.008 per kWh denitrification premium for all coal-fired generating units equipped with denitrification facilities that are inspected and accepted by authorized national or provincial authority.

In March 2012, the PRC Government issued a notice, which mandated the confirmation method for the power generation projects, subsidy standards and fund appropriation standards relating to the application for a subsidy for renewable energy power price of power generation projects. In December 2012, the PRC Government issued the Notice on the Guidelines of Enhancing the Reform of Marketization of Coal Used for Power Generation to further reform the coal pricing mechanism. Effective January 1, 2013, all key coal purchase contracts between power generation companies and coal suppliers were terminated and contracts are directly negotiated between power generation companies and coal suppliers without the interference of local governments. According to the notice, the NDRC will no longer issue inter-provincial guidance on the railway transportation capacity plan. In addition, the dual-track coal pricing system, which included the government regulated mandatory annual contract pricing and spot market prices for the remaining coal production output of each coal supplier, was abolished due to the narrowing gap between the government regulated coal contract price and the spot market price. Pursuant to the notice, future coal contract prices will be determined by the market and freely negotiated between power generation companies and coal suppliers. Furthermore, the coal-electricity price linkage mechanism will continue to be implemented and constantly improved. Once the coal price fluctuates for more than 5% on an annual basis, the on-grid tariff would be adjusted accordingly. The notice also mandates that power generation companies absorb 10% of the coal price fluctuations as compared to 30% prior to 2013. Given the narrow gap between the key contract coal price and the spot market price, the overall on-grid tariff was not adjusted.

In September 2013, NDRC issued the Notice on the Adjustment of Power Tariff for Power Generation Companies and Related Matters, pursuant to which the on-grid tariffs for coal-fired generating units were lowered, by a national average of RMB0.013 per kWh, and the on-grid tariff for gas turbine power plants was slightly increased. The Notice also increased the power tariff for power-generating companies that are equipped with denitrification facilities and dust-removal facilities.

In March 2014, the NDRC and the Ministry of Environmental Protection jointly issued the Measures to Monitor the Operation of Environmental Protection Tariffs and Facilities Regarding Coal-fired Generating Units, under which the standard on-grid electricity tariff incorporating environmental protection element will no longer be

applicable to coal-fired generating units unless the coal-fired power generating enterprise has completed renovation for environmental protection acceptable after testing. In August 2014, the NDRC issued the Notice to Further Resolve Conflicts Regarding Environmental Protection Tariff, under which the standard on-grid tariff for coal-fired power generating units is lowered with the view to resolve the environmental protection tariffs conflicts such as denitrification and dedusting of coal-fired power generation enterprises, and setting the tariff subsidy for denitrification and dedusting at RMB0.01/kWh and RMB0.002/kWh, respectively. In December 2014, the NDRC issued the Notice Regarding Adjusting Standard On-grid Tariff for Onshore Wind Powers, under which the standard on-grid tariff for each of Class I, Class II and Class III wind powers is lowered by RMB0.02, and the tariff for Class IV wind power remains unchanged at RMB0.61/kWh. In December 2014, the NDRC issued the Notice Regarding Certain issues of On-grid Tariff of Natural Gas Powers, defining the principles to formulate and modify the tariff of electricity generated by natural gas, aiming to regulate on-grid tariff administration and used facilitate healthy and orderly growth of natural gas power generating sector in China.

In April 2015, the NDRC issued the Notice on Reducing On-grid Tariff for Coal-fired Power and Commercial and Industrial Power Tariff in order to guide on tariffs for natural gas and for companies that utilize denitration or dedusting techniques or with extremely low emissions, to lower commercial and industrial power tariff, and to moderately lower on-grid tariff for coal-fired power, the power tariff in provincial grids nationwide was decreased by an average of RMB0.02 per kWh.

In December 2015, the NDRC issued the Notice on Issues of Perfecting the Mechanism of Coal-electricity Price Linkage, confirming the annual cycle of the mechanism, the NDRC’s leading role in implementing the mechanism, and provinces and cities’ executor role in implementing the mechanism. The coal-electricity prices with which the mechanism of coal-electricity price linkage is in line are indexed to the national thermal coal price index. The benchmark coal price is the provincial average price in China’s thermal coal price index of 2014. And the benchmark tariff is in principle the on-grid tariff in line with the benchmark coal price. In December 2015, the NDRC also issued the Notice on Improving On-grid Tariff Policy for Wind Power and Photovoltaic Power, which established a policy that the benchmark on-grid tariffs for wind power and photovoltaic power decrease in line with the development of these two types of power plants. To further indicate the investment expectation, the Notice confirmed the benchmark on-grid tariffs for wind power of 2016 and 2018. The 2016 benchmark on-grid tariff for photovoltaic power has been confirmed, yet that of 2017 and onward will be confirmed at a later stage.

On January 1, 2016, after the annual review based on the calculations prescribed in the mechanism of coal-electricity price linkage, the NDRC adjusted on-grid tariff for coal-fired power and commercial and industrial power tariff. National on-grid tariffs for coal power decreased by an average of RMB0.03 per kWh, based on the relevant regulations, RMB0.01 per kWh of which shall be contributed to a specialized corporate restructuring fund with the purpose of supporting placement of personnel laid off during the supply-side reform. The NDRC also increased on-grid tariff for renewable power by RMB0.004 per kWh in order to replenish the renewable energy fund and to support emission reduction efforts of coal-fired power generation enterprises and to resolve conflicts regarding environmental protection tariffs.

In December 2016, in order to implement General Office of the State Council’s Energy Development Strategic Action Plan (2014-2020) about achieving equal on-grid tariff for wind and solar power with coal power to encourage the orderly development of wind and solar power by properly guiding investments in these areas, the NDRC issued the Announcement on the Adjustment of Standard On-Grid Tariff for Solar and Onshore Wind Power. From January 1, 2017, standard on-grid tariffs for Class I, Class II and Class III solar powers were adjusted to RMB0.65 per kWh, RMB0.75 per kWh and RMB0.85 per kWh, respectively, which is RMB0.15 per kWh, RMB0.13 per kWh and RMB0.13 per kWh lower than the corresponding tariff in 2016. Such standard on-grid tariff will be adjusted annually. 2018 standard on-grid tariff for Class I, Class II and Class III onshore wind power decreased by RMB0.04 per kWh, RMB0.02 per kWh, RMB0.01 per kWh, respectively. Yunnan Province has been recategorized as Class II from Class IV, which meant the standard on-grid tariff for wind power generated in Yunnan province will decrease by an additional RMB0.12 per kWh.

In June 2017, NDRC issued Circular on Canceling or Reducing Governmental Funds and Additional Charges and Reasonably Adjusting On-Grid Tariff Structure, which cancels the special fund for industrial restructuring charged to the power generating enterprises and reduces major water conservancy project construction fund and large and medium-sized reservoir resettlement support fund by 25% to relieve power generation enterprises from its difficulties in daily operations.

