20-F

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 20-F

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

OR

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

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

Commission file number: 001-35530

BROOKFIELD RENEWABLE PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

Bermuda

(Jurisdiction of incorporation or organization)

73 Front Street, 5th Floor, Hamilton HM 12, Bermuda

(Address of principal executive offices)

Jane Sheere

73 Front Street, 5th Floor, Hamilton HM 12, Bermuda

Telephone: 441-294-3304

Facsimile: 441-296-4475

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Class	Name of each exchange on which registered
Limited Partnership Units	New York Stock Exchange, Toronto Stock Exchange

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

None

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

None

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

180,388,361 Limited Partnership Units as of December 31, 2017

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

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  S  No  ☐ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  S  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 definitions of “accelerated filer”, “large accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act (Check one):

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

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

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. [  ]

☐U.S. GAAP  x 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 S 

TABLE OF CONTENTS
INTRODUCTION AND USE OF CERTAIN TERMS			6
FORWARD-LOOKING STATEMENTS			15
CAUTIONARY STATEMENT REGARDING THE USE OF NON-IFRS MEASURES			17
PART I			18
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS		18
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE		18
ITEM 3.	KEY INFORMATION		19
	3.A	SELECTED FINANCIAL DATA	19
	3.B	CAPITALIZATION AND INDEBTEDNESS	22
	3.C	REASONS FOR THE OFFER AND USE OF PROCEEDS	22
	3.D	RISK FACTORS	22
ITEM 4.	INFORMATION ON THE COMPANY		50
	4.A	HISTORY AND DEVELOPMENT OF THE COMPANY	50
	4.B	BUSINESS OVERVIEW	54
	4.C	ORGANIZATIONAL STRUCTURE	80
	4.D	PROPERTY, PLANT AND EQUIPMENT	85
ITEM 4A.	UNRESOLVED STAFF COMMENTS		85
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS		85
	5.A	OPERATING RESULTS	85
	5.B	LIQUIDITY AND CAPITAL RESOURCES	141
	5.C	RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC.	141
	5.D	TREND INFORMATION	141
	5.E	OFF-BALANCE SHEET ARRANGEMENTS	141
	5.F	TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS	141
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES		142
	6.A	DIRECTORS AND SENIOR MANAGEMENT	142
	6.B	COMPENSATION	150
	6.C	BOARD PRACTICES	151
	6.D	EMPLOYEES	160
	6.E	SHARE OWNERSHIP	160
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS		161
	7.A	MAJOR SHAREHOLDERS	161
	7.B	RELATED PARTY TRANSACTIONS	161
	7.C	INTEREST OF EXPERTS AND COUNSEL	172
ITEM 8.	FINANCIAL INFORMATION		172
	8.A	CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION	172
	8.B	SIGNIFICANT CHANGES	172
ITEM 9.	THE OFFER AND LISTING		172
	9.A	OFFER AND LISTING DETAILS	172
	9.B	PLAN OF DISTRIBUTION	174
	9.C	MARKETS	174
	9.D	SELLING SHAREHOLDERS	174
	9.E	DILUTION	174
	9.F	EXPENSES OF THE ISSUE	174
ITEM 10.	ADDITIONAL INFORMATION		174
	10.A	SHARE CAPITAL	174
	10.B	MEMORANDUM AND ARTICLES OF ASSOCIATION	175
	10.C	MATERIAL CONTRACTS	205
	10.D	EXCHANGE CONTROLS	208
	10.E	TAXATION	208
	10.F	DIVIDENDS AND PAYING AGENTS	229
	10.G	STATEMENT OF EXPERTS	229
	10.H	DOCUMENTS ON DISPLAY	229
	10.I	SUBSIDIARY INFORMATION	230
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		230
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		230
PART II			231
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		231
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS		231
ITEM 15.	CONTROLS AND PROCEDURES		231
ITEM 16.	[RESERVED]		232
	16.A	AUDIT COMMITTEE FINANCIAL EXPERT	232
	16.B	CODE OF ETHICS	232
	16.C	PRINCIPAL ACCOUNTANT FEES AND SERVICES	232
	16.D	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE	233
	16.E	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	233
	16.F	CHANGE IN REGISTRANT'S CERTIFYING ACCOUNTANT	234
	16.G	CORPORATE GOVERNANCE	234
	16.H	MINE SAFETY DISCLOSURE	234
PART III			234
ITEM 17.	FINANCIAL STATEMENTS		234
ITEM 18.	FINANCIAL STATEMENTS		234
ITEM 19.	EXHIBITS		234
SIGNATURE			239
INDEX TO FINANCIAL STATEMENTS			F-1

Page 3

Page 4

INTRODUCTION AND USE OF CERTAIN TERMS  

Unless otherwise specified, information provided in this annual report on Form 20-F (this “Form 20-F”) is as of December 31, 2017. Unless the context requires otherwise, when used in this Form 20-F, the terms “Brookfield Renewable”, “we”, “us” and “our” refer to BEP, BRELP, the Holding Entities and the Operating Entities, each as defined in this Form 20-F, individually or collectively, as applicable; “BEP” refers to Brookfield Renewable Partners L.P.; and “Brookfield” refers to Brookfield Asset Management Inc. and its subsidiaries (other than Brookfield Renewable). All references to “our portfolio” include 100% of the capacity and energy of the facilities even though we do not own 100% of the economic output of such facilities (see the table under Item 4.B. “Business Overview — Our Operations” for details on our portfolio).

“ABCA” means the Business Corporations Act (Alberta),  R.S.A. 2000, c. B-9, as amended, including the regulations promulgated under such Act.

“Adjusted EBITDA” means revenues less direct costs (including energy marketing costs) and other income, before the effects of interest expense, income taxes, depreciation, management service costs, non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments, distributions to preferred limited partners and other typical non-recurring items. Refer to “Cautionary Statement Regarding Use of Non-IFRS Measures”.

“Adjusted Funds From Operations” means Funds From Operations less Brookfield Renewable’s share of levelized sustaining capital expenditures (based on long-term capital expenditure plans). Sustaining capital expenditures are an estimate made by management of the amount of ongoing capital investment required to maintain condition of all our facilities and current revenues. Refer to “Cautionary Statement Regarding Use of Non-IFRS Measures”.

“Affiliate” or “affiliate” of any person is a person that, directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with such person.

“Amended and Restated Limited Partnership Agreement of BEP” means the fourth amended and restated limited partnership agreement of BEP, dated May 3, 2016, as further amended on May 25, 2016, February 14, 2017 and January 16, 2018.

“Amended and Restated Limited Partnership Agreement of BRELP” means the third amended and restated limited partnership agreement of BRELP, dated February 11, 2016, as further amended on May 25, 2016, February 14, 2017 and January 16, 2018.

“ANEEL” has the meaning given to it under Item 4.B “Business Overview — Brazilian Business”.

“Audit Committee” means the audit committee of the board of directors of the Managing General Partner.

 “Base Management Fee” has the meaning given to it under Item 6.A “Directors and Senior Management — Our Master Services Agreement — Management Fee”.

“Base Marketing Fee” has the meaning given to it under Item 7.B “Related Party Transactions — Energy Marketing Agreement”.

“BC Hydro” means British Columbia Hydro and Power Authority.

“BEM LP” means Brookfield Energy Marketing LP, an indirect wholly-owned subsidiary of Brookfield Asset Management.

“BEP” means Brookfield Renewable Partners L.P., formerly named Brookfield Renewable Energy Partners L.P.

“Bond Indenture” means the amended and restated indenture, dated as of November 23, 2011, among Finco, The Bank of New York Mellon and BNY Trust Company of Canada, as amended and restated from time to time, governing the Finco Bonds.

“BPUSHA” means Brookfield Power US Holding America Co.

“BRELP” means Brookfield Renewable Energy L.P.

Page 5

“BRELP Class A Preferred Units” means the Class A Preferred Limited Partnership Units, issuable in series, of BRELP.

“BRELP General Partner” means BRP Bermuda GP Limited, which serves as the general partner of BRELP GP LP.

“BRELP GP LP” means BREP Holding L.P., which serves as the general partner of BRELP.

“BRELP Preferred Units” means the preferred limited partnership units in the capital of BRELP.

“BRELP Series 5 Preferred Units” means the Class A Preferred Units, Series 5 of BRELP.

“BRELP Series 7 Preferred Units” means the Class A Preferred Units, Series 7 of BRELP.

“BRELP Series 8 Preferred Units” means the Class A Preferred Units, Series 8 of BRELP.

“BRELP Series 9 Preferred Units” means the Class A Preferred Units, Series 9 of BRELP.

“BRELP Series 10 Preferred Units” means the Class A Preferred Units, Series 10 of BRELP.

“BRELP Series 11 Preferred Units” means the Class A Preferred Units, Series 11 of BRELP.

“BRELP Series 12 Preferred Units” means the Class A Preferred Units, Series 12 of BRELP.

“BRELP Series 13 Preferred Units” means the Class A Preferred Units, Series 13 of BRELP.

“BRELP Series 14 Preferred Units” means the Class A Preferred Units, Series 14 of BRELP.

“Brookfield” means Brookfield Asset Management and any subsidiary of Brookfield Asset Management, other than entities within Brookfield Renewable.

“Brookfield Asset Management” means Brookfield Asset Management Inc.

“Brookfield Renewable” means BEP, BRELP, the Holding Entities and the Operating Entities, taken together.

“Brookfield Renewable Power Assets” means Brookfield’s renewable power assets (other than the assets held by the Fund) that were transferred to BEP on November 28, 2011.

“BRP Equity” means Brookfield Renewable Power Preferred Equity Inc.

“BRPI” means Brookfield Renewable Power Inc., an indirect wholly-owned subsidiary of Brookfield Asset Management.

“CBCA” means the Canada Business Corporations Act, R.S.C. 1985, c. C-44, as amended, including the regulations promulgated under such Act.

“CDS” means CDS Clearing and Depository Services Inc.

“CFA” means a “controlled foreign affiliate” as defined in the Tax Act.

“Class A Preference Shares” means BRP Equity’s Class A Preference Shares, issuable in series (which includes the Series 1, Series 2, Series 3, Series 4, Series 5 and Series 6 Preference Shares).

“Class A Preferred Units” means BEP’s Class A Preferred Limited Partnership Units, issuable in series (which includes the Series 5, Series 7, Series 8, Series 9, Series 10, Series 11, Series 12, Series 13 and Series 14 Preferred Units), of BEP.

“Class B Preference Shares” has the meaning given to it under Item 10.B “Memorandum and Articles of Association – BRP Equity”.

“Co-gen” means gas-fired co-generation.

“Code” has the meaning given to it under Item 6.C “Board Practices — Code of Business Conduct and Ethics”.

“CODM” has the meaning given to it under Item 5.A “Operating Results — “— Financial Performance Review on Proportionate Information”.

Page 6

“Common Shares” has the meaning given to it under Item 10.B “Memorandum and Articles of Association — BRP Equity”.

“Conflicts Policy” has the meaning given to it under Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties — Conflicts of Interest”.

“CPI” means the Canadian consumer price index.

“CRA” means the Canada Revenue Agency.

“DRIP” means BEP’s distribution reinvestment plan.

“DRS Statement” has the meaning given to it under Item 4.B “Business Overview — Our LP Unit Distribution Reinvestment Plan”.

“DTC” means The Depository Trust Company.

“EDGAR” means the Electronic Data Gathering, Analysis, and Retrieval system administered by the SEC.

“Energy Marketing Agreement” has the meaning given to it under Item 7.B “Related Party Transactions — Energy Marketing Agreement”.

“Energy Revenue Agreement” has the meaning given to it under Item 7.B “Related Party Transactions — Energy Revenue Agreement”.

 “EURIBOR” means the European Interbank Offered Rate.

“Euro Holdco” means Brookfield BRP Europe Holdings (Bermuda) Limited.

“E.U.” means the European Union.

“Exchange Act” means the United States Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

“FAPI” means “foreign accrual property income” as defined in the Tax Act.

“FATCA” means the Foreign Account Tax Compliance provisions of the Hiring Incentives to Restore Employment Act of 2010.

“FCPA” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Our Operations and the Renewable Power Industry”.

“FERC” has the meaning given to it under Item 4.B “Business Overview — North American Business”.

“Finco” means Brookfield Renewable Partners ULC, formerly named Brookfield Renewable Energy Partners ULC.

“Finco Bonds” means all outstanding bonds issued by Finco pursuant to the Bond Indenture.

“Finco BondGuarantors” means, collectively, BEP, BRELP, NA Holdco, LATAM Holdco, Euro Holdco and Investco.

“First Distribution Threshold” has the meaning given to it under item 10.B “Memorandum and Articles of Association – Description of the Amended and Restated Limited Partnership Agreement of BRELP – Distributions”.

“Fixed Amount” has the meaning given to it under Item 7.B “Related Party Transactions — Energy Revenue Agreement”.

“Foreign Tax Credit Generator Rules” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Form 20-F” means this annual report filed on Form 20-F.

“Fund” means Brookfield Renewable Power Fund, a limited purpose trust established under the laws of the Province of Québec, and where appropriate, includes its subsidiaries. 