In December 2017, NDRC issued Circular on the Pricing Policy of Photovoltaic Projects in 2018, From January 1, 2018, standard on-grid tariffs for Class I, Class II and Class III solar powers were adjusted to RMB0.55 per kWh, RMB0.65 per kWh and RMB0.75 per kWh, respectively (tax included). All distributed photovoltaic projects commencing operation after January 1, 2018, adopting “Self Generate, Self Consume, with Spare Power Put On-grid” model, shall apply a subsidy of RMB0.37 per kWh. All distributed photovoltaic projects adopting “All Power Put On-grid” model shall apply the price set by the region they locate at.

In May 2018, the NDRC, NEA and MOF issued Circular on the Issues related to Photovoltaic Projects in 2018, reducing the standard on-grid tariffs by RMB0.05 for each of Class I, Class II and Class III solar powers. All distributed photovoltaic projects commencing operation after the issuance of the circular, adopting “Self Generate, Self Consume, with Spare Power Put On-grid” model, shall apply a subsidy of RMB0.32 per kWh. All distributed photovoltaic projects adopting “All Power Put On-grid” model shall apply the price set by the region they locate at. In June 2018, the NDRC, NEA and MOF issued the Notice on Releasing the Catalogue of Additional Subsidies for Renewable Energy Tariff (the Seventh Group), which provides that on-grid renewable energy projects incorporated in the catalogue shall not receive the subsidy from the fund of additional subsidies for renewable energy tariff.

In 2019, NDRC and NEA successively issued, among others, Notice on Regulating the Management of Priority Generation and Priority Purchase Plan, Notice on Establishing and Perfecting Renewable Energy Power Consumption Guarantee Mechanism, Notice on Full Release of Power Generation and Utilization Plan for Operating Power Users, and Guidance on Deepening the Reform of the On-grid Tariff Formation Mechanism for Coal-fired Power to guarantee the purchase of clean energy such as wind power and solar power, increase the utilization rate of renewable energy, and reduce the amount of abandoned wind and solar power. In principle, the power generation and utilization plans for operating power users are all opened up with scope of power transactions further expanded. The current on-grid tariff benchmark mechanism has been changed to the market pricing mechanism of "floating around base price," and the previous coal-power price linkage mechanism has been cancelled.

Pricing Policy in Singapore

Pricing Policy of Electricity in Singapore

All licensed power plants in Singapore sell their plant output into the NEMS under a half-hourly competitive bidding process, during which a clearing price is determined based on the projected system demand. All successful bids/power plants that are cleared in each half hour will be dispatched automatically by control signals from the Power System Operator, a division of the EMA, and in turn will receive the cleared price as determined earlier. The cleared price paid to the power plants is the nodal price at their point of injection, and the Market Clearing Engine, the computer software that creates dispatch schedules and determines market clearing prices, automatically produces a different price at each node on the network. A Demand Response scheme is being introduced where demand could be curtailed in response to high prices in return for a share of the total savings arising out of lower prices as a result of demand being reduced.

As there is no certainty in the price or the dispatch levels for any power plants, operators of power plants may enter into short- or long-term financial arrangements with other counterparties or their own subsidiary company involved in the electricity retail market (to end consumers of electricity) to secure stability in their revenue stream and manage the commercial risks associated with operations in a competitive market.

In addition, the major power generation companies, including Tuas Power, are obliged to hold vesting contracts. Vesting contracts are a form of the bilateral contract imposed/vested on the generation companies who had been licensed by the EMA before the establishment of NEMS. Market Support Services Licensee is the counterparty to all of the vesting contracts, and the vesting contracts are settled between the parties through the EMC’s settlement system. The quantity of vesting contract allocated to the power generation company depends on the proportion of such power generation company’s capacity to the total licensed or planned generation capacity at the commencement of the vesting contract regime. Vesting contract price is set by the EMA at the long-run marginal cost and is adjusted by the EMA on a periodic basis for changes in the long-run marginal cost and on a quarterly basis for inflation and changes in fuel prices and electricity demand. Such mechanism helps protect the profit margins of the power generation companies in the Singapore market. The contract quantity and price are currently recalculated every three months. Following the review of vesting contract regime by EMA in 2016, it is determined that the vesting contract level will maintain at 25% until the end of first half of 2018 and reduce to LNG vesting level by the second half of 2019. The vesting contract regime will be phased out by 2023 when the LNG vesting contracts expire. There will be increased exposure to pool prices which are volatile in nature. The authority has introduced a demand response scheme where loads can choose to participate in peak load shaving and share in part of the consumer surplus and an Electricity Futures Market which attracts independent retailers to enter the Singapore market. We continue to monitor closely and evaluate the impact of such markets on our business.

The gross pool design adopted in NEMS means all quantity sold by retailers to consumers has to be in turn purchased from the pool. The retailers pay for their electricity purchases at the Uniform Singapore Energy Price, which is a weighted average of nodal prices and is determined on a half-hourly basis in the NEMS.

Pricing Policy of Utilities in Singapore

Utilities supply to industrial customers is based on long-term contracts. The pricing of utilities has both fixed and variable components.

Pricing Policy in Pakistan

In 2013, the NEPRA reviewed a proposal from Private Power Infrastructure Board for determination of upfront tariff for power generating enterprises based on imported as well as local coal other than Thar coal. Such proposal was based on data gathered from different sources, including feasibility studies of Engro Group, Applied Energy Services and certain tariff determinations of the NEPRA. After due process, determination in the matter of upfront tariff for the Project on Imported/Local Coal (Other than Thar Coal) was issued on June 6, 2013. Later, Government of Pakistan, through Ministry of Energy (formerly known as Ministry of Water & Power), filed a request dated February 11, 2014 for reconsideration of the aforementioned decision determining the upfront tariff for coal power projection. The NEPRA admitted the Government’s reconsideration request and issued a new decision in June 2014. Power generating entities can choose to opt such determined upfront tariff. Huaneng Shandong Ruyi (Pakistan) Energy (Private) Limited, the operating entity of the Sahiwal Power Plant, opted the upfront tariff in 2015 and applied for the adjustment of the element components of such tariff in 2018. The modification was approved in 2019.

Power sales

Each of our power plants has entered into a written agreement with the local grid companies for the sales of its planned power output. Generally, the agreement has a fixed term of one year and provides that the annual utilization hours of the power plant will be determined with reference to the average annual utilization hours of the similar generating units connected to the same grid.

In 2003, SERC and the State Administration of Commerce and Industry jointly promulgated a model contract form (the “Model Contract Form”) for use by power grid companies and power generation companies in connection with electricity sale and purchase transactions. The Model Contract Form contains provisions on the parties’ rights and obligations, amount of electricity subject to purchase, payment method and liabilities for breach of contract, etc. We believe that the publication of the Model Contract Form has facilitated the negotiation and execution of electricity purchase contracts between power grid companies and power generation companies in a fair, transparent and efficient manner. In 2016, a majority of the agreements entered into between our power plants and the local grid companies were based on the Model Contract Form. In 2018, our power plants, large power end-users and electric power companies/grid companies started to sign tripartite contracts.