Page 7

“Funds From Operations” means Adjusted EBITDA less interest, current income taxes, management service costs and distributions to preferred limited partners, before the effects of deferred income taxes, depreciation, non-cash portion of non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments and other typical non-recurring items as these are not reflective of the performance of the underlying business. For the year ended December 31, 2014, “Funds-From-Operations” include the earnings received from the wind portfolio we acquired in Ireland, reflecting our economic interest from January 1 to June 20, 2014.  Refer to “Cautionary Statement Regarding Use of Non-IFRS Measures”.

“GLHA” has the meaning given to it under Item 7.B “Related Party Transactions — Other Power Agreements”.

“GLPL” has the meaning given to it under Item 7.B “Related Party Transactions — Other Power Agreements”.

“Governing Body” in relation to an entity, means the board of directors or equivalent of such entity.

“Government of Canada Yield” on any date means the yield to maturity on such date (assuming semi-annual compounding) of a Canadian dollar denominated non-callable Government of Canada bond with a term to maturity of five years as quoted as of 10:00 a.m. (Toronto time) on such date and which appears on the Bloomberg Screen GCAN5YR Page on such date; provided that, if such rate does not appear on the Bloomberg Screen GCAN5YR Page on such date, the Government of Canada Yield will mean the average of the yields determined by two registered Canadian investment dealers selected by BRP Equity, as being the yield to maturity on such date (assuming semi-annual compounding) which a Canadian dollar denominated non-callable Government of Canada bond would carry if issued in Canadian dollars at 100% of its principal amount on such date with a term to maturity of five years.

“GP Interest” has the meaning given to it under Item 5.A “Operating Results — Presentation to Public Stakeholders”.

“GW” means gigawatt.

“GWh” means gigawatt hour.

“Holder” has the meaning given to it under Item 10.E “Taxation — Certain Material Canadian Federal Income Tax Considerations”.

“Holding Entities” means LATAM Holdco, NA Holdco, Euro Holdco, Investco and any other direct wholly-owned subsidiary of BRELP created or acquired after the date of the Amended and Restated Limited Partnership Agreement of BRELP.

“HPI” has the meaning given to it under Item 7.B “Related Party Transactions — Other Power Agreements”.

“HSS&E” has the meaning given to it under Item 4.B “Business Overview — Operating Philosophy”.

“IASB” means the International Accounting Standards Board.

“IFRS” means the International Financial Reporting Standards, as issued by the IASB.

“Indirect CFA” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Investco” means Brookfield Renewable Investments Limited.

“Investment Company Act” means the United States Investment Company Act of 1940, as amended, and the rules and regulations promulgated under such Act.

“IRS” means the United States Internal Revenue Service.

“Isagen” means Isagen S.A. E.S.P.

“Isagen Acquisition” means the acquisition of Isagen in January 2016 by a consortium that included Brookfield Renewable and its institutional partners.

Page 8

“LATAM Holdco” means BRP Bermuda Holdings I Limited.

“LIBOR” means London Interbank Offered Rate.

“Licensing Agreement” has the meaning given to it under Item 7.B “Related Party Transactions — Licensing Agreement”.

“LIHI” has the meaning given to it under Item 4.B “Our Operations – Environmental Protection and Corporate Social Responsibility”.

“LP Unitholders” means holders of LP Units.

“LP Units” means the non-voting limited partnership units in the capital of BEP, other than the Preferred Units.

“LTA” means long-term average.

“Managing General Partner” means Brookfield Renewable Partners Limited, which serves as BEP’s general partner.

“Market Price” means the volume weighted average of the trading price for our LP Units on the NYSE for the five trading days immediately preceding the date the relevant distribution is paid by BEP.

“Master Services Agreement” means the second amended and restated master management and administration agreement, dated February 26, 2015, as amended from time to time, among Brookfield Asset Management, BEP, BRELP, the Holding Entities, the Service Provider and others.

“MI 61-101” has the meaning given to it under Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

“MPT” has the meaning given to it under Item 7.B “Related Party Transactions — Other Power Agreements”.

“MRE” means the hydrological balancing pool administered by the government of Brazil.

“MW” means megawatt.

“MWh” means megawatt hour.

“NA Holdco” means Brookfield BRP Holdings (Canada) Inc.

“Nominating and Governance Committee” means the nominating and governance committee of the board of directors of the Managing General Partner.

“Non-Resident Entities” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Non-Resident Holder” has the meaning given to it in Item 10.E “Taxation — Holders Not Resident in Canada”.

“Non-Resident Subsidiaries” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Non-Resident Unitholders” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Non-U.S. Holder” has the meaning given to it under Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations”.

“NYSE” means the New York Stock Exchange.

“OCI” has the meaning given to it under Item 5.A “Operating Results – Critical Estimate, Accounting Policies and Internal Controls”.

“Operating Entities” means the subsidiaries of the Holding Entities which, from time to time, directly or indirectly hold, or may in the future hold, assets or operations, including any assets or operations held through joint ventures, partnerships and consortium arrangements.

Page 9

“Original Bond Indenture” has the meaning given to it in Item 10.B “Memorandum and Articles of Association — Finco — Bond Indenture and Guarantees”.

“Ownership Requirement” has the meaning given to it in Item 6.A “Directors and Senior Management — Director LP Unit Ownership Requirements”.

“PFIC” means a passive foreign investment company.

“PJM ISO” means the market operated by PJM Interconnection, L.L.C.

“Power Agency Agreements” has the meaning given to it under Item 7.B “Related Party Transactions — Power Agency Agreements”.

“PPA” means a power purchase agreement, power guarantee agreement or similar long-term agreement between a seller and buyer of electrical power generation.

“Preference Share Guarantees”  means the guarantees granted by the Preference Share Guarantors in respect of the Series 1, Series 2, Series 3, Series 4, Series 5 and Series 6 Preference Shares.

“Preference ShareGuarantors” means, collectively, BEP, BRELP, NA Holdco, LATAM Holdco, Euro Holdco and Investco.

“Preference Shares” means the Class A Preference Shares and the Class B Preference Shares.

“Preferred Unit Guarantees” means the guarantees granted by the Preferred Unit Guarantors in respect of the Series 5, Series 7, Series 8, Series 9, Series 10, Series 11, Series 12, Series 13 and Series 14 Preferred Units.   

“Preferred UnitGuarantors” means, collectively, BRELP, NA Holdco, LATAM Holdco, Euro Holdco and Investco.

“Preferred Unitholders” means holders of Preferred Units.

“Preferred Units” means the preferred limited partnership units in the capital of BEP.

“QEF Election” has the meaning given to it in Item 10.E “Taxation — Consequences to U.S. Holders — Passive Foreign Investment Compliance”.

“Qualifying Income Exception” has the meaning given to it under Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations — Partnership Status of BEP and BRELP”.

“RDSP” has the meaning given to it under Item 3.D “Risk Factors – Risks Related to Taxation – Canada”.

“Redeemable/Exchangeable partnership unit” means a limited partnership unit of BRELP that has the rights of the Redemption-Exchange Mechanism.

“Redemption-Exchange Mechanism” means the mechanism by which Brookfield may request redemption of its limited partnership interests in BRELP in whole or in part in exchange for cash, subject to the right of Brookfield Renewable to acquire such interests (in lieu of such redemption) in exchange for LP Units.

“REFIT”  means the Republic of Ireland’s Renewable Energy Feed-in Tariff 1 and Renewable Energy Feed-in Tariff 2 programs.

“Registration Rights Agreement” has the meaning given to it under Item 7.B “Related Party Transactions — Registration Rights Agreement”.

“Regular Distribution Waterfall” has the meaning given to it under Item 10.B “Memorandum and Articles of Association —Description of the Amended and Restated Limited Partnership Agreement of BRELP — Distributions”.

“Relationship Agreement” means the relationship agreement, dated November 28, 2011, by and among Brookfield Asset Management, BEP, BRELP, the Service Provider and others.

Page 10

“Relevant Foreign Tax Law” has the meaning given to it under Item 10.E “Taxation — Certain Material Canadian Federal Income Tax Considerations — Holders Resident in Canada — Computation of Income or Loss”.

“Resident Holder” means a Holder who, for the purposes of the Tax Act and at all relevant times, is or is deemed to be a resident of Canada.

“RESP” has the meaning given to it under Item 3.D “Risk Factors – Risks Related to Taxation – Canada”.

“RPS” has the meaning given to it under Item 4.B “Business Overview — Global Renewable Power Drivers”.

“RRIF” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“RRSP” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“S&P” means S&P Global Ratings Canada, a business unit of S&P Global Canada Corp.

“Sarbanes-Oxley Act” means the United States Sarbanes-Oxley Act of 2002, including the rules and regulations promulgated thereunder.

“SEC” means the United States Securities and Exchange Commission.

“Second Distribution Threshold” has the meaning given to it under Item 10.B “Memorandum and Articles of Association – Description of the Amended and Restated Limited Partnership Agreement of BRELP – Distributions”.

“Securities Act” means the United States Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

“SEDAR” means the System for Electronic Document Analysis and Retrieval administered by the Canadian Securities Administrators.

“Series 1 Shares” means the Class A Preference Shares, Series 1 of BRP Equity.

“Series 2 Shares” means the Class A Preference Shares, Series 2 of BRP Equity.

“Series 3 Shares” means the Class A Preference Shares, Series 3 of BRP Equity.

“Series 4 Shares” means the Class A Preference Shares, Series 4 of BRP Equity.

“Series 5 Preferred Units” means the Class A Preferred Units, Series 5 of BEP.

“Series 5 Shares” means the Class A Preference Shares, Series 5 of BRP Equity.

“Series 6 Shares” means the Class A Preference Shares, Series 6 of BRP Equity.

“Series 7 Preferred Units” means the Class A Preferred Units, Series 7 of BEP.

“Series 8 Preferred Units” means the Class A Preferred Units, Series 8 of BEP.

“Series 9 Preferred Units” means the Class A Preferred Units, Series 9 of BEP.

“Series 10 Preferred Units” means the Class A Preferred Units, Series 10 of BEP.

“Series 11 Preferred Units” means the Class A Preferred Units, Series 11 of BEP.

“Series 12 Preferred Units” means the Class A Preferred Units, Series 12 of BEP. 

“Series 13 Preferred Units” means the Class A Preferred Units, Series 13 of BEP.

“Series 14 Preferred Units” means the Class A Preferred Units, Series 14 of BEP.

“Service Provider” means BRP Energy Group L.P., Brookfield Renewable Energy Group (Bermuda) Limited, Brookfield Global Renewable Energy Advisor Limited and Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P., and, unless the context otherwise requires, includes

Page 11

any other affiliate of such entities that provides services to Brookfield Renewable pursuant to our Master Services Agreement or any other service agreement or arrangement.

“Service Recipients” means BEP, BRELP, the Holding Entities and, at the option of the Holding Entities, any Operating Entities.

“SHPP” means a small hydroelectric power plant, which is a category of hydro power facilities in Brazil with 30 MW of capacity or less.

“SIFT Rules” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“Tax Act” means the Canadian Income Tax Act, R.S.C. 1985, c. 1. (5th Supp), as amended, including the regulations promulgated under such Act.

“Tax Cuts and Jobs Act” has the meaning given to it under Item 3.D “Risk Factors – Risks Related to Taxation – United States”.

“Tax Proposals” means all specific proposals to amend the Tax Act publicly announced by or on behalf of the Minister prior to the date hereof.

“TerraForm Global” means TerraForm Global, Inc.

“TerraForm Power” means TerraForm Power, Inc.

“TFSA” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

“TJLP” means Taxa de Juros de Longo Prazo.

“Total Capitalization Value” means, in any quarter, the sum of (i) the fair market value of an LP Unit multiplied by the number of LP Units issued and outstanding on the last trading day of the quarter (assuming full conversion of any limited partnership interests held by any member of Brookfield in BRELP into LP Units), plus (ii) for each class or series of security of a Service Recipient (other than LP Units) issued to third parties, the fair market value of such security multiplied by the number of securities of such class or series issued and outstanding on the last trading day of the quarter (calculated on a fully-diluted basis), plus (iii) the principal amount of all debt not captured by paragraph (ii) owed by each Service Recipient (excluding for this purpose any Operating Entity) on the last trading day of the quarter to any person that is not a member of Brookfield Renewable, which debt has recourse to any Service Recipient, less any amount of cash held by all Service Recipients (excluding for this purpose any Operating Entity) on such day.

“Treasury Regulations” means the Treasury regulations promulgated under the U.S. Internal Revenue Code.

“Treaty” means the Canada-United States Income Tax Convention (1980), as amended.

“TSX” means the Toronto Stock Exchange.

“TWh” means terawatt hour.

“UBTI” has the meaning given to it under Item 3.D “Risk Factors — Risks Related to Taxation — United States”.

“U.K.” means the United Kingdom of Great Britain and Northern Ireland.

“Unitholders” means LP Unitholders and Preferred Unitholders.

“Units” means LP Units and Preferred Units.

“U.S.” or “United States” means the United States of America.

“U.S. Holder” has the meaning given to it under Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations”.

“U.S. Internal Revenue Code” means the United States Internal Revenue Code of 1986, as amended.

Page 12

“Voting Agreement” means the voting agreement, dated November 28, 2011, between BEP and Brookfield that provides BEP, through the Managing General Partner, with a number of voting rights, including the right to direct all eligible votes in the election of the directors of the BRELP General Partner.