From 2015, several rules have been issued to implement the plan for power market reform, including Regulation on Market Access and Exit of Electric Power Company, Several Opinions on Further Deepening the Reform of the Electric Power System, Regulations on Orderly Opening Up Electricity Distribution Business, Basic Rules for Mid- to Long- Term Electricity Trade (Interim), Circulate on Orderly Opening Up Power Generation and Consumption Plans, Response regarding Approving Regulation on Pilot Inter-Region Incremental Renewable Energy Power Trade (Interim), Circular on Establishment of Pilot Electricity Power Stock Exchange, Notice on Actively Promoting Market-oriented Power Exchange and Further Improving the Trading Mechanism, and Implementing Rules on Allocating the Distribution Region of the Incremental Distribution Business, etc. to further the reform of electricity market and the establishment of the electricity exchange.

Starting from 2016, two nationwide and 33 provincial level electricity exchanges have been established, and we have invested in the electricity exchanges established in Chongqing, Shanxi and Hubei, holding 3%, 5% and 5% equity interests, respectively. In 2018, the NDRC and NEA issued Circular on Promoting the Standardization of the Power Exchanges, which provides the power exchanges shall pursue the variety of shareholders and demands a non-grid capital involvement of more than 20%. More than 20 market administration committees have been established, and we have participated in the market administration committees established in areas such as Beijing, Guangzhou, Jiangsu, Shanxi, Liaoning, Shanghai, Henan, Hubei, Chongqing, Jilin and Shandong.

At the end of 2018, all municipalities, autonomous regions and provinces, except for Tibet, have finished their approval of electricity distribution price. We have established 20 provincial level energy sales companies and 13 municipal level energy sales companies, taking a meaningful market share.

In 2018, all municipalities, autonomous regions and provinces, except for Tibet, have developed direct purchase programs. We participated in direct purchase programs in all regions where we have control over power plants, other than Hainan, and obtained market shares similar to our capacity shares.

In 2019, with the continuous deepening of power system reform, the Chinese government has adopted the following regimes for power market management and tariff formation: (i) the power generation of power plants consists of base power generation and market trading power generation, the plan of the former is formulated and issued by the government authority and the amount and price of the latter are determined by various market players through bilateral negotiation and platform bidding process. The Chinese government will continue to advance the reform of power system, further strengthen the construction of the power market, and vigorously promote the medium and long-term power exchanges, spot trading market, market-oriented auxiliary service trading market, etc., to improve the efficiency of resource allocation.

In general, establishing liberalized power markets represents the general trend in China’s power market reform, which is conducive to creating a competitive environment that is fair, transparent and equitable.

Power sales in Singapore

According to EMC, the total registered capacity in commercial operation for 2019 in Singapore was 12,440 MW, of which 10,512 MW belonged to CCGT/Cogen/Trigen facilities. In 2019, the peak demand for electricity was 7,195 MW against 2018’s 7,071 MW. The power market in Singapore is competitive, and power generation companies compete to sell their power output into NEMS through a bidding process with hedging via vesting contracts and retail sales. The Vesting Contract Scheme has dropped to LNG vesting level in second half of 2019. The decrease in allocated vesting contract volumes will have to be made up through increased retail sales or increased exposure to pool prices which are volatile in nature.

The volatility in the sales price of the revenue associated with the sale of electricity in the NEMS is effectively managed via vesting contracts and direct retail sales which is carried out through a Tuas Power’s subsidiary. The effective tariffs Tuas Power received for its electricity output are thus largely dependent on the vesting contract prices and volumes as well as prices secured under retail sales. The EMA has launched the Open Electricity Market (previously known as Full Retail Contestability) in April 2018 progressively based on geographical zones and the nationwide launch of the Open Electricity Market was completed.

Utility sales in Singapore

In 2019, TMUC sold 2,264,884MT of steam to customers, a decrease of 5% as compared to 2,385,087 MT in 2018.

Power sales in Pakistan

In 2015, the CPPA assumed the business of National Transmission and Dispatch Company pertaining to the market operations and presently functioning as the market operator in accordance with Rule-5 of the NEPRA Market Operator (Registration, Standards and Procedure) Rules, 2015. The CPPA’s functions includes, among others, procurement of power on behalf of distribution companies (the “DISCOs”). Power generating entities such as Sahiwal Power Plant sell power to CPPA directly, which shall sell power to DISCOs for their further distribution and selling of powers to users.

Fuel supply arrangements

The majority of our power plants in capacity are thermal plants, which are fueled by coal, gas and oil.

Coal

Our coal supply for our coal-fired power plants is mainly obtained from numerous coal producers in Shanxi Province, Inner Mongolia Autonomous Region and Gansu Province. We also obtain coal from overseas suppliers.

In 2017, we purchased 168 million tons of coal and consumed 172 million tons of coal. Of our total coal purchases, 64% was purchased under annual contracting arrangements and the remainder was purchased on the open market. The coal purchase price for our Company, including transportation costs and miscellaneous expenses, averaged approximately RMB547.72 per ton in 2017, representing an increase of 29.4% compared to 2016. Our average unit fuel cost in 2017 increased by 32.41% from that in 2016.

In 2018, we purchased 196 million tons of coal and consumed 187 million tons of coal. Of our total coal purchases, 55% was purchased under annual contracting arrangements and the remainder was purchased on the open market. The coal purchase price for our Company, including transportation costs and miscellaneous expenses, averaged approximately RMB551.35 per ton in 2018, representing an increase of 0.66% compared to 2017. Our average unit fuel cost in 2018 increased by 4.85% from that in 2017.

In 2019, we purchased 183 million tons of coal and consumed 182 million tons of coal. Of our total coal purchases, 62% was purchased under annual contracting arrangements and the remainder was purchased on the open market. The coal purchase price for our Company, including transportation costs and miscellaneous expenses, averaged approximately RMB505.12 per ton in 2019, representing a decrease of 8.38% compared to 2018. Our average unit fuel cost in 2019 decreased by 5.77% from that in 2018.

Singapore’s Tuas Power used coal as primary fuel for its TMUC’s cogeneration plants. Coal is procured from coal producers in Indonesia via two long-term coal supply contracts with 10 year and 15-year terms respectively, and short-term contracts. The prices are indexed to the Global Coal Newcastle Index and HBA (Coal Reference Price which is regulated by Indonesia Government) Index. In 2019, Tuas Power purchased more volume from the open market and with the downtrend of coal prices, there was cost savings in this spot purchase compared to the term contract pricing.

Gas

Currently, the Company has 11 Combined Cycle Gas Turbine Power Plants (“CCGT”) in China, including:

• Huaneng Shanghai Combined Cycle Gas Turbine Power Plant (“Shanghai CCGT”) with gas supply transported through the pipeline of “West-East Gas Transport Project”;

• Huaneng Jiangsu Jinling Combined Cycle Gas Turbine Power Plant (“Jinling CCGT”) with gas supply transported through the pipeline of “West-East Gas Transport Project”;

• Huaneng Beijing Co-generation CCGT Power Plant (“Beijing Co-generation CCGT”) with gas supply transported through Shaanxi-Beijing Pipeline;

• Huaneng Zhejiang Tongxiang Combined Cycle Gas Turbine Power Plant (“Tongxiang CCGT”), with gas supply transported through the pipeline of “West-East Gas Transport Project”;

• Huaneng Chongqing Liangjiang Combined Cycle Gas Turbine Power Plant (“Liangjiang CCGT”) with gas supply transported through the pipeline of “West-East Gas Transport Project”;

• Huaneng Tianjin Lingang Combined Cycle Gas Turbine Co-generation Power Plant (“Lingang CCGT Co-generation”) with gas supply by CNOOC Tianjin Trading Branch and Petro China Tianjin Trading Branch;

• Huaneng Shanxi Dongshan Combined Cycle Gas Turbine Power Plant (“Dongshan CCGT”) with gas supply transported through Shaanxi-Beijing Pipeline II;

• Huaneng Hainan Nanshan Combined Cycle Gas Turbine Power Plant (“Nanshan CCGT”) with gas supply by CNOOC Hainan Branch;

• Huaneng Zhongyuan Combined Cycle Gas Turbine Power Plant (“Zhongyuan CCGT”) with gas supply transported through the pipeline of “West-East Gas Transport Project”;

• Huaneng Jiangsu Suzhou Combined Cycle Gas Turbine Co-generation Power Plant (“Suzhou CCGT Co-generation”) with gas supply transported through the pipeline of “West-East Gas Transport Project”; and

• Huaneng Guangxi Guilin Distributed Energy Project (“Guilin Distributed Energy”) with gas supply by Petro China Nanning Branch.

In addition, Tuas Power in Singapore has five gas-fired combined cycle generating units and three gas-fired backup boilers. The piped gas for Tuas Power is provided by Pavilion Energy Singapore Pte Ltd and Sembcorp Gas Pte Ltd., whereas LNG is provided by Shell Gas Marketing Pte Ltd.

Oil

Tuas Power maintains operation of one 600 MW oil-fired steam generating unit. The oil supply for Tuas Power is purchased from the open market. With the increased competition from new gas-fired CCPs, fuel oil consumption is expected to be marginal at best and therefore future purchases, if any, will be on a spot basis. Diesel, as backup fuel for oil-fired units, is also purchased on a spot basis.

Repairs and maintenance

Each of our power plants shall conduct repairs and maintenance as per the repairs and maintenance plan issued by the regional grid company. The daily repairs and maintenance procedure of generating units shall comply with the relevant rules and technical specifications of the Company.

We arrange our annual repairs and maintenance plan based on the operating status and equivalent operating hours (“EOH”) of generating units:

• for imported units of and above 300MW, and domestically-built units of and above 600MW, we arrange an A-grade repairs and maintenance after 60,000 EOH, after which, we arrange a B-grade repairs and maintenance after 30,000 EOH each;

• for domestically-built units below 600MW, we arrange an A-grade repairs and maintenance after 40,000 EOH, after which we arrange a B-grade repairs and maintenance after 20,000 EOH each, provided, that a C-grade repairs and maintenance shall be conducted after 10,000 EOH or 18 months, whichever is longer;

• for all units not scheduled for any A-grade, B-grade or C-grade repairs and maintenance within a calendar year, a D-grade repairs and maintenance shall be arranged;

• for all high backpressure heating units and circulating fluidized bed boilers, we arrange a separate D-grade repairs and maintenance each calendar year;

• in principle, we arrange no C-grade or above repairs and maintenance for units newly put into operations, but only one D-grade repairs and maintenance for every two units; and

• for CCGT units, we arrange repairs and maintenance pursuant to the long-term servicing agreement.

C. Organizational structure

We are 32.28% owned by HIPDC, which in turn is a subsidiary of Huaneng Group. Huaneng Group was established in 1988 with the approval of the State Council. Huaneng Group also holds a 13.31% equity interest in us in addition to HIPDC’s ownership. In 2002, Huaneng Group was restructured as one of the five independent power generation group companies to take over the power generation assets originally belonging to the State Power Corporation of China. Huaneng Group has a registered capital of RMB20 billion and is controlled and managed by the central government. Huaneng Group is principally engaged in the development, investment, construction, operation and management of power plants; organizing the generation and sale of power (and heat); and the development, investment, construction, production and sale of products in relation to energy, transportation, new energy and environmental protection industries.

HIPDC was established in 1985 as a joint venture controlled by Huaneng Group. HIPDC is engaged in developing, investing, operating and constructing power plants in China. Some of the power plants currently owned and operated by us were originally built and later transferred to us by HIPDC. Both Huaneng Group and HIPDC have agreed to give us preferential rights in the power development business and power assets transfers. See “Item 7.A. Major shareholders” for details.

The following organizational chart sets forth the organizational structure of HIPDC and us as of March 31, 2020:

___________________________

Notes:

* Huaneng Group indirectly holds 100% equity interests in Pro-Power Investment Limited through its wholly owned subsidiary, China Hua Neng Hong Kong Company Limited, and Pro-Power Investment Limited in turn holds 25% equity interests in HIPDC. As a result, Huaneng Group beneficially holds 100% of equity interests in HIPDC.

** 
9.91% was directly held by Huaneng Group, 3.01% was held by Huaneng Group through its wholly owned subsidiary, China Hua Neng Hong Kong Company Limited, and the remaining approximately 0.39% was held by Huaneng Group through its subsidiary, China Huaneng Finance Corporation Limited.

For a detailed discussion of the Company’s subsidiaries, see Note 9 to the Financial Statements.

D. Property, plants and equipment

The following table presents certain summary information on our power plants as of December 31, 2019.