Page 13

FORWARD-LOOKING STATEMENTS

This Form 20-F contains forward-looking statements concerning the business and operations of Brookfield Renewable. Forward-looking statements may include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. Forward-looking statements in this Form 20-F include statements regarding the quality of Brookfield Renewable’s assets and the resiliency of the cash flow they will generate, BEP’s anticipated financial performance, future commissioning of assets, contracted portfolio, technology diversification, acquisition opportunities, expected completion of acquisitions, future energy prices and demand for electricity, economic recovery, achieving long-term average generation, project development and capital expenditure costs, diversification of shareholder base, energy policies, economic growth, growth potential of the renewable asset class, the future growth prospects and distribution profile of BEP and BEP’s access to capital. In some cases, forward-looking statements can be identified by the use of words such as “plans”, “expects”, “scheduled”, “estimates”, “intends”, “anticipates”, “believes”, “potentially”, “tends”, “continue”, “attempts”, “likely”, “primarily”, “approximately”, “endeavors”, “pursues”, “strives”, “seeks” or variations of such words and phrases, or statements that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved. Although we believe that our anticipated future results, performance or achievements expressed or implied by the forward-looking statements and information in this Form 20-F are based upon reasonable assumptions and expectations, we cannot assure you that such expectations will prove to have been correct. You should not place undue reliance on forward-looking statements and information as such statements and information involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievement expressed or implied by such forward-looking statements and information.

Factors that could cause actual results to differ materially from those contemplated or implied by forward-looking statements include, but are not limited to, the following: 

·changes to hydrology at our hydroelectric facilities, to wind conditions at our wind energy facilities, to irradiance at our solar facilities or to weather generally at any of our facilities;

·volatility in supply and demand in the energy markets;

·our inability to re-negotiate or replace expiring PPAs on similar terms;

·increases in water rental costs (or similar fees) or changes to the regulation of water supply;

·advances in technology that impair or eliminate the competitive advantage of our projects;

·an increase in the amount of uncontracted generation in our portfolio;

·industry risks relating to the power markets in which we operate;

·the termination of, or a change to, the MRE balancing pool in Brazil;

·increased regulation of our operations;

·concessions and licenses expiring and not being renewed or replaced on similar terms;

·increases in the cost of operating our plants;

·our failure to comply with conditions in, or our inability to maintain, governmental permits;

·equipment failures, including relating to wind turbines and solar panels;

·dam failures and the costs and potential liabilities associated with such failures;

·force majeure events;

·uninsurable losses;

·adverse changes in currency exchange rates and our inability to effectively manage foreign currency exposure;

·availability and access to interconnection facilities and transmission systems;

·health, safety, security and environmental risks;

·disputes, governmental and regulatory investigations and litigation;

·counterparties to our contracts not fulfilling their obligations;

·the time and expense of enforcing contracts against non-performing counter-parties and the uncertainty of success;

·our operations being affected by local communities;

·fraud, bribery, corruption, other illegal acts or inadequate or failed internal processes or systems;

Page 14

·our reliance on computerized business systems, which could expose us to cyber-attacks;

·newly developed technologies in which we invest not performing as anticipated;

·labor disruptions and economically unfavorable collective bargaining agreements;

·our inability to finance our operations due to the status of the capital markets;

·operating and financial restrictions imposed on us by our loan, debt and security agreements;

·changes to our credit ratings;

·our inability to identify sufficient investment opportunities and complete transactions;

·the growth of our portfolio and our inability to realize the expected benefits of our transactions or acquisitions;

·our inability to develop greenfield projects or find new sites suitable for the development of greenfield projects;

·delays, cost overruns and other problems associated with the construction and operation of generating facilities and risks associated with the arrangements we enter into with communities and joint venture partners;

·Brookfield’s election not to source acquisition opportunities for us and our lack of access to all renewable power acquisitions that Brookfield identifies;

·we do not have control over all our operations or investments;

·foreign laws or regulation to which we become subject as a result of future acquisitions in new markets;

·changes to government policies that provide incentives for renewable energy;

·a decline in the value of our investments in securities, including publicly traded securities of other companies;

·we are not subject to the same disclosure requirements as a U.S. domestic issuer;

·the separation of economic interest from control within our organizational structure;

·the incurrence of debt at multiple levels within our organizational structure;

·being deemed an “investment company” under the Investment Company Act;

·the effectiveness of our internal controls over financial reporting;

·our dependence on Brookfield and Brookfield’s significant influence over us;

·the departure of some or all of Brookfield’s key professionals;

·changes in how Brookfield elects to hold its ownership interests in Brookfield Renewable;

·Brookfield acting in a way that is not in the best interests of BEP or our Unitholders; and

·other factors described in this Form 20-F, including those set forth under Item 3.D “Risk Factors”, Item 4.B “Business Overview” and Item 5.A “Operating Results”.

We caution that the foregoing list of important factors that may affect future results is not exhaustive. The forward-looking statements represent our views as of the date of this Form 20-F and should not be relied upon as representing our views as of any date subsequent to the date of this Form 20-F. While we anticipate that subsequent events and developments may cause our views to change, we disclaim any obligation to update the forward-looking statements, other than as required by applicable law. For further information on these known and unknown risks, please see Item 3.D “Risk Factors”.

Historical Performance and Market Data

This Form 20-F contains information relating to our business as well as historical performance and market data. When considering this data, you should bear in mind that historical results and market data may not be indicative of the future results that you should expect from us.

Financial Information

The financial information contained in this Form 20-F is presented in U.S. dollars and, unless otherwise indicated, has been prepared in accordance with IFRS. All figures are unaudited unless otherwise indicated. In this Form 20-F, all references to “$” are to U.S. dollars. Canadian dollars, Brazilian reais, Euros, Colombian pesos and British pounds sterling are identified as “C$”, “R$”, “€”, “COP” and “£” respectively.

Page 15

CAUTIONARY STATEMENT REGARDING USE OF NON-IFRS MEASURES

This Form 20-F contains references to Adjusted EBITDA, Funds From Operations, Funds From Operations per Unit and Adjusted Funds From Operations which are not generally accepted accounting measures under IFRS and therefore may differ from definitions of Adjusted EBITDA, Funds From Operations, Funds From Operations per Unit and Adjusted Funds From Operations used by other entities. In particular, our definition of Funds From Operations and Adjusted Funds From Operations may differ from the definition of funds from operations used by other organizations, as well as the definition of funds from operations used by the Real Property Association of Canada (“REALPAC”) and the National Association of Real Estate Investment Trusts, Inc. (“NAREIT”), in part because the NAREIT definition is based on U.S. GAAP, as opposed to IFRS. We believe that Adjusted EBITDA, Funds From Operations, Funds From Operations per Unit and Adjusted Funds From Operations are useful supplemental measures that may assist investors in assessing our financial performance. None of Adjusted EBITDA, Funds From Operations, Funds From Operations per Unit or Adjusted Funds From Operations should be considered as the sole measure of our performance and should not be considered in isolation from, or as a substitute for, analysis of our financial statements prepared in accordance with IFRS. These non-IFRS measures reflect how we manage our business and, in our opinion, enable the reader to better understand our business. Reconciliations of each of Adjusted EBITDA, Funds From Operations, and Adjusted Funds From Operations to net income (loss) are presented in Item 5.A “Operating Results —  Financial Performance Review on Proportionate Information”.  

Page 16

PART I

ITEM 1.       IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2.       OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

Page 17

ITEM 3.       KEY INFORMATION                    

3.A              SELECTED FINANCIAL DATA

The information in this section, excluding the operational information, Adjusted EBITDA, Funds From Operations and Funds From Operations per LP Unit, and Adjusted Funds From Operations set forth in the tables below, is derived from and should be read in conjunction with the audited consolidated financial statements of Brookfield Renewable as at December 31, 2017 and 2016, and for the years ended December 31, 2017, 2016 and 2015 and related notes which are included elsewhere in this Form 20-F. 

See Item 5. “Operating and Financial Review and Prospects,” Item 8. “Financial Information” and Item 18. “Financial Statements”.

Page 18

HISTORICAL OPERATIONAL AND FINANCIAL INFORMATION

YEAR ENDED DECEMBER 31
(MILLIONS, EXCEPT AS NOTED)			2017		2016		2015		2014		2013
Operational information:
Capacity (MW)			16,369		10,731		7,284		6,707		5,849
Total generation (GWh)
	Long-term average generation		42,334		38,982		24,467		22,315		20,303
	Actual generation		43,385		34,071		23,332		22,548		22,222
Proportionate generation (GWh)
	Long-term average generation		23,251		22,362		18,749		17,942		17,050
	Actual generation		23,968		20,222		17,662		18,173		18,927
	Average revenue ($ per MWh)		70		71		71		78		79
Additional financial information:
Net (loss) income attributable to
	Unitholders	$	(56)	$	(65)	$	3	$	114	$	137
Basic income (loss) per LP Unit(1)			(0.18)		(0.23)		0.10		0.42		0.52
Consolidated Adjusted EBITDA(2)			1,751		1,499		1,224		1,219		1,211
Proportionate Adjusted EBITDA(2)			1,142		942		907		1,008		1,055
Funds From Operations(2)			581		419		467		560		594
Adjusted Funds From Operations(2)			513		352		407		502		538
Funds From Operations per LP Unit			1.90		1.45		1.69		2.07		2.24
Distribution per LP Unit			1.87		1.78		1.66		1.55		1.45

AS AT DECEMBER 31
(MILLIONS, EXCEPT AS NOTED)			2017		2016		2015		2014		2013
Property, plant and equipment, at fair value		$	27,096	$	25,257	$	18,358	$	18,566	$	15,741
Equity-accounted investments			721		206		197		273		290
Total assets			30,904		27,737		19,507		19,849		16,999
Long-term debt and credit facilities			11,766		10,182		7,338		7,678		6,623
Deferred income tax liabilities			3,588		3,802		2,695		2,637		2,265
Total liabilities			16,622		15,065		10,744		10,968		9,463
Participating non-controlling interests - in
	operating subsidiaries		6,298		5,589		2,587		2,062		1,303
General partnership interest in a holding
	subsidiary held by Brookfield		58		55		52		59		54
Participating non-controlling interests - in
	a holding subsidiary - Redeemable/
	Exchangeable units held by Brookfield		2,843		2,680		2,559		2,865		2,657
Preferred equity			616		576		610		728		796
Preferred limited partners' equity			511		324		128		-		-
Limited partners' equity			3,956		3,448		2,827		3,167		2,726
Total equity			14,282		12,672		8,763		8,881		7,536
Debt to capitalization			40%		38%		39%		40%		41%

⁽¹⁾For the year ended December 31, 2017, weighted average LP Units, Redeemable/Exchangeable partnership units and GP interest totaled 305.8 million (2016: 288.7 million, 2015: 275.6 million, 2014: 271.1 million and 2013: 265.3 million).

⁽²⁾Non-IFRS measures. See “Cautionary Statement Regarding Use of Non-IFRS Measures”.

Page 19

FINANCIAL REVIEW FOR THE YEARS ENDED DECEMBER 31, 2017 TO 2013

The following table reflects the Adjusted EBITDA, Funds From Operations, Adjusted Funds From Operations and the reconciliation to net income (loss) for the years indicated:

(MILLIONS, EXCEPT AS NOTED)					2017		2016		2015		2014		2013
Generation (GWh) - LTA				42,334		38,982		24,467		22,315		20,303
Generation (GWh) - actual(1)				43,385		34,071		23,332		22,548		22,222
Revenues				$	2,625	$	2,452	$	1,628	$	1,704	$	1,706
Other income(2)(3)(4)					53		64		81		10		11
Share of Adjusted EBITDA from
	equity-accounted investments				51		21		67		29		24
Direct operating costs					(978)		(1,038)		(552)		(524)		(530)
Adjusted EBITDA(5)					1,751		1,499		1,224		1,219		1,211
Fixed earnings adjustment(6)					-		-		-		11		-
Management service costs					(82)		(62)		(48)		(51)		(41)
Interest expense – borrowings					(632)		(606)		(429)		(415)		(410)
Current income taxes					(39)		(44)		(18)		(18)		(19)
Share of interest and cash taxes from
	equity-accounted investments				(22)		(12)		(47)		(3)		(3)
Distributions to preferred limited partners					(28)		(15)		(1)		-		-
Cash portion of non-controlling interests
	Participating non-controlling interests -
		in operating subsidiaries			(341)		(316)		(184)		(145)		(107)
	Preferred equity				(26)		(25)		(30)		(38)		(37)
Funds From Operations(5)					581		419		467		560		594
Less: adjusted sustaining capital expenditures(7)					(68)		(67)		(60)		(58)		(56)
Adjusted Funds From Operations(5)					513		352		407		502		538
Add: cash portion of non-controlling interests					367		341		255		183		144
Add: distributions to preferred limited partners					28		15		1		-		-
Add: adjusted sustaining capital expenditures(7)					68		67		60		58		56
Less: fixed earnings adjustment					-		-		-		(11)		-
Depreciation					(782)		(781)		(616)		(548)		(535)
Unrealized financial instruments (loss) gain					(33)		(4)		(9)		10		37
Share of non-cash loss from equity-accounted investments					(27)		(9)		(10)		(23)		(12)
Deferred income tax (expense) recovery					(49)		97		78		29		18
Other					(34)		(38)		(63)		3		(31)
Net income				$	51	$	40		103	$	203	$	215
Net income (loss) attributable to:
	Non-controlling interests
		Participating non-controlling interests -
			in operating subsidiaries	$	53	$	65	$	69	$	51	$	41
		General partnership interest in a holding
			subsidiary held by Brookfield		(1)		-		-		1		1
		Participating non-controlling interests - in
			a holding subsidiary - Redeemable/
			Exchangeable units held by Brookfield		(23)		(29)		1		55		67
		Preferred equity			26		25		30		38		37
	Preferred limited partners' equity				28		15		1		-		-
	Limited partners' equity				(32)		(36)		2		58		69
Basic and diluted earnings (loss) per LP Unit(8)				$	(0.18)	$	(0.23)	$	0.01	$	0.42	$	0.52

⁽¹⁾Variations in generation are described under Item 5.A “Operating Results – Financial Performance Review on Proportionate Information”.

⁽²⁾In July 2015, Brookfield Renewable, along with its institutional partners, sold its interest in a 102 MW wind facility in California to a third party for gross cash consideration of $143 million, resulting in a gain of $53 million. Brookfield Renewable’s share of the gain was $12 million, representing the 22% interest in the facility and is net of the cash portion of non-controlling interests. 

Page 20

⁽³⁾In July 2015, concession agreements relating to two Brazilian hydroelectric facilities expired. Brookfield Renewable elected not to renew these concession agreements in exchange for compensation of $17 million.

⁽⁴⁾In 2015, Brookfield Renewable realized gains of $31 million on the settlement of foreign currency contracts.

⁽⁵⁾Non-IFRS measures. See “Cautionary Statement Regarding Use of Non-IFRS Measures”

⁽⁶⁾The fixed earnings adjustment relates to Brookfield Renewable’s investment in the acquisition of a wind portfolio in Ireland and the $11 million net Funds From Operations contribution was recorded as part of the purchase price.

⁽⁷⁾Based on long-term capital expenditure plans.

⁽⁸⁾Weighted average LP Units, Redeemable/Exchangeable partnership units and GP interest outstanding during the year totaled 305.8 million (2016: 288.7 million, 2015: 275.6 million, 2014: 271.1 million and 2013: 265.3 million).

3.B              CAPITALIZATION AND INDEBTEDNESS

Not applicable.

3.C              REASONS FOR THE OFFER AND USE OF PROCEEDS

Not applicable.

3.D              RISK FACTORS

You should carefully consider the following factors in addition to the other information set forth in this Form 20-F. If any of the following risks actually occur, our business, financial condition, results of operations and prospects could be adversely affected and the value of our Units would likely decline, and you could lose all or part of your investment.

Risks Related to Our Operations and the Renewable Power Industry

Changes to hydrology at our hydroelectric facilities, wind conditions at our wind energy facilities, irradiance at our solar facilities or weather conditions generally at any of our facilities could materially adversely affect the volume of electricity generated.

The revenues generated by our facilities are correlated to the amount of electricity generated, which in turn is dependent upon available water flows and upon wind, irradiance and weather conditions generally. Hydrology, wind, irradiance and weather conditions have natural variations from season to season and from year to year and may also change permanently because of climate change or other factors. A natural disaster could also impact water flows within the watersheds in which we operate. Wind energy and solar energy are highly dependent on weather conditions and, in particular, on wind conditions and irradiance, respectively.  The profitability of a wind farm depends not only on observed wind conditions at the site, which are inherently variable, but also on whether observed wind conditions are consistent with assumptions made during the project development phase or when a given project was acquired. Similarly, projections of solar resources depend on assumptions about weather patterns, shading and irradiance, which are inherently uncertain and may not be consistent with actual conditions at the site. A sustained decline in water flow at our hydroelectric facilities or in wind conditions at our wind energy facilities or of irradiance at our solar facilities could lead to a material adverse change in the volume of electricity generated, revenues and cash flow. Weather conditions have historically caused variability in sugarcane harvest.  A decline in sugarcane supply caused by drought, frost or floods, to the sugar and ethanol mills that are the feedstock suppliers of our biomass cogeneration facilities, could limit the volume of electricity these facilities are able to generate.

Supply and demand in the energy market is volatile and such volatility could have an adverse impact on electricity prices and a material adverse effect on Brookfield Renewable’s assets, liabilities, business, financial condition, results of operations and cash flow. 

A portion of Brookfield Renewable’s revenues are tied, either directly or indirectly, to the wholesale market price for electricity in the markets in which Brookfield Renewable operates. Wholesale market electricity prices are impacted by a number of factors including: the price of fuel (for example, natural gas) that is used to generate electricity; the management of generation and the amount of excess generating capacity relative to load in a particular market; the cost of controlling emissions of pollution, including the cost of emitting CO₂; the structure of the electricity market; and weather conditions (such as extremely hot or cold weather) that impact electrical load. More generally, there is uncertainty surrounding the trend in electricity demand growth, which is influenced by: macroeconomic conditions; absolute and relative energy prices; and energy conservation and demand-side management. Correspondingly, from a

Page 21

supply perspective, there are uncertainties associated with the timing of generating plant retirements – in part driven by environmental regulations – and with the scale, pace and structure of replacement capacity, again reflecting a complex interaction of economic and political pressures and environmental preferences. For example, declines in natural gas prices have impacted prices in power markets in North America. This volatility and uncertainty in the power market generally, including the non-renewable power market, could have a material adverse effect on Brookfield Renewable’s assets, liabilities, business, financial condition, results of operations and cash flow.

As our contracts expire, we may not be able to replace them with agreements on similar terms.

Certain PPAs in our portfolio will be subject to re-contracting in the future. If the price of electricity in power markets is declining at the time of such re-contracting, it may impact our ability to re-negotiate or replace these contracts on terms that are acceptable to us, or at all. We cannot provide any assurance that we will be able to re-negotiate or replace these contracts once they expire, and even if we are able to do so, we cannot provide any assurance that we will be able to obtain the same prices or terms we currently receive. If we are unable to re-negotiate or replace these contracts, or unable to secure prices at least equal to the current prices we receive, our business, financial condition, results of operation and prospects could be adversely affected.

Conversely, a significant percentage of our sales will be made by facilities subject to indefinite term contracts with Brookfield (taking into account its rights of renewal) at fixed prices per MWh. Accordingly, with respect to those facilities, our ability to realize improved revenues due to increases in market prices may be limited.

A significant portion of the power we generate is sold under long-term PPAs with Brookfield, public utilities or industrial or commercial end-users, some of whom may not be rated by any rating agency. For example, as at December 31, 2017, approximately 42% of our 2018 contracted generation (on a proportionate basis) was with Brookfield entities, the majority of which are not publicly rated and whose obligations are not guaranteed by Brookfield Asset Management.

Increases in water rental costs (or similar fees) or changes to the regulation of water supply may impose additional obligations on Brookfield Renewable.

Water rights are generally owned or controlled by governments that reserve the right to control water levels or impose water-use requirements as a condition of license renewal that differ from those arrangements in place today. We are required to pay taxes, make rental payments or pay similar fees for use of water and related rights once our hydroelectric projects are in commercial operation. Significant increases in water rental costs or similar fees or changes in the way that governments regulate water supply could, if imposed at a material number of our assets in our portfolio, have a material adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow.

Advances in technology could impair or eliminate the competitive advantage of our projects.

Technology related to the production of renewable power and conventional power generation are continually advancing, resulting in a gradual decline in the cost of producing electricity.   If advances in technology further reduce the cost of producing power, the competitive advantage of our existing projects may be significantly impaired or eliminated and our assets, liabilities, business, financial condition, results of operations and cash flow could be materially and adversely affected as a result.

The amount of uncontracted generation in our portfolio may increase. 

As at December 31, 2017, approximately 72% of our generation (on a proportionate basis) was contracted over the following five years under long-term, fixed price contracts with creditworthy counterparties. In each of 2016 and 2017, 91% of our generation (on a proportionate basis) was contracted.  The portion of our portfolio that is uncontracted may increase gradually over time. While increases in uncontracted generation may allow us to be opportunistic and take advantage of high spot-market prices, it will also increase our exposure to variability in power prices, which could, in certain circumstances, have an adverse effect on our business, financial condition, results of operations and cash flows.

There are general industry risks associated with the power markets in which we operate.

Page 22

We currently operate in power markets in North America, South America, Europe and Asia, each of which is affected by competition, price, supply of and demand for power, the location of import/export transmission lines and overall political, economic and social conditions and policies.  Our operations are also largely concentrated in a relatively small number of countries, and accordingly are exposed to country-specific risks (such as weather conditions, local economic conditions or political/regulatory environments) that could disproportionately affect us.  A general and extended decline in the North American, South American, European or Asian economies, or in the economies of the specific countries in which we operate, or sustained conservation efforts to reduce electricity consumption, could have the effect of reducing demand for electricity.

The MRE could be terminated or changed or Brookfield Renewable’s reference amount revised downward.

In Brazil, hydroelectric power generators have access to the MRE, which seeks to stabilize hydrology by assuring that all participant plants in the MRE receive a reference amount of electricity, approximating long-term average regardless of the actual volume of energy generated. Substantially all our assets are part of that pool. In cases of nationwide drought, when the pool as a whole is in shortfall relative to the long-term average, an asset can expect to share the nationwide shortfall pro-rata with the rest of the pool. In addition, specific rules provide the minimum percentages of the reference amount of electricity that must be actually generated each year for assuring participation in the MRE. The energy reference amount is assessed yearly according to the criteria of such regulation, and can be adjusted positively or negatively. If the Brookfield Renewable reference amount is revised, our share of the balancing pool could be reduced. If the MRE is terminated or changed, Brookfield Renewable’s financial results would be more exposed to variations in hydrology at certain hydroelectric facilities in Brazil. In either case, this could have an adverse effect on our results of operations and cash flows.   

Our operations are highly regulated and may be exposed to increased regulation which could result in additional costs to Brookfield Renewable.

Our generation assets are subject to extensive regulation by various government agencies and regulatory bodies in different countries at the federal, regional, state, provincial and local level. As legal requirements frequently change and are subject to interpretation and discretion, we may be unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. Any new law, rule or regulation could require additional expenditure to achieve or maintain compliance or could adversely impact our ability to generate and deliver energy. Also, operations that are not currently regulated may become subject to regulation which could result in additional cost to our business. Further, changes in wholesale market structures or rules, such as generation curtailment requirements or limitations to access the power grid, could have a material adverse effect on our ability to generate revenues from our facilities. For example, in North America, many of our assets are subject to the operating and market-setting rules determined by independent system operators. These independent system operators could introduce rules that adversely impact our operations.

There is a risk that our concessions and licenses will not be renewed.

We hold concessions and licenses and we have rights to operate our facilities which generally include rights to the land and water required for power generation. We generally expect that our concessions and licenses will be renewed. However, if we are not granted renewal rights, or if our concessions or licenses are renewed subject to conditions which impose additional costs, or impose additional restrictions such as setting a price ceiling for energy sales, our profitability and operational activity could be adversely impacted.

The cost of operating our plants could increase for reasons beyond our control.

While we currently maintain an appropriate and competitive cost position, there is a risk that increases in our cost structure that are beyond our control could materially adversely impact our financial performance. Examples of such costs include compliance with new conditions imposed during a relicensing process, municipal property taxes, water rental fees and the cost of procuring materials and services required for our maintenance activities.

Page 23

We may fail to comply with the conditions in, or may not be able to maintain, our governmental permits.

Our generation assets and construction projects are required to comply with numerous supranational (in the case of the E.U.), federal, regional, state, provincial and local statutory and regulatory standards and to maintain numerous licenses, permits and governmental approvals required for operation. Some of the licenses, permits and governmental approvals that have been issued to our operations contain conditions and restrictions, or may have limited terms. If we fail to satisfy the conditions or comply with the restrictions imposed by our licenses, permits and governmental approvals, or the restrictions imposed by any statutory or regulatory requirements, we may become subject to regulatory enforcement or be subject to fines, penalties or additional costs or revocation of regulatory approvals, permits or licenses. In addition, if we are not able to renew, maintain or obtain all necessary licenses, permits and governmental approvals required for the continued operation or further development of our projects, the operation or development of our assets may be limited or suspended. Our failure to renew, maintain or obtain all necessary licenses, permits or governmental approvals may have a material adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow.

We may experience equipment failure, including failures relating to wind turbines and solar panels.

Our generation assets may not continue to perform as they have in the past and there is a risk of equipment failure due to wear and tear, latent defect, design error, operator error or early obsolescence, among other things, which could have a material adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow. Wind turbines and solar panels have shorter lifespans than hydroelectric assets.  Spare parts for wind turbines and solar facilities and key pieces of equipment may be difficult to acquire as a result of a limited number of suppliers of solar panels, inverters, module turbines, towers and other system components and equipment associated with wind and solar power plants.  In addition, warranties on equipment provided to TerraForm Power or TerraForm Global by SunEdison Inc. or any of its affiliates likely will not be available to cover all or a portion of the expense associated with faulty equipment as a result of the bankruptcy of SunEdison Inc.  Any resulting delay in replacing equipment could result in significant delays in returning facilities to full operation, which could adversely impact our business and financial condition.   

The occurrence of dam failures could result in a loss of generating capacity and require us to expend significant amounts of capital and other resources.