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity	Type of Fuel
(Names as defined below)		(MW)	%	MW
Heilongjiang Province
Xinhua Power Plant	Unit I: Sep. 1979	1 x 200	70%	140	Coal
	Unit II: Sep. 2005	1 x 330	70%	231
Hegang Power Plant	Unit I: Nov. 1998	1x 300	64%	192	Coal
	Unit II: Nov. 1999	1x 300	64%	192
	Unit III: Apr. 2007	1 x 600	64%	384
Daqing Co-generation	Unit I: Jun. 2013	1 x 350	100%	350	Coal
	Unit II: Aug. 2013	1 x 350	100%	350
Yichun Co-generation	Unit I: Sep. 2015	1 x 350	100%	350	Coal
	Unit II: Dec. 2015	1 x 350	100%	350
Sanjiangkou Wind Power	66 turbines: Feb. 2010	99	82.85%	82	Wind
Linjiang Jiangsheng Wind Power	66 turbines: Oct. 2015	99	82.85%	82	Wind
Daqing Heping Aobao Wind Power	32 turbines: Dec. 2011	96	100%	96	Wind
	32 turbines: May 2012	96	100%	96

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity	Type of Fuel
(Names as defined below)		(MW)	%	MW
	32 turbines: Dec. 2013	96	100%	48
Zhaodong Dechang Photovoltaic	Dec. 2017	20	100%	20	Solar
Shuangyu Photovoltaic
Shuangyu Photovoltaic	Jul. 2018	20	100%	20	Solar
Xinhua Photovoltaic	Jun. 2018	20	100%	20	Solar
Donghai Photovoltaic	Jul. 2018	20	100%	20	Solar
Jilin Province
Jiutai Power Plant	Unit I: Oct. 2009	1 x 670	100%	670	Coal
	Unit II: Dec. 2009	1 x 670	100%	670
Changchun Co-generation	Unit I: Dec. 2009	1 x 350	100%	350	Coal
	Unit II: Apr. 2010	1 x 350	100%	350
Nongan Biomass	Dec. 2011	1 x 25	100%	25	Biomass
Linjiang Jubao Hydropower	Sep. 2004	2 x 10	100%	20	Solar
Zhenlai Wind Power	33 turbines: Jun. 2009	49.5	100%	49.5	Wind
	33 turbines: Dec. 2011	49.5	100%	49.5
Siping Wind Power	50 turbines: Oct. 2010	75	100%	75	Wind
	25 turbines: Nov. 2010	50	100%	50
	50 turbines: Dec. 2010	75	100%	75
	2 turbines: 2019	6	100%	6
Tongyu Tuanjie Wind Power	74 turbines: Dec. 2015	148	100%	148	Wind
Linjiang Jubao Photovoltaic	Jun. 2017	15	100%	15	Solar
Zhenlai Photovoltaic	Jun. 2018	20	50%	10	Solar
Liaoning Province
Dalian Power Plan
Phase I	Unit I: Sep. 1988	2 x 350	100%	700	Coal
	Unit II: Dec. 1988
Phase II	Unit III: Jan. 1999	2 x 350	100%	700	Coal
	Unit IV: Jan. 1999
Dandong Power Plant	Unit I: Jan. 1999	2 x 350	100%	700	Coal
	Unit II: Jan. 1999
Yingkou Power Plant
Phase I	Unit I: Jan. 1996	2 x 320	100%	640	Coal
	Unit II: Dec. 1996
Phase II	Unit III: Aug. 2007	2 x 600	100%	1,200	Coal
	Unit IV: Oct. 2007
Yingkou Co-generation	Unit I: Dec. 2009	2 x 330	100%	660	Coal
	Unit II: Dec. 2009
Wafangdian Wind Power	24 turbines: Jun. 2011	48	100%	48	Wind
Changtu Wind Power	33 turbines: Nov. 2012	97.5	100%	97.5	Wind
	24 turbines: Oct. 2014
Suzihe Hydropower	2012	3 x 12.5	100%	37.5	Hydro
Dandong Photovoltaic	May. 2016	10	100%	10	Solar
Yingkou Co-generation Photovoltaic	Jun. 2016	10	100%	10	Solar
Yingkou Co-generation Wind Power	May 2019	12.5	100%	12.5	Wind
Xianrendao Co-generation	Mar. 2017	1 x 50	100%	50	Coal
Yingkou Xianrendao Co-generation Power	Mar. 2017	2*50	100%	100	Coal
Jianchang Bashihan Photovoltaic
Phase I	Aug. 2017	22.03	100%	22.03	Solar
Phase II	Aug. 2017	22.03	100%	22.03	Solar
Xiao Deyingzi Photovoltaic	Aug. 2017	15.56	100%	15.56	Solar
Chaoyang Heiniuyingzi Photovoltaic	Aug. 2017	18.79	100%	18.79	Solar
Inner Mongolia Autonomous Region
Huade Wind Power
Phase I	33 turbines: Dec. 2009	49.5	100%	49.5	Wind

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
Phase II	33 turbines: Jun. 2011	49.5	100%		49.5	Wind
Hebei Province
Shang’ an Power Plant	Unit I: Aug. 1990	2 x 350	100%		700	Coal
Phase I	Unit II: Dec. 1990
Phase II	Unit III: Oct. 1997	2 x 330	100%		660	Coal
	Unit IV: Oct. 1997
Phase III	Unit V: Jul. 2008	2 x 600	100%		1,200	Coal
	Unit VI: Aug. 2008
Kangbao Wind Power
Phase I	33 turbines: Jan. 2011	49.5	100%		49.5	Wind
Kangbao Xitan Photovoltaic	Jun. 2016	20	100%		20	Solar
Zhuolu Dabao Wind Power	24 turbines: Mar. 2017	48	100%		48	Wind
Shang’an Dianchanghuichang Photovoltaic	Dec. 2017	17	100%		17	Solar
Gansu Province
Pingliang Power Plant
Phase I	Unit I: Sep. 2000	3 x 325	65%		633.75	Coal
	Unit II: Jun. 2001
	Unit III: Jun. 2003
	Unit IV: Nov. 2003	1 x 330	65%		214.5	Coal
	Unit V: Feb. 2010	2 x 600	65%		780	Coal
	Unit VI: March 2010
Jiuquan Wind Power	259 turbines: Dec. 2011	401	100%		401	Wind
	3 turbines: 2019	6	100%		6
	20 turbines: 2019	44	100%		44
Jiuquan II Wind Power	100 turbines: Dec. 2014	200	100%		200	Wind
	100 turbines: Jun. 2015	200	100%		200	Wind
Yumen Wind Power	24 turbines: Jun. 2015	48	100%		48	Wind
	67 turbines: Jun. 2015	100.5	100%		100.5	Wind
Yigang Wind Power	96 turbines: Dec. 2015	192	100%		192	Wind
Ningxia Autonomous Region
Ruyi Helan Rooftop Photovoltaic	Jun. 2017	19.8	40%		7.92	Solar
Beijing Municipality
Beijing Co-generation
Phase I	Unit I: Jan. 1998	2 x 165	41%		135.3	Coal
	Unit II: Jan. 1998
	Unit III: Dec. 1998	2 x 220	41%		180.4	Coal
	Unit IV: Jun. 1999
	Unit V: Apr. 2004	1 x 75	41%		30.75	Coal
Beijing Co-generation CCGT
Phase II	Unit VI: Dec. 2011	2 x 306.9	41%		251.66	Gas
	Unit VII: Dec. 2011
	Unit VIII: Dec. 2011	1 x 309.6	41%		126.936	Gas
Beijing Co-generation CCGT
Phase III	Unit IX: Nov. 2017	2 x 342.97	41%		281.24	Gas
	Unit X: Nov. 2017
	Unit XI: Nov. 2017	1 x 312.6	41%		128.166	Gas
Tianjin Municipality
Yangliuqing Co-generation	Unit I: Dec. 1998	4 x 300	55%		660	Coal
	Unit II: Sep. 1999
	Unit III: Dec. 2006
	Unit IV: May 2007
Lingang Co-generation CCGT	Unit I: Dec. 2014	1 x 313	55%		254.65	Gas