The occurrence of dam failures at any of our hydroelectric generating stations or the occurrence of dam failures at other generating stations or dams operated by third parties whether upstream or downstream of our hydroelectric generating stations could result in a loss of generating capacity until the failure has been repaired. If the failure is at one of our facilities, repairing such failure could require us to expend significant amounts of capital and other resources. Such failures could result in damage to the environment or damages and harm to third parties or the public, which could expose us to significant liability.  A dam failure at a generating station or dam operated by a third party could result in new and potentially onerous regulations that could impact Brookfield Renewable’s facilities. Any such new regulations could require material capital expenditures to maintain compliance and our financial position could be adversely affected.

We may be exposed to force majeure events.

The occurrence of a significant event that disrupts the ability of our generation assets to produce or sell power for an extended period, including events which preclude customers from purchasing electricity, could have a material adverse effect on our assets, liabilities, business, financial condition, results of operations and cash flow. In addition, force majeure events affecting our assets could result in damage to the environment or harm to third parties or the public, which could expose us to significant liability. Our generation assets could be exposed to severe weather conditions, natural disasters and potentially catastrophic events.  An assault or an act of malicious destruction, cyber-attacks, sabotage or terrorism committed on our generation assets could also disrupt our ability to generate or sell power. In certain cases, there is the potential that some events may not excuse Brookfield Renewable from

Page 24

performing its obligations pursuant to agreements with third parties and therefore may expose Brookfield Renewable to liability. In addition, many of our generation assets are located in remote areas which may make access for repair of damage difficult.

We may be exposed to uninsurable losses.

While we maintain certain insurance coverage, such insurance may not continue to be offered on an economically feasible basis, may not cover all events that could give rise to a loss or claim involving our assets or operations, and may not cover all of our assets. If our insurance coverage is insufficient and we are forced to bear such losses or claims, our financial position could be materially and adversely affected.  In addition, Brookfield Renewable participates in certain shared insurance arrangements with Brookfield, allowing us to benefit from lower premiums and other economies of scale. In particular, we share third party excess liability, crime, employee dishonesty, director and officer, and errors and omissions insurance coverage. Under such shared policies, claim limits may also be shared between us and Brookfield meaning that any claim by one insured party in a given year reduces the amount that each other insured party can claim. Consequently, there is a risk that Brookfield Renewable’s ability to claim in a given year could be eroded by claims made by Brookfield affiliates who are also covered by a shared policy but that are not part of Brookfield Renewable, which could have an adverse effect on our financial position.

We are subject to foreign currency risk which may adversely affect the performance of our operations and our ability to manage such risk depends, in part, on our ability to implement an effective hedging strategy.

A significant portion of our current operations are in countries where the U.S. dollar is not the functional currency. These operations pay distributions in currencies other than the U.S. dollar, which we must convert to U.S. dollars prior to making such distributions. A significant depreciation in the value of such foreign currencies, measures introduced by foreign governments to control inflation or deflation, currency exchange or export controls may have a material adverse effect on our business, financial condition, results of operations and cash flows. When managing our exposure to currency risks, we use foreign currency forward contracts and other strategies to mitigate currency risk and there can be no assurances that these strategies will be successful.

The ability to deliver electricity to our various counterparties requires the availability of and access to interconnection facilities and transmission systems.

Our ability to sell electricity is impacted by the availability of, and access to, the various transmission systems to deliver power to its contractual delivery point and the arrangements and facilities for interconnecting the generation projects to the transmission systems. The absence of this availability and access, our inability to obtain reasonable terms and conditions for interconnection and transmission agreements, the operational failure or decommissioning of existing interconnection facilities or transmission facilities, the lack of adequate capacity on such interconnection or transmission facilities, curtailment as a result of transmission facility downtime, or the failure of any relevant jurisdiction to expand transmission facilities, may have a material adverse effect on our ability to deliver electricity to our various counterparties or the requirement of counterparties to accept and pay for energy delivery, which could materially and adversely affect our assets, liabilities, business, financial condition, results of operations and cash flow.

Our operations are exposed to health, safety, security and environmental risks.

The ownership, construction and operation of our generation assets carry an inherent risk of liability related to health, safety, security and the environment, including the risk of government imposed orders to remedy unsafe conditions and/or to remediate or otherwise address environmental contamination or damage. We could also be exposed to potential penalties for contravention of health, safety, security and environmental laws and potential civil liability. In the ordinary course of business we incur capital and operating expenditures to comply with health, safety, security and environmental laws, to obtain and comply with licenses, permits and other approvals and to assess and manage related risks. The cost of compliance with these laws (and any future laws or amendments enacted) may increase over time and result in additional material expenditures. We may become subject to government orders, investigations, inquiries or other proceedings (including civil claims) relating to health, safety, security and

Page 25

environmental matters as a result of which our operations may be limited or suspended. The occurrence of any of these events or any changes, additions to or more rigorous enforcement of health, safety, security and environmental laws could have a material and adverse impact on operations and result in additional material expenditures. Additional environmental, health and safety issues relating to presently known or unknown matters may require unanticipated expenditures, or result in fines, penalties or other consequences (including changes to operations) that may be material and adverse to our business and results of operations.

We may be involved in disputes, governmental and regulatory investigations and possible litigation.

In the normal course of our operations, Brookfield Renewable is involved in various legal actions that could expose it to liability for damages. The outcome with respect to outstanding, pending or future actions cannot be predicted with certainty and may be adverse to us and as a result could have a material adverse effect on our assets, liabilities, business, financial condition, results of operations, cash flow and reputation. We and our affiliates are subject to governmental or regulatory investigations from time to time. Governmental and regulatory investigations, regardless of their outcome, are generally costly, divert management attention, and have the potential to damage our reputation.  The unfavorable resolution of any governmental or regulatory investigation could result in criminal liability, fines, penalties or other monetary or non-monetary remedies and could materially affect our business or results of operations.

Counterparties to our contracts may not fulfill their obligations

If, for any reason, any of the purchasers of power under our PPAs, including Brookfield, are unable or unwilling to fulfill their contractual obligations under the relevant PPA or if they refuse to accept delivery of power pursuant to the relevant PPA, our assets, liabilities, business, financial condition, results of operations and cash flow could be materially and adversely affected as we may not be able to replace the agreement with an agreement on equivalent terms and conditions. External events, such as a severe economic downturn, could impair the ability of some counterparties to the PPAs or some customers to pay for electricity received.  In addition, inadequate performance by counterparties to operation and maintenance contracts related to certain of our assets or investments may increase the risk of operational or mechanical failures of such facilities.

Seeking to enforce a contract through the courts may take significant amounts of time and expense with no certainty of success.

High litigation costs and long delays make resolving commercial disputes in court time consuming and expensive.  Such costs can be difficult to calculate with certainty.  In addition, in certain jurisdictions in which we currently conduct business or may seek to conduct business in the future, there can be uncertainty regarding the interpretation and application of laws and regulations relating to the enforceability of contractual rights.  Our business could be adversely affected if we are unsuccessful in enforcing contracts through the courts or if we incur significant amounts of time and expenses seeking to do so. 

The operation of our generating facilities could be affected by local communities.

We may become impacted by the interests of local communities and stakeholders, including in some cases, Indigenous peoples, that affect the operation of our facilities. Certain of these communities may have or may develop interests or objectives which are different from or even in conflict with our objectives, including the use of our project lands and waterways near our facilities. Any such differences could have a negative impact on the successful operation of our facilities. As well, disputes surrounding, and settlements of, Indigenous land claims regarding lands on or near our generating assets could interfere with operations and/or result in additional operating costs or restrictions.

We may suffer a significant loss resulting from fraud, bribery, corruption, other illegal acts, inadequate or failed internal processes or systems, or from external events.

We may suffer a significant loss resulting from fraud, bribery, corruption, other illegal acts, inadequate or failed internal processes or systems, or from external events, such as security threats affecting our ability to operate. We operate in multiple jurisdictions and it is possible that our operations will expand into new jurisdictions.  Doing business in multiple jurisdictions requires Brookfield Renewable

Page 26

to comply with the laws and regulations of the U.S. government as well as those of various non-U.S. jurisdictions. These laws and regulations may apply to Brookfield Renewable, our Service Provider, our subsidiaries, individual directors, officers, employees and third-party agents. In particular, our non-U.S. operations are subject to U.S. and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (“FCPA”). The FCPA, among other things, prohibits companies and their officers, directors, employees and third-party agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. Brookfield Renewable and its officers, directors, employees and third-party agents regularly deal with government bodies and government owned and controlled businesses, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. Also, as we make acquisitions, we may expose ourselves to FCPA or other corruption related risks if our due diligence processes are unable to uncover or detect violations of applicable anti-corruption laws.

The risk of illegal and corrupt acts or failed systems is managed through our infrastructure, controls, systems and people, complemented by central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, as well as personnel and systems risks. We rely on our employees and certain third parties to comply with our policies and processes as well as applicable laws. Specific programs, policies, standards, methodologies and training have been developed to support the management of these risks and, as we expand into new markets and make new investments, we update and implement our programs, policies, standards, methodologies and training to address the risks that we perceive. The failure to adequately identify or manage these risks could result in direct or indirect financial loss, regulatory censure and/or harm to the reputation of Brookfield Renewable.  The acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts may create additional risk of financial loss, regulatory censure and/or harm to the reputation of Brookfield Renewable. In addition, programs, policies, standards, methodologies and training, no matter how well designed, do not provide absolute assurance of effectiveness.

We rely on computerized business systems, which could expose us to cyber-attacks.

Our business relies on information technology. In addition, our business relies upon telecommunication services to remotely monitor and control our assets and interface with regulatory agencies, wholesale power markets and customers. The information and embedded systems of key business partners and regulatory agencies are also important to our operations. In light of this, we may be subject to cybersecurity risks or other breaches of information technology security. Any such breach of our information technology could go undetected for an extended period of time. A breach of our cyber security measures or the failure or malfunction of any of our computerized business systems, associated backup or data storage systems for a significant time period could have a material adverse effect on our business operations, financial reporting, financial condition and results of operations.

There can be no guarantee that newly developed technologies that we invest in will perform as anticipated.

We may invest in and use newly developed, less proven, technologies in our development projects or in maintaining or enhancing our existing assets. There is no guarantee that such new technologies will perform as anticipated. The failure of a new technology to perform as anticipated may materially and adversely affect the profitability of a particular development project.

Performance of our Operating Entities may be harmed by future labor disruptions and economically unfavorable collective bargaining agreements.

Certain of BEP’s subsidiaries are parties to collective agreements that expire periodically and those subsidiaries may not be able to renew their collective agreements without a labor disruption or without agreeing to significant increases in cost. In the event of a labor disruption such as a strike or lock-out, the ability of our generation assets to generate electricity may be impaired and our results from operations and cash flow could be materially and adversely affected.

The economic viability of the feedstock supplier of our biomass cogeneration facilities is linked to the market price for sugar and ethanol, and the prices of these commodities are cyclical and are affected by general economic conditions in Brazil and globally.

Page 27

            The principal feedstock of our 175 MW biomass cogeneration facilities is “bagasse” – a dry, fibrous residue left after the extraction of juice from sugar cane.  The biomass cogeneration facilities that we own are attached to mills that are suppliers of the bagasse, which they provide to these facilities in exchange for some of the steam and electricity that the facilities produce.  The excess electricity that is not delivered to the relevant mill is sold under contract to commercial offtakers, to the government by way of a regulated auction process or directly into the market.  The viability of these mills depends on prevailing market prices for ethanol and sugar as well as other factors that are out of our control.  These mills depend on a single supplier of bagasse, who is the owner of each of these mills.  The supplier of these mills, and therefore of our biomass cogeneration facilities, is currently in financial distress and if such supplier becomes unavailable, we would have to procure bagasse from other sources, which could have a material adverse effect on the value of this investment.

Risks Related to Financing

Our ability to finance our operations is subject to various risks relating to the state of the capital markets.

We expect to finance future acquisitions, the development and construction of new facilities and other capital expenditures out of cash generated from our operations, capital recycling, debt and possible future issuances of equity. There is debt throughout our corporate structure that will need to be replaced from time to time: BEP, BRELP and the Holding Entities have corporate debt and many Operating Entities have limited recourse project level debt (which is non-recourse to BEP). Our ability to obtain debt or equity financing to fund our growth, and our ability to refinance existing indebtedness, is dependent on, among other factors, the overall state of the capital markets (as well as local market conditions, particularly in the case of non-recourse financings), continued operating performance of our assets, future electricity market prices, the level of future interest rates, lenders’  and investors’ assessment of our credit risk, capital markets conditions and investor appetite for investments in renewable energy and infrastructure assets in general and in Brookfield Renewable’s securities in particular. Also, Brookfield Renewable’s financing agreements contain conditions that limit our ability to repay indebtedness prior to maturity without incurring penalties, which may limit our ability to raise capital and financing on favorable terms. To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to fund acquisitions and make necessary capital investments to construct new or maintain existing facilities will be impaired, and as a result, our business, financial condition, results of operations and prospects may be materially and adversely affected.

We are subject to operating and financial restrictions through covenants in our loan, debt and security agreements.

Brookfield Renewable is subject to operating and financial restrictions through covenants in our loan, debt and security agreements. These restrictions prohibit or limit our ability to, among other things, incur additional debt, provide guarantees for indebtedness, grant liens, dispose of assets, liquidate, dissolve, amalgamate, consolidate or effect corporate or capital reorganizations, declare distributions, issue equity interests, and create subsidiaries. A financial covenant in our corporate bonds and in our corporate bank credit facilities limits our overall indebtedness to a percentage of total capitalization, a restriction which may limit our ability to obtain additional financing, withstand downturns in our business and take advantage of business and development opportunities. If we breach our covenants, our credit facilities may be terminated or come due and such event may cause our credit rating to deteriorate and subject Brookfield Renewable to higher interest and financing costs. We may also be required to seek additional debt financing on terms that include more restrictive covenants, require repayment on an accelerated schedule or impose other obligations that limit our ability to grow our business, acquire needed assets or take other actions that we might otherwise consider appropriate or desirable.

Changes in our credit ratings may have an adverse effect on our financial position and ability to raise capital.

The credit rating assigned to BEP or any of our subsidiaries’ debt securities may be changed or withdrawn entirely by the relevant rating agency. A lowering or withdrawal of such ratings may have an adverse effect on our financial position and ability to raise capital.

Risks Related to Our Growth Strategy

Page 28

We may be unable to identify sufficient investment opportunities and complete transactions as planned.

Our strategy for building LP Unitholder value is to seek to acquire or develop high-quality assets and businesses that generate sustainable and increasing cash flows, with the objective of achieving appropriate risk-adjusted returns on our invested capital over the long-term. However, there is no certainty that we will be able to find sufficient investment opportunities and complete transactions that meet our investment criteria. Our investment criteria consider, among other things, the financial, operating, governance and strategic merits of a proposed acquisition including whether we expect it will meet our targeted return hurdle and, as such, there is no certainty that we will be able to continue growing our business by making acquisitions or developing assets at attractive returns. Competition for assets is significant and competition from other well-capitalized investors or companies may significantly increase the purchase price or prevent us from completing an acquisition. We may also decline opportunities that we do not believe meet our investment criteria, which our competition may pursue instead. Further, our growth initiatives are subject to a number of closing conditions, including, as applicable, third party consents, regulatory approvals (including from competition authorities) and other third party approvals or actions that are beyond our control. If all or some of our growth initiatives are unable to be completed on the terms agreed, we may need to delay certain acquisitions or abandon them altogether or may not fully realize their anticipated benefit. In addition, we occasionally seek to recycle capital to fund future acquisitions and the development and construction of new facilities by selling assets; however, we may not be able to complete such sales on desired timelines or at favorable prices. 

Future growth of our portfolio may subject us to additional risks and the expected benefits of our transactions, including acquisitions, may not materialize.

A key part of Brookfield Renewable’s strategy involves seeking acquisition opportunities. Acquisitions in general, and large-scale acquisitions in particular, have the potential to materially increase the scale, scope and complexity of our operations. If we do not effectively manage the additional operations, our business, financial condition and results of operations may be adversely affected.

Acquisitions will likely involve some or all of the following risks, which could materially and adversely affect our business, financial condition or results of operations: the potential to not close or otherwise realize the expected benefits of an announced transaction, the difficulty of integrating the acquired operations and personnel into our current operations; the inability to achieve potential synergies; potential disruption of our current operations; diversion of resources, including the time and attention of Brookfield’s professionals; the difficulty of managing the growth of a larger organization; the risk of entering markets in which we have little experience; the risk of becoming involved in labor, commercial or regulatory disputes or litigation related to the new operations; the risk of environmental or other liabilities associated with the acquired business; the risk of alleged or actual violation of applicable anti-bribery/anti-corruption laws of the acquired business; and the risk of a change of control resulting from an acquisition triggering rights of third parties or government agencies under contracts with, or authorizations held by, the operating business being acquired. While it is our practice to conduct extensive due diligence investigations into businesses being acquired, it is possible that due diligence may fail to uncover or adequately assess all material risks in the business being acquired, whether operational, financial, legal or otherwise. For example, we may fail to identify a change of control trigger in a material contract or authorization, or a contractual counterparty or government agency may take a different view on the interpretation of such a provision to that taken by us, thereby resulting in a dispute. The discovery of any material liabilities subsequent to an acquisition, as well as the failure of an acquisition to perform according to expectations, could have a material adverse effect on Brookfield Renewable’s business, financial condition and results of operations. In addition, if returns are lower than anticipated from new acquisitions, we may not be able to achieve growth in our distributions in line with our stated goals and the market value of our Units may decline.   

There are several factors which may affect our ability to develop existing sites and find new sites suitable for the development of greenfield power projects.

Page 29

Our ability to realize our greenfield development growth plans is dependent on our ability to develop existing sites and find new sites suitable for development into viable projects. Our ability to maintain a development permit often requires specific development steps to be undertaken. Successful development of greenfield renewable power projects is typically dependent on a number of factors, including: the ability to secure an attractive site on reasonable terms; accurately measuring resource availability at levels deemed economically attractive for continued project development; the ability to secure approvals, licenses and permits; the acceptance of local stakeholders, including in some cases, Indigenous peoples; the ability to secure transmission interconnection access or agreements; and the ability to secure a long-term PPA or other sales contract on reasonable terms. Each of these factors can be critical in determining whether or not a particular development project might ultimately be suitable for construction. Failure to achieve any one of these elements may prevent the development and construction of a project. When this occurs we may lose all of our investment in development expenditures and may be required to write-off project development assets.

The development of our greenfield power projects is subject to construction risks and risks associated with the arrangements we enter into with communities and joint venture partners.

Our ability to develop an economically successful project is dependent on, among other things, our ability to construct a particular project on-time and on-budget. The construction and development of generating facilities is subject to environmental, engineering and construction risks that could result in cost-overruns, delays and reduced performance. A number of factors that could cause such delays, cost over-runs or reduced performance include, but are not limited to, permitting delays, changing engineering and design requirements, the costs of construction, the performance of contractors, labor disruptions and inclement weather. In addition, we enter into various types of arrangements with communities and joint venture partners, including in some cases, Indigenous peoples, for the development of projects. Certain of these communities and partners may have or may develop interests or objectives which are different from or even in conflict with our objectives. Any such differences could have a negative impact on the success of our projects.

Brookfield has no obligation to source acquisition opportunities for us and we may not have access to all renewable power acquisitions that Brookfield identifies.

Our ability to grow through acquisitions depends on Brookfield’s ability to identify and present us with acquisition opportunities. Brookfield established BEP to hold and acquire, directly or indirectly, renewable power generating operations and development projects on a global basis. However, Brookfield has no obligation to source acquisition opportunities specifically for us. In addition, Brookfield has not agreed to commit any minimum level of dedicated resources to us for the pursuit of renewable power-related acquisitions. Moreover, pursuant to a relationship agreement between TerraForm Power and Brookfield, Brookfield has, subject to certain exceptions, designated TerraForm Power (of which Brookfield Renewable owns approximately 16%) as its primary vehicle for the acquisition of operating solar and wind assets in North America and Western Europe. There are a number of factors which could materially and adversely impact the extent to which suitable acquisition opportunities are made available to BEP from Brookfield, for example:

·it is an integral part of Brookfield’s (and our) strategy to pursue the acquisition or development of renewable power assets through consortium arrangements with institutional investors, strategic partners or financial sponsors and to form partnerships to pursue such acquisitions on a specialized or global basis. Although Brookfield has agreed with us that it will not enter into any such arrangements that are suitable for us without giving us an opportunity to participate in them, there is no minimum level of participation to which we will be entitled;

·the same professionals within Brookfield’s organization that are involved in acquisitions that are suitable for us are responsible for the consortiums and partnerships referred to above, as well as having other responsibilities within Brookfield’s broader asset management business. Limits on the availability of such individuals will likewise result in a limitation on the availability of acquisition opportunities for us;

·Brookfield will only recommend acquisition opportunities that it believes are suitable for us. Our focus is on assets where we believe that our operations-oriented approach can be deployed to create value. Accordingly, opportunities where Brookfield cannot play an active

Page 30

role in influencing the underlying operating company or managing the underlying assets may not be suitable for us, even though they may be attractive from a purely financial perspective. Legal, regulatory, tax and other commercial considerations will likewise be an important consideration in determining whether an opportunity is suitable and could limit our ability to participate in these certain investments; and

·in addition to structural limitations, the question of whether a particular acquisition is suitable is highly subjective and is dependent on a number of factors including an assessment by Brookfield of our liquidity position, the risk profile of the opportunity, its fit with the balance of our then current operations and other factors. If Brookfield determines that an opportunity is not suitable for us, it may still pursue such opportunity on its own behalf, or on behalf of a Brookfield sponsored partnership or consortium.

In making these determinations, Brookfield may be influenced by factors that result in a misalignment or conflict of interest. See Item 3.D “Risk Factors — Risks Related to our Relationship with Brookfield” and Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

We do not control all our operations and investments.

We have structured some of our operations and investments as joint ventures, partnerships and consortium arrangements. An integral part of our strategy is to participate with institutional investors in Brookfield sponsored or co-sponsored consortiums for asset acquisitions and as a partner in or alongside Brookfield sponsored or co-sponsored partnerships that target acquisitions that suit our profile. These arrangements are driven by the magnitude of capital required to complete acquisitions of renewable assets and other industry-wide trends that we believe will continue. Such arrangements involve risks not present where a third party is not involved, including the possibility that partners or co-venturers might become bankrupt or otherwise fail to fund their share of required capital contributions. Additionally, partners or co-venturers might at any time have economic or other business interests or goals different from Brookfield Renewable and Brookfield.

Joint ventures, partnerships and consortium investments generally provide for a reduced level of control over an acquired company because governance rights are shared with others or in some cases may be delegated to a third party like Brookfield. Consequently, management and operations, as well as the timing and nature of any exit, are often made by a majority vote of the investors or by separate agreements that are reached with respect to individual decisions. For example, when we participate with institutional investors in Brookfield sponsored or co-sponsored consortiums for asset acquisitions and as a partner in or alongside Brookfield sponsored or co-sponsored partnerships, there is often a finite term to the investment, which could lead to the investment being sold prior to the date we would otherwise choose. Similarly, the recent acquisition of a 51% interest in TerraForm Power, which was made by BEP together with its institutional partners, did not result in BEP having control of TerraForm Power. Accordingly, decisions relating to the management and operation of TerraForm Power and its assets are not made by BEP.

In addition, such operations may be subject to the risk that any joint venture, partnership or consortium may make business, financial or management decisions with which we do not agree or the management of the company may take risks or otherwise act in a manner that does not serve our interests. Because we may not have the ability to exercise control over such operations, we may not be able to realize some or all of the benefits that we believe will be created from Brookfield’s involvement. If any of the foregoing were to occur, our financial condition and results of operations could suffer as a result.

The sale or transfer of interests in certain of our operations that are joint ventures, partnerships or consortium arrangements are subject to rights of first refusal or first offer, tag along rights or drag along rights and some agreements in these operations provide for buy-sell or similar arrangements. Such rights may be triggered at a time when we may not want them to be exercised and such rights may inhibit our ability to sell our interest in an entity within the desired time frame or on any other desired basis. In addition, the operations are also all subject to pre-emptive or default rights which may lead to the joint venture or third parties compulsorily acquiring assets from the joint venture.

Page 31

We may pursue acquisitions in new markets that are subject to foreign laws or regulations that are more onerous or uncertain than the laws and regulations we are currently subject to.

We may pursue acquisitions in new markets that are regulated by foreign governments and regulatory authorities and subject to foreign laws. For example, through the acquisition of TerraForm Global, we acquired an additional 307 MW in Brazil, 302 MW in India, 167 MW in China, 99 MW in South Africa (this includes 33 MW in respect of which TerraForm Global receives the economic benefit, but has not yet acquired), 39 MW in Thailand, 26 MW in Uruguay and 12 MW in Malaysia.  Foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in, for example, the U.S., which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Any existing or new operations may also be subject to significant political, economic and financial risks, which vary by country, and may include: changes in government policies or personnel; changes in general economic conditions; restrictions on currency transfer or convertibility; changes in labor relations; political instability and civil unrest; regulatory or other changes in the local electricity market; and breach or repudiation of important contractual undertakings by governmental entities and expropriation and confiscation of assets and facilities for less than fair market value.

Government policies providing incentives for renewable energy could change at any time.

Development of new renewable energy sources and the overall growth of the renewable energy industry has generally been supported by state or provincial, national, supranational and international policies. Some of our projects benefit from such incentives.  The attractiveness of renewable energy to purchasers of renewable assets, as well as the economic return available to project sponsors, is often enhanced by such incentives. Particularly in light of political changes in certain jurisdictions – including the United States – there is a risk that regulations that provide incentives for renewable energy could change or expire in a manner that adversely impacts the market for renewables generally. Any such changes may impact the competitiveness of renewable energy generally and the economic value of certain of our projects in particular.

Brookfield Renewable may occasionally make purchases of securities, including the publicly listed securities of other companies, the value of which could decline due to factors beyond our control.

Brookfield may periodically recommend that Brookfield Renewable make investments in securities, including the publicly traded securities or debt of other companies. For example, in 2017, Brookfield Renewable, together with its institutional partners, acquired a 51% interest in TerraForm Power, a Nasdaq listed public company, giving Brookfield Renewable an approximate 16% interest in the publicly traded securities of TerraForm Power. Investments in securities are particularly subject to market volatility and market disruptions, changes in interest and currency exchange rates, equity prices and other economic and business factors beyond our control. In addition, at the time of any sales and settlements of securities, the price we ultimately realize will depend on demand and liquidity in the market at that time and may be materially lower than their current fair value.  While investments in securities are not expected to account for a large portion of Brookfield’s Renewable investments generally, a decline in the value of such securities could result in returns that are lower than anticipated or even in the investment being lost completely, which could mean that we are not be able to achieve growth in our distributions in line with our stated goals and the market value of our units may decline. 