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
		1 x 150
Chenxi Photovoltaic	Jun. 2017	2.2	55%		1.21	Solar
Shanxi Province
Yushe Power Plant	Unit III: Oct. 2004	2 x 300	60%		360	Coal
	Unit IV: Nov. 2004
Zuoquan Power Plant	Unit I: Dec. 2011	2 x 673	80%		1,076.8	Coal
	Unit II: Jan. 2012
Dongshan CCGT	Unit I: Oct. 2015	2 x297.7	100%		595.4	Gas
	Unit II: Oct. 2015
	Unit III: Oct. 2015	263.6	100%		263.6	Gas
Yushe Photovoltaic	Jun. 2017	50	100%		50	Solar
Yushe Fupin Photovoltaic	Aug. 2018	10.5	90%		9.45	Solar
Ruicheng Monan Photovoltaic	2019	150	100%		150	Solar
Shandong Province
Dezhou Power Plant
Phase I	Unit I: 1992	1 x 330	100%		330	Coal
	Unit II: 1992	1 x 320	100%		320	Coal
Phase II	Unit III: Jun. 1994	1 x 330	100%		330	Coal
	Unit IV: May 1995	1 x 320	100%		320	Coal
Phase III	Unit V: Jun. 2002	2 x 700	100%		1,400	Coal
	Unit VI: Oct. 2002
Jining Power Plant
Circulating fluidized bed boiler	Unit V: Jul. 2003	2 x 135	100%		270	Coal
	Unit VI: Aug. 2003
Co-generation	Unit I: Nov. 2009	2 x 350	100%		700	Coal
	Unit II: Dec. 2009
Xindian Power Plant
Phase III	Unit V: Sep 2006	2 x 300	95%		570	Coal
	Unit VI: Nov. 2006
Weihai Power Plant
Phase II	Unit III: Mar. 1998	2 x 320	60%		384	Coal
	Unit IV: Nov. 1998
Phase III	Unit V: Dec. 2012	2 x 680	60%		816	Coal
	Unit VI: Dec. 2012
Rizhao Power Plant
Phase I	Unit I: Sep. 1999	1 x 350	88.8%		311	Coal
	Unit II: Jan. 2003	1 x 350	88.8%		311
Phase II	Dec. 2008	2 x 680	100%		1,360	Coal
Zhanhua Co-generation	Jul. 2005	2 x 165	100%		330	Coal
Baiyanghe Power Plant	Unit I: Oct. 2003	1 x 145	80%		116	Coal
	Unit II: Oct. 2003	1 x 145	80%		116
	Unit III: Dec. 2009	1 x 300	80%		240
	Unit IV: Dec. 2009	1 x 300	80%		240
Jiaxiang Power Plant	Unit I: Oct. 2006	1 x 330	40%		132	Coal
	Unit II: May. 2007	1 x 330	40%		132
Jining Co-generation	Unit I: Apr. 2004	1 x 30	40%		12	Coal
	Unit II: Jul. 2004	1 x 30	40%		12
Qufu Co-generation	Unit I: Feb. 2009	1 x 225	40%		90	Coal
	Unit II: Sep. 2009	1 x 225	40%		90
Huangtai Power Plant	Unit I: Nov. 1987	1 x 330	72%		237.6	Coal
	Unit II: Jan. 2011	1 x 350	72%		252
	Unit III: Jan. 2011	1 x 350	72%		252
Yantai Power Plant	Unit I: Apr. 1996	1 x 110	80%		88	Coal

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
	Unit II: Oct. 2005	1 x 160	80%		128
	Unit III: Dec. 2005	1 x 160	80%		128
	Unit IV: Oct. 2006	1 x 160	80%		128
Linyi Power Plant	Unit I: Dec. 2012	1 x 350	60%		210	Coal
	Unit II: Oct. 2013	1 x 350	60%		210
	Unit III: Dec. 1997	1 x 140	60%		84
	Unit IV: Apr. 2003	1 x 140	60%		84
	Unit V: Sep. 2003	1 x 140	60%		84
	Unit VI: Apr. 2005	1 x 140	60%		84
Jining Yunhe Power Plant	Unit I: Jul. 2000	1 x 145	78.68%		114.09	Coal
	Unit II: Nov. 2000	1 x 145	78.68%		114.09
	Unit III: Sep. 2003	1 x 145	78.68%		114.09
	Unit IV: Feb. 2004	1 x 145	78.68%		114.09
	Unit V: Sep. 2006	1 x 330	78.68%		259.64
	Unit VI: Mar. 2006	1 x 330	78.68%		259.64
Liaocheng Co-generation	Unit I: Jan. 2006	1 x 330	60%		198	Coal
	Unit II: Sep. 2006	1 x 330	60%		198
Zhongtai Power Plant	Unit I: May. 2007	1 x 150	80%		120	Coal
	Unit II: Dec. 2007	1 x 150	80%		120
Laiwu Power Plant	Unit I: Dec. 2015	1 x 1000	64%		640	Coal
	Unit II: Nov. 2016	1 x 1000	64%		640
Muping Wind Power	28 turbines: Dec. 2010	42	80%		34	Wind
Penglai Wind Power	24 turbines: Sep. 2014	48	80%		38.4	Wind
	1 turbine: Sep. 2014	1.8	80%		1.44
	24 turbines: Oct. 2016	48	80%		38.4
	1 turbine: Oct. 2016	1.8	80%		1.44
Rushan Wind Power	8 turbines: Sep. 2014	12	80%		9.6	Wind
	11 turbines: Sep. 2014	16.5	80%		13.2
	2 turbines: Oct. 2016	3	80%		2.4
	5 turbines: Oct. 2016	10.5	80%		8.4
Rongcheng Wind Power	1 turbine: Jan. 2006	1.5	48%		0.72	Wind
	1 turbine: Jan. 2006	1.5	48%		0.72
	1 turbine: Jan. 2006	1.5	48%		0.72
	2 turbines: Feb. 2006	3	48%		1.44
	2 turbines: Feb. 2006	3	48%		1.44
	3 turbines: Mar. 2006	4.5	48%		2.16
Dongying Wind Power	32 turbines: Dec. 2009	48	56%		27	Wind
Boshan Photovoltaic	May. 2016	12	80%		10	Solar
Sishui Photovoltaic	Jun. 2015	20	80%		16	Solar
Gaozhuang Photovoltaic	May. 2016	20	80%		16	Solar
Jining Co-generation Photovoltaic	Feb. 2017	20	80%		16	Solar
Zhanhua Qingfenghu Wind Power	50 turbines: Dec. 2017	100	80%		80	Wind
Jining Photovoltaic	Feb. 2017	20	80%		16	Solar
Laiwu Niuquan Photovoltaic	Apr. 2017	20	80%		16	Solar
Furuite Rooftop Photovoltaic	Jun. 2017	6.3	95%		5.99	Solar
Zhanhua Qingfenghu Photovoltaic	Jun. 2017	100	46%		46	Solar
Weihai Haibu Photovoltaic	Jun. 2017	19.75	80%		15.8	Solar
Jining Weishan Zhaozhuang Photovoltaic	Dec. 2017	80	40%		64	Solar
Dezhou Dingzhuang Photovoltaic	13 turbines: 2019	52	80%		41.6	Wind
Henan Province
Qinbei Power Plant
Phase I	Unit I: Nov. 2004	2 x 600	60%		720	Coal
	Unit II: Dec. 2004
Phase II	Unit III: Nov. 2007	2 x 600	60%		720	Coal
	Unit IV: Nov. 2007
Phase III	Unit V: Mar. 2012	2 x 1000	60%		1,200	Coal