Other Risks Related to BEP

BEP is a “foreign private issuer” under U.S. securities laws and is therefore subject to disclosure obligations different from requirements applicable to U.S. domestic registrants listed on the NYSE.

Although BEP is subject to the periodic reporting requirements of the Exchange Act, the periodic disclosure required of foreign private issuers under the Exchange Act is different from periodic disclosure required of U.S. domestic registrants. Therefore, there may be less publicly available information about

Page 32

BEP than is regularly published by or about other public companies in the U.S. BEP is exempt from certain other sections of the Exchange Act to which U.S. domestic issuers are subject, including the requirement to provide our LP Unitholders with information statements or proxy statements that comply with the Exchange Act. In addition, insiders and large LP Unitholders of BEP are not obligated to file reports under Section 16 of the Exchange Act, and certain corporate governance rules that are imposed by the NYSE will be inapplicable to BEP.

We may be subject to the risks commonly associated with a separation of economic interest from control within an organizational structure.

Our ownership and organizational structure is similar to structures whereby one company controls another company which in turn holds controlling interests in other companies; thereby, the company at the top of the chain may control the company at the bottom of the chain even if its effective equity position in the bottom company is less than a controlling interest. Brookfield is the sole shareholder of the Managing General Partner and, as a result of such ownership of the Managing General Partner, Brookfield will be able to control the appointment and removal of the Managing General Partner’s directors and, accordingly, will exercise substantial influence over us. In turn, we often have a majority controlling interest or a significant influence in our investments. Even though Brookfield has an effective economic interest in our business of approximately 60% as a result of its ownership of our LP Units and the Redeemable/Exchangeable partnership units, over time Brookfield may reduce this economic interest while still maintaining its controlling interest. This could lead to Brookfield using its control rights in a manner that conflicts with the economic interests of our other Unitholders. For example, despite the fact that we have the Conflicts Policy in place, which, among other things, sets out requirements for the review and approval of transactions between Brookfield Renewable and Brookfield, because Brookfield will be able to exert substantial influence over us, and, in turn, over our investments, there is a greater risk that we make investments on terms that disproportionately benefit Brookfield over Brookfield Renewable and its Unitholders.

We may be subject to the risks commonly associated with the incurrence of debt at multiple levels within an organizational structure.

Debt incurred at multiple levels within the chain of control could exacerbate the separation of economic interest from controlling interest at such levels, thereby creating an incentive to leverage us and our investments. Any such increase in debt would also make us more sensitive to declines in revenues, increases in expenses and interest rates, and adverse market conditions. The servicing of any such debt would also reduce the amount of funds available to pay distributions to us and ultimately to our Unitholders.

We could become regulated as an “investment company” under the Investment Company Act (and similar legislation in other jurisdictions) which would make it impractical for us to operate as contemplated.

The Investment Company Act (and similar legislation in other jurisdictions) provides certain protections to investors and imposes certain restrictions on companies that are registered as investment companies. BEP is not an “investment company” under the Investment Company Act and does not intend to become one. If BEP were to be deemed an investment companyunder the Investment Company Act, we might be required to materially restrict or limit the scope of our operations or plans as it would be impractical for us to operate as intended: certain agreements we have with Brookfield would be impaired, the type and amount of acquisitions that we would be able to make as a principal would be limited, and our business, financial condition and results of operations would be materially adversely affected. We would also be limited in the types of acquisitions that we might make, and we might need to modify our organizational structure or dispose of assets of which we would not otherwise dispose. Accordingly, we would be required to take extraordinary steps to address the situation, such as the amendment or termination of our Master Services Agreement, the restructuring of BEP and the Holding Entities, the amendment of the Amended and Restated Limited Partnership Agreement of BEP or the termination of BEP, any of which could materially adversely affect the value of our Units. In addition, if BEP were deemed to be an investment company under the Investment Company Act, it would be taxable as a corporation for U.S. federal income tax purposes, which could materially adversely affect the value of our Units. 

Page 33

Our failure to maintain effective internal controls could have a material adverse effect on our business and the price of our Units.

Pursuant to Section 404 of the Sarbanes-Oxley Act, our management has delivered a report that assesses the effectiveness of our internal controls over financial reporting (in which they concluded that these internal controls are effective) and our independent registered public accounting firm has delivered an attestation report on our management’s assessment of, and the operating effectiveness of, our internal controls over financial reporting in conjunction with their opinion on our audited consolidated financial statements. Failing to maintain adequate internal controls over financial reporting or to implement required, new or improved controls, or difficulties encountered in their implementation, could cause us to report material weaknesses in our internal controls over financial reporting and could result in a more than remote possibility of errors or misstatements in our consolidated financial statements that would be material. If we or our independent registered public accounting firm were to conclude that our internal controls over financial reporting were not effective, investors could lose confidence in our reported financial information and the price of our Units could decline. Our failure to achieve and maintain effective internal controls could have a material adverse effect on our business, our access to the capital markets and investors’ perception of us. In addition, material weaknesses in our internal controls could require significant expense and management time to remediate.

Risks Related to Our Relationship with Brookfield

Brookfield exercises substantial influence over Brookfield Renewable and we are highly dependent on the Service Provider.

A subsidiary of Brookfield Asset Management is the sole shareholder of the Managing General Partner. As a result of its ownership of the Managing General Partner, Brookfield is able to control the appointment and removal of the Managing General Partner’s directors and, accordingly, exercise substantial influence over Brookfield Renewable. In addition, BEP holds its interest in the Operating Entities indirectly through BRELP and will hold any future acquisitions indirectly through BRELP, the general partner of which is indirectly owned by Brookfield. As BEP’s only substantial asset is the limited partnership interests that it holds in BRELP, except future rights under the Voting Agreement, BEP does not have a right to participate directly in the management or activities of BRELP or the Holding Entities, including with respect to the making of decisions (although it has the right to remove and replace the BRELP GP LP).

BEP and BRELP depend on the management and administration services provided by or under the direction of the Service Provider under our Master Services Agreement. Brookfield personnel and support staff that provide services to us under our Master Services Agreement are not required to have as their primary responsibility the management and administration of BEP or BRELP or to act exclusively for either of us and our Master Services Agreement does not require any specific individuals to be provided by Brookfield to BEP. Failing to effectively manage our current operations or to implement our strategy could have a material adverse effect on our business, financial condition and results of operations. Our Master Services Agreement continues in perpetuity, until terminated in accordance with its terms.

The departure of some or all of Brookfield’s professionals could prevent us from achieving our objectives.

We depend on the diligence, skill and business contacts of Brookfield’s professionals and the information and opportunities they generate during the normal course of their activities. Our future success will depend on the continued service of these individuals, who are not obligated to remain employed with Brookfield. Brookfield has experienced departures of key professionals in the past and may experience departures again in the future, and we cannot predict the impact that any such departures will have on our ability to achieve our objectives. The departure of a significant number of Brookfield’s professionals for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on our ability to achieve our objectives. The Amended and Restated Limited Partnership Agreement of BEP and our Master Services Agreement do not require Brookfield to maintain the employment of any of its professionals or to cause any particular professionals to provide services to us or on our behalf.

Page 34

The role and ownership of Brookfield may change.

Our arrangements with Brookfield do not require Brookfield to maintain any ownership level in BEP or in BRELP. Accordingly, the Managing General Partner may transfer its general partnership interest to a third party, including in a merger or consolidation or in a transfer of all or substantially all of its assets, without the consent of our Unitholders provided the transferee is an affiliate of the BRELP General Partner. In addition, Brookfield may sell or transfer all or part of its interests in the Service Provider or in the Managing General Partner, in each case, without the approval of our Unitholders. If a new owner were to acquire ownership of the Managing General Partner and to appoint new directors or officers of its own choosing, it would be able to exercise substantial influence over Brookfield Renewable’s policies and procedures and exercise substantial influence over our management and the types of acquisitions that we make. Such changes could result in Brookfield Renewable’s capital being used to make acquisitions in which Brookfield has no involvement or to make acquisitions that are substantially different from those targeted by our current growth strategy. Additionally, BEP cannot predict with any certainty the effect that any transfer in the ownership of the Managing General Partner would have on the trading price of our Units or Brookfield Renewable’s ability to raise capital or make investments in the future, because such matters would depend to a large extent on the identity of the new owner and the new owner’s intentions with regard to BEP. As a result, the future of BEP would be uncertain and Brookfield Renewable’s business, financial condition and results of operations may suffer.

Brookfield is not necessarily required to act in the best interests of the Service Recipients, Brookfield Renewable or our Unitholders.

Our Master Services Agreement and our other arrangements with Brookfield do not impose any duty on the Service Provider to act in the best interest of the Service Recipients, and the Service Provider is not prohibited from engaging in other business activities that compete with the Service Recipients. Additionally, the Managing General Partner, the general partner of BRELP, the Service Provider and their affiliates will have access to material confidential information. Although some of these entities will be subject to confidentiality obligations pursuant to confidentiality agreements or pursuant to implied duties of confidence, none of the Amended and Restated Limited Partnership Agreement of BEP, the Amended and Restated Limited Partnership Agreement of BRELP nor our Master Services Agreement contains general confidentiality provisions. See Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Our Master Services Agreement and our other arrangements with Brookfield do not impose on Brookfield any fiduciary duties to act in the best interests of our Unitholders.

Our Master Services Agreement and our other arrangements with Brookfield do not impose on Brookfield any duty (statutory or otherwise) to act in the best interests of the Service Recipients, nor do they impose other duties that are fiduciary in nature. As a result, the Managing General Partner, a wholly-owned subsidiary of Brookfield Asset Management, in its capacity as our general partner, will have sole authority to enforce the terms of such agreements and to consent to any waiver, modification or amendment of their provisions in accordance with our Conflicts Policy.

The Bermuda Limited Partnership Act 1883, under which BEP and BRELP were established, does not impose statutory fiduciary duties on a general partner of a limited partnership in the same manner that corporate statutes, such as the Canada Business Corporations Act and the Delaware Revised Uniform Limited Partnership Act, impose fiduciary duties on directors of a corporation. In general, under applicable Bermudian legislation, a general partner has certain limited duties to its limited partners, such as the duty to render accounts, account for private profits and not compete with the partnership in business. In addition, Bermuda common law recognizes that a general partner owes a duty of utmost good faith to its limited partners. These duties are, in most respects, similar to duties imposed on a general partner of a limited partnership under U.S. and Canadian law. However, to the extent that the Managing General Partner and BRELP GP LP owe any fiduciary duties to Brookfield Renewable or our Unitholders, these duties have been modified pursuant to the Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP as a matter of contract law. We have been advised by Bermuda counsel that such modifications are not prohibited under Bermuda law, subject to typical qualifications as to enforceability of contractual provisions, such as the application of general equitable principles. This is similar to Delaware law which expressly permits

Page 35

modifications to the fiduciary duties owed to partners, other than an implied contractual covenant of good faith and fair dealing.

The Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP contain various provisions that modify the fiduciary duties that might otherwise be owed to Brookfield Renewable or our Unitholders, including when conflicts of interest arise. For example, the agreements provide that the Managing General Partner, the BRELP General Partner and their affiliates do not have any obligation under the Amended and Restated Limited Partnership Agreements of BEP or the Amended and Restated Limited Partnership Agreement of BRELP, or as a result of any duties stated or implied by law or equity, including fiduciary duties, to present business or investment opportunities to BEP, BRELP, any Holding Entity or any other holding entity established by us. They also allow affiliates of the Managing General Partner and BRELP General Partner to engage in activities that may compete with us or our activities. Further, when resolving conflicts of interest, neither the Amended and Restated Limited Partnership Agreement of BEP nor the Amended and Restated Limited Partnership Agreement of BRELP impose limitations on the discretion of the independent directors or the factors which they may consider in resolving any such conflicts. The independent directors of our Managing General Partner can therefore take into account the interests of third parties, including Brookfield, when resolving conflicts of interest. These modifications to the fiduciary duties are detrimental to our Unitholders because they restrict the remedies available for actions that might otherwise constitute a breach of fiduciary duty and permit conflicts of interest to be resolved in a manner that is not in the best interests of Brookfield Renewable or the best interests of our Unitholders. See Item 7.B. “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Our organizational and ownership structure may create significant conflicts of interest that may be resolved in a manner that is not in the best interests of Brookfield Renewable or the best interests of our Unitholders.

Our organizational and ownership structure involves a number of relationships that may give rise to conflicts of interest between Brookfield Renewable and our Unitholders, on the one hand, and Brookfield, on the other hand. In certain instances, the interests of Brookfield may differ from the interests of Brookfield Renewable or our Unitholders, including with respect to the types of acquisitions made, the timing and amount of distributions by BEP, the reinvestment of returns generated by our operations, the use of leverage when making acquisitions and the appointment of outside advisers and service providers, including as a result of the reasons described under Item 7.B “Related Party Transactions”.

In addition, the Service Provider, an affiliate of Brookfield, will provide management services to us pursuant to our Master Services Agreement as consideration for an annual Base Management Fee.  BRELP GP LP will also receive incentive distributions based on the amount by which quarterly distributions on the limited partnership units of BRELP exceed specified target levels as set forth in the Amended and Restated Limited Partnership Agreement of BRELP. For a further explanation of the Base Management Fee and incentive distributions, see Item 6.A “Directors and Senior Management — Our Master Services Agreement — Management Fee” and Item 7.B “Related Party Transactions — Incentive Distributions”.

This relationship may give rise to conflicts of interest between us and our Unitholders, on the one hand, and Brookfield, on the other, as Brookfield’s interests may differ from the interests of Brookfield Renewable and our Unitholders. The Managing General Partner, the sole shareholder of which is Brookfield, has sole authority to determine whether we will make distributions, the amount of distributions on our Units and the timing of these distributions. The arrangements we have with Brookfield may create an incentive for Brookfield to take actions which would have the effect of increasing distributions on our LP Units and fees payable to it, which may be to the detriment of Brookfield Renewable and our Unitholders. For example, because the Base Management Fee is calculated based on the Total Capitalization Value it may create an incentive for Brookfield to increase or maintain the Total Capitalization Value over the near-term when other actions may be more favorable to us or our Unitholders. Similarly, Brookfield may take actions to increase our distributions on our LP Units in order to ensure Brookfield is paid incentive distributions in the near-term when other investments or actions may be more favorable to us or our Unitholders. Also, through Brookfield’s ownership of our LP Units and the Redeemable/Exchangeable partnership units, it currently has an effective economic interest in our

Page 36

business of approximately 60% and therefore may be motivated to increase distributions payable to our LP Unitholders and thereby to Brookfield.

The Managing General Partner may be unable or unwilling to terminate our Master Services Agreement.

Our Master Services Agreement provides that the Service Recipients may terminate the agreement only if: the Service Provider defaults in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm to the Service Recipients and the default continues unremedied for a period of 60 days after written notice of the breach is given to the Service Provider; the Service Provider engages in any act of fraud, misappropriation of funds or embezzlement against any Service Recipient that results in material harm to us; the Service Provider is grossly negligent in the performance of its duties under the agreement and such negligence results in material harm to the Service Recipients; or upon the happening of certain events relating to the bankruptcy or insolvency of the Service Provider. The Managing General Partner cannot terminate the agreement for any other reason, including if the Service Provider or Brookfield experiences a change of control or due solely to the poor performance or under-performance of Brookfield Renewable’s operations or assets, and the agreement continues in perpetuity, until terminated in accordance with its terms. In addition, because the Managing General Partner is an affiliate of Brookfield, it may be unwilling to terminate our Master Services Agreement, even in the case of a default. If the Service Provider’s performance does not meet the expectations of investors, and the Managing General Partner is unable or unwilling to terminate our Master Services Agreement, the market price of our Units could suffer. Furthermore, the termination of our Master Services Agreement would terminate BEP’s rights under the Relationship Agreement and the Licensing Agreement. See Item 7.B “Related Party Transactions — Relationship Agreement” and Item 7.B “Related Party Transactions — Licensing Agreement”.

The liability of the Service Provider is limited under our arrangements with it and we have agreed to indemnify the Service Provider against claims that it may face in connection with such arrangements, which may lead it to assume greater risks when making decisions relating to us than it otherwise would if acting solely for its own account.

Under our Master Services Agreement, the Service Provider has not assumed any responsibility other than to provide or arrange for the provision of the services described in our Master Services Agreement in good faith and will not be responsible for any action that the Managing General Partner takes in following or declining to follow its advice or recommendations. In addition, under the Amended and Restated Limited Partnership Agreement of BEP, the liability of the Managing General Partner and its affiliates, including the Service Provider, is limited to the fullest extent permitted by law to conduct involving gross negligence, bad faith, fraud or willful misconduct or, in the case of a criminal matter, action that was known to have been unlawful. The liability of the Service Provider under our Master Services Agreement is similarly limited. In addition, BEP has agreed to indemnify the Service Provider to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses incurred by an indemnified person or threatened in connection with our operations, investments and activities or in respect of or arising from our Master Services Agreement or the services provided by the Service Provider, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the conduct in respect of which such persons have liability as described above. These protections may result in the Service Provider tolerating greater risks when making decisions than otherwise would be the case, including when determining whether to use leverage in connection with acquisitions. The indemnification arrangements to which the Service Provider is a party may also give rise to legal claims for indemnification that are adverse to Brookfield Renewable and Unitholders.

Risks Related to Our Units

We may not be able to continue paying comparable or growing cash distributions to our Unitholders in the future.

The amount of cash we can distribute to our Unitholders depends upon the amount of cash we receive from BRELP and, indirectly, the Holding Entities and the Operating Entities. The amount of cash BRELP, the Holding Entities and the Operating Entities generate will fluctuate from quarter to quarter and

Page 37

will depend upon, among other things, the weather in the jurisdictions in which they operate, the level of their operating costs, and prevailing economic conditions. In addition, the actual amount of cash we will have available for distribution will also depend on other factors, such as: the level of costs related to litigation and regulatory compliance matters; the cost of acquisitions, if any; the ability of our assets to achieve long-term average generation; fluctuations in our working capital needs; rising interest rates and other factors which could increase our debt service requirements; our ability to borrow under our credit facilities; our ability to access capital markets; restrictions on distributions contained in our debt agreements; and the amount, if any, of cash reserves established by our Managing General Partner in its discretion for the proper conduct of our business. As a result of all these factors, we cannot guarantee that we will have sufficient available cash to pay a specific level of cash distributions to our Unitholders. Furthermore, our Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon the cash flow of BRELP, the Holding Entities and the Operating Entities, and is not solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions on our Units during periods when we record net losses.

We may need additional funds in the future and BEP may issue additional LP Units or, Preferred Units in lieu of incurring indebtedness which may dilute existing holders of our LP Units or BEP may issue securities that have rights and privileges that are more favorable than the rights and privileges accorded to our Unitholders.

Under the Amended and Restated Limited Partnership Agreement of BEP, BEP may issue additional partnership securities, including LP Units, Preferred Units and options, rights, warrants and appreciation rights relating to partnership securities for any purpose and for such consideration and on such terms and conditions as the Managing General Partner may determine. The Managing General Partner’s board of directors will be able to determine the class, designations, preferences, rights, powers and duties of any additional partnership securities, including any rights to share in BEP’s profits, losses and distributions, any rights to receive partnership assets upon a dissolution or liquidation of BEP and any redemption, conversion and exchange rights. The Managing General Partner may use such authority to issue additional LP Units or Preferred Units, which could dilute holders of our LP Units, or to issue securities with rights and privileges that are more favorable than those of our LP Units or Preferred Units. Holders of Units do not have any pre-emptive right or any right to consent to or otherwise approve the issuance of any such securities or the terms on which any such securities may be issued.

Our Unitholders do not have a right to vote on BEP matters or to take part in the management of BEP.

Under the Amended and Restated Limited Partnership Agreement of BEP, our Unitholders are not entitled to vote on matters relating to BEP, such as acquisitions, dispositions or financing, or to participate in the management or control of BEP. In particular, our Unitholders do not have the right to remove the Managing General Partner, to cause the Managing General Partner to withdraw from BEP, to cause a new general partner to be admitted to BEP, to appoint new directors to the Managing General Partner’s board of directors, to remove existing directors from the Managing General Partner’s board of directors or to prevent a change of control of the Managing General Partner. In addition, except for certain fundamental matters prescribed by applicable laws, our LP Unitholders’ and Preferred Unitholders’ consent rights apply only with respect to certain amendments to the Amended and Restated Limited Partnership Agreement of BEP. As a result, unlike holders of common shares of a corporation, our LP Unitholders are not able to influence the direction of BEP, including its policies and procedures, or to cause a change in its management, even if they are unsatisfied with the performance of BEP. Consequently, our LP Unitholders may be deprived of an opportunity to receive a premium for their LP Units in the future through a sale of BEP and the trading price of our LP Units may be adversely affected by the absence or a reduction of a takeover premium in the trading price. LP Unitholders and Preferred Unitholders only have a right to vote under limited circumstances as described in Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”. 

The market price of our Units may be volatile.

The market price of our Units may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect the price of our Units include: general market and

Page 38

economic conditions, including disruptions, downgrades, credit events and perceived problems in the credit markets; actual or anticipated variations in our quarterly operating results or distributions on our LP Units; changes in our investments or asset composition; write-downs or perceived credit or liquidity issues affecting our assets; market perception of BEP, our business and our assets; our level of indebtedness and/or adverse market reaction to any indebtedness we incur in the future; our ability to raise capital on favorable terms; loss of any major funding source; the termination of our Master Services Agreement or additions or departures of our or Brookfield’s key personnel; changes in market valuations of similar renewable power companies or renewable power markets generally; speculation in the press or investment community regarding us or Brookfield; and changes in U.S. tax laws that make it impractical or impossible to continue to be taxable as a partnership for U.S. federal income tax purposes.

Securities markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies or partnerships. Any broad market fluctuations may adversely affect the trading price of our Units.

Non-U.S. Holders may be subject to foreign currency risk associated with BEP’s distributions.

A significant number of BEP’s LP Unitholders may reside in countries where the U.S. dollar is not the functional currency. Our distributions are denominated in U.S. dollars but may be settled in the local currency of the LP Unitholder receiving the distribution. For each Non-U.S. Holder, the value received in the local currency from the distribution will be determined based on the exchange rate between the U.S. dollar and the applicable local currency at such time. As such, if the U.S. dollar depreciates significantly against the local currency of the Non-U.S. Holder, the value received by such LP Unitholder in its local currency will be adversely affected.

Investors in our Units may find it difficult or impossible to enforce service of process and enforcement of judgments against us and directors and officers of the Managing General Partner and the Service Provider.

We were established under the laws of Bermuda, and many of our subsidiaries are organized in jurisdictions outside of Canada and the U.S. In addition, our executive officers and the experts identified in this Form 20-F are located outside of the U.S. and some are also located outside of Canada. Certain of the directors and officers of the Managing General Partner and the Service Provider reside outside of Canada and the U.S. A substantial portion of our assets are, and the assets of the directors and officers of the Managing General Partner and the Service Provider and the experts identified in this Form 20-F may be, located outside of Canada and the U.S. It may not be possible for investors to effect service of process within the U.S. or within Canada upon the directors and officers of the Managing General Partner and the Service Provider. It may also not be possible to enforce a judgment against us, the experts identified in this Form 20-F or the directors and officers of the Managing General Partner and the Service Provider, if such judgment was obtained in Canadian or U.S. courts predicated upon the civil liability provisions of securities laws in Canada or the U.S., as applicable.

We rely on BRELP and, indirectly, the Holding Entities and the Operating Entities to provide us with the funds necessary to pay distributions and meet our financial obligations.

BEP’s sole direct investment is its limited partnership interest and preferred limited partnership interest in BRELP, which owns all of the common shares or equity interests, as applicable, of the Holding Entities, through which we hold all of our interests in the Operating Entities. We have no independent means of generating revenue. As a result, we depend on distributions and other payments from BRELP and, indirectly, the Holding Entities and the Operating Entities to provide us with the funds necessary to pay distributions on our Units and to meet our financial obligations. BRELP, the Holding Entities and the Operating Entities are legally distinct from BEP and they will generally be required to service their debt obligations before making distributions to us or their parent entity, as applicable, thereby reducing the amount of our cash flow available to pay distributions on our Units, fund working capital and satisfy other needs. Any other entities through which we may conduct operations in the future will also be legally distinct from BEP and may be restricted in their ability to pay dividends and distributions or otherwise make funds available to us under certain conditions.

We anticipate that the only distributions we will receive in respect of our limited partnership interests in BRELP will consist of amounts that are intended to assist us in making distributions to our LP

Page 39

Unitholders in accordance with our distribution policy, to our Preferred Unitholders in accordance with the terms of our Preferred Units and to allow us to pay expenses as they become due. See Item 4.B “Business Overview – Our LP Unit Distribution Policy”.

Our payout ratio has exceeded our long-term target and, in some periods, our Funds From Operations. If this were to continue it could impact our ability to maintain or grow our distributions to Unitholders.

BEP’s payout ratio is a measure of its ability to make cash distributions to Unitholders. BEP targets a long-term payout ratio of 70% of Funds From Operations. From time to time BEP’s payout ratio may exceed 100%, during periods of lower generation or lower merchant power prices or combination thereof. Because our business is primarily dependent on generation conditions and merchant power prices, as well as other factors beyond our control, it is possible that our payout ratio may remain above 100% for a sustained period. If this were to occur, it could impact our ability to maintain or grow our distributions to Unitholders in line with our stated targets. 

Risks Related to Taxation

General

Changes in tax law and practice may have a material adverse effect on the operations of BEP, the Holding Entities, and the Operating Entities and, as a consequence, the value of BEP’s assets and the net amount of distributions payable to Unitholders.

The Brookfield Renewable structure, including the structure of the Holding Entities and the Operating Entities, is based on prevailing taxation law and practice in the local jurisdictions in which Brookfield Renewable operates. These jurisdictions include Canada, the U.S., Brazil, the Republic of Ireland, the United Kingdom, Portugal and Colombia. Any change in tax legislation (including in relation to taxation rates) and practice in these jurisdictions or provinces, states or municipalities within them, could adversely