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
	Unit VI: Feb. 2013
Zhongyuan CCGT	Unit I: Aug. 2007	2 x 390	90%		702	Coal
	Unit II: Jan. 2008
Luoyang Co-generation Power Plant	Unit I: May. 2015	2 x 350	80%		560	Coal
	Unit II: Jun. 2015
Mianchi Co-generation	Unit I: Dec. 2016	2 x 350	60%		420	Coal
	Unit II: Dec. 2016
Zhumadian Wind Power	16 turbines: Dec. 2016	32	90%		28.8	Wind
Qinbei Dianchanghuichang
Photovoltaic	Jun. 2017	20	60%		12	Solar
Tangyin Wind Power	69 turbines: Dec. 2018	151.8	100%		151.8	Wind
Mianchi Wind Power	27 turbines: 2019	54	100%		54	Wind
	3 turbines: 2019	21	100%		21
Zhenyao Wind Power	24 turbines: 2019	48	96.52%		46.33	Wind
Puyang Wind Power	36 turbines: 2019	90	100%		90	Wind
Xiayi Wind Power	4 turbines: 2019	10	100%		10	Wind
Jiangsu Province
Nantong Power Plant
Phase I	Unit I: Sep. 1989	2 x 352	100%		704	Coal
	Unit II: Mar. 1990
Phase II	Unit III: Jul. 1999	2 x 350	100%		700	Coal
	Unit IV: Oct. 1999
Nanjing Power Plant	Unit I: Mar. 1994	2 x 320	100%		640	Coal
	Unit II: Oct. 1994
Taicang Power Plant
Phase I	Unit I: Dec. 1999	2 x 320	75%		480	Coal
	Unit II: Apr. 2000
Phase II	Unit III: Jan. 2006	2 x 630	75%		945	Coal
	Unit IV: Feb. 2006
Taicang Dianchanghuichang Photovoltaic	Jun. 2018	50	75%		37.5	Solar
Huaiyin Power Plant
Phase II	Unit III: Jan. 2005	2 x 330	63.64%		420	Coal
	Unit IV: Mar. 2005
Phase III	Unit V: May 2006	2 x 330	63.64%		420	Coal
	Unit VI: Sep. 2006
Huaiyin Dianchang Photovoltaic	Jun. 2018	30	100%		30	Solar
Jinling Power Plant
CCGT	Unit I: Dec. 2006	2 x 390	60%		468	Gas
	Unit II: Mar. 2007
CCGT-Cogeneration	Unit I: April 2013	191.3	51%		97.56	Gas
	Unit II: May 2013	191.3	51%		97.56
Jinling Coal-Fired	Unit III: Dec. 2009	2 x 1,030	60%		1,236	Coal
	Unit IV: Aug. 2012
Suzhou Co-generation	Unit I: Aug. 2006	2 x 60	53.45%		64.14	Coal
	Unit II: Oct. 2006
Nanjing Chemical Industry Park Co-generation	Unit I: Apr. 2016	50	70%		35	Coal
	Unit II: Dec. 2016	50	70%		35
Qidong Wind Power
Phase I	61 turbines: Mar. 2009	91.5	65%		59.5	Wind
Phase II	25 turbines: Jan. 2011	50	65%		32.5	Wind
	22 turbines: Jun. 2012	44	65%		28.6	Wind
Rudong Wind Power	24 turbines: Nov. 2013	48	90%		43.2	Wind
Tongshan Wind Power
Phase I	25 turbines: Mar. 2016	50	70%		35	Wind

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
Phase II	24 turbines: Dec. 2017	48	70%		33.6	Wind
Luhe Wind Power	25 turbines: Dec. 2016	50	100%		50	Wind
Rudong Offshore Wind Power	26 turbines: Mar, 2017	106.4	70%		211.68	Wind
	44 turbines: Sep. 2017	196
Guanyun Power	Unit I: Dec. 2017	2 x 25	100%		50	Coal
	Unit II: Dec. 2017
Suzhou CCGT	Unit I: Jul. 2017	178	100%		452	Gas
	Unit II: Jul. 2017	48
	Unit III: Sep. 2017	178
	Unit IV: Sep. 2017	48
Yizheng Wind Power
Phase I	21 turbines: Dec. 2017	46.2	100%		46.2	Wind
Phase II	6 turbines: Jul. 2018	13.8	100%		13.8	Wind
Guanyun Photovoltaic	Jun. 2017	14.1	100%		14.1	Solar
Dafeng Offshore Wind Power	48 turbines: 2019	201.6	100%		201.6	Wind
	20 turbines: 2019	100	100%		100
Shanghai Municipality
Shidongkou I	Unit I: Feb. 1988	4 x 325	100%		1,300	Coal
	Unit II: Dec. 1988
	Unit III: Sep. 1989
	Unit IV: May 1990
Shidongkou II	Unit I: Jun. 1992	2 x 600	100%		1,200	Coal
	Unit II: Dec. 1992
Shidongkou Power	Unit I: Oct. 2011	2 x 660	50%		660	Coal
	Unit II: Oct. 2011
Shanghai CCGT	Unit I: May 2006	3 x 390	70%		819	Gas
	Unit II: Jun. 2006
	Unit III: Jul. 2006
Chongqing Municipality
Luohuang Power Plant
Phase I	Unit I: Sep. 1991	2 x 360	60%		432	Coal
	Unit II: Feb. 1992
Phase II	Unit III: Dec. 1998	2 x 360	60%		432	Coal
	Unit IV: Dec. 1998
Phase III	Unit V: Dec. 2006	2 x 600	60%		720	Coal
	Unit VI: Jan. 2007
Liangjiang CCGT	Unit I: Oct. 2014	2 x 467	90%		840.6	Gas
	Unit II: Dec. 2014
Fengjie Jinfengshan Wind Power	55 turbines: Dec. 2018	110	100%		110	Wind
Zhejiang Province
Changxing Power Plant	Unit I: Dec. 2014	2 x 660	100%		1320	Coal
	Unit II: Dec. 2014
Yuhuan Power Plant
Phase I	Unit I: Nov. 2006	2 x 1,000	100%		2,000	Coal
	Unit II: Dec. 2006
Phase II	Unit III: Nov. 2007	2 x 1,000	100%		2,000	Coal
	Unit IV: Nov. 2007
Tongxiang CCGT	Unit I: Sep. 2014	1 x 258.4	95%		245.48	Gas
	Unit II: Sep. 2014	1 x 200	95%		190	Gas
Changxing Photovoltaic	Dec. 2014	5	100%		5	Solar
	Mar. 2015	5	100%		5	Solar
Changxing Hongqiao Photovoltaic	Sep. 2016	30	100%		30	Solar
Huzhou Distributed Photovoltaic	Jun. 2017	16.13	100%		20	Solar
	Dec. 2017	3.87

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
Jiapu Photovoltaic	2019	1.03	100%		1.03	Solar
Xitang Photovoltaic	2019	1.77	100%		1.77	Solar
Hunan Province
Yueyang Power Plant
Phase I	Unit I: Sep. 1991	2 x 362.5	55%		398.75	Coal
	Unit II: Dec. 1991
Phase II	Unit III: Mar. 2006	2 x 300	55%		330	Coal
	Unit IV: May 2006
Phase III	Unit V: Jan. 2011	2 x 600	55%		660	Coal
	Unit VI: Aug. 2012
Xiangqi Hydropower	Unit I: Dec. 2011	4 x 20	100%		80	Hydro
	Unit II: May 2012
	Unit III: Jul. 2012
	Unit IV: Aug. 2012
Subaoding Wind Power	40 turbines: Dec. 2014	80	100%		80	Wind
	35 turbines: May. 2015	70	100%		70	Wind
Guidong Wind Power	42 turbines: Aug. 2015	48	100%		48	Wind
	18 turbines: Sep. 2015	36	100%		36	Wind
Yueyang Xingang Photovoltaic	May. 2017	10	60%		6	Solar
Yueyang Leigutai Photovoltaic	Jun. 2017	20	55%		11	Solar
Lianping Wind Power	1 turbine: 2019	3.6	80%		2.88	Wind
	13 turbines: 2019	44.2	80%		35.36
	1 turbine: 2019	3.2	80%		2.56
	7 turbines: 2019	14	80%		11.2
Yueyang Sanhui Photovltaic	2019	20	55%		11	Solar
Hubei Province
Enshi Maweigou Hydropower	Dec. 2011	3 x 5	100%		15	Hydro
	Dec. 2015	2 x 20	100%		40	Hydro
Dalongtan Hydropower	Unit I: May 2006	12	97%		11.64	Hydro
	Unit II: Aug. 2005	12	97%		11.64	Hydro
	Unit III: Mar. 2006	12	97%		11.64
	Unit IV: Oct. 2008	1 x 1.6	97%		1.552	Hydro
Yangluo Power Plant
Phase I	Unit I: Jun. 1993	2 x 300	75%		450	Coal
	Unit II: Jan. 1994
Phase II	Unit III: May 1997	2 x 330	75%		495	Coal
	Unite IV: Dec. 1997
Phase III	Unit V: Oct. 2006	2 x 600	75%		900	Coal
	Unit VI: Dec. 2006
Jingmen Co-generation	Unit I: Nov. 2014	2 x 350	100%		700	Coal
	Unit II: Oct. 2014
Yingcheng Co-generation	Unit II: Jan. 2015	1 x 350	100%		350	Coal
	Unit I: Jun. 2016	1 x 50	100%		50	Coal
Jieshan Wind Power
Phase I	24 turbines: Jun. 2015	48	100%		48	Wind
Phase II	36 turbines: Aug. 2016	72	100%		72	Wind
Zhongxiang Hujiawan Wind Power	12 turbines: Dec. 2017	24	100%		24	Wind
	63 turbines: Aug. 2018	126	100%		126	Wind
Suizhou Zengdufuhe Photovoltaic	Sep. 2017	16.7	100%		20	Solar
	Oct. 2017	3.3
Jiangxi Province
Jinggangshan Power Plant
Phase I	Unit I: Dec. 2000	2 x 300	100%		600	Coal
	Unit II: Aug. 2001
Phase II	Unit III: Nov. 2009	2 x 660	100%		1,320	Coal

Plant or Expansion	Actual In-service Date	Current Installed Capacity	Ownership	Attributable Capacity		Type of Fuel
(Names as defined below)		(MW)	%	MW
	Unit IV: Dec. 2009
Jianggongling Wind Power	24 turbines: Dec. 2014	48	100%		48	Wind
	13 turbines: Dec. 2016	26	100%		26	Wind
Ruijin Power Plant	Unit I: May 2008	2 x 350	100%		700	Coal
	Unit II: Aug. 2008
Anyuan Power Plant	Unit I: Jun. 2015	2 x 660	100%		1,320	Coal
	Unit II: Aug. 2015
Hushazui Wind Power	13 turbines: Dec. 2016	26	100%		26	Wind
Linghuashan Wind Power	26 turbines: Jun. 2017	52	100%		100	Wind
	24 Turbines: Sep. 2017	48
Gaolongshan Wind Power	36 turbines: Nov. 2018	80	100%		80	Wind
Daguzhai Wind Power	28 turbines: 2019	84	100%		84	Wind
	4 turbines: 2019	10	100%		10
Shangrao Poyang Photovoltaic	2019	159.66	50%		80.58	Solar
Anhui Province
Chaohu Power Plant	Unit I: May 2008	2 x 600	60%		720	Coal
	Unit II: Aug. 2008
Hualiangting Hydropower Phase I	Unit I: Oct. 1981	2 x 10	100%		20	Hydro
	Unit II: Nov. 1981
Phase II	Unit III: Nov. 1987	2 x 10	100%		20	Hydro
	Unit IV: Nov. 1987
Huaining Wind Power	25 turbines: Jun. 2016	50	100%		50	Wind
	45 turbines: Dec. 2017	99	100%		99	Wind
Fujian Province
Fuzhou Power Plant
Phase I	Unit I: Sep. 1988	2 x 350	100%		700	Coal
	Unit II: Dec. 1988
Phase II	Unit III: Oct. 1999	2 x 350	100%		700	Coal
	Unit IV: Oct. 1999
Phase III	Unit V: Jul. 2010	2 x 660	100%		1,320	Coal
	Unit VI: Oct. 2011
Changle Photovoltaic	Jun. 2017	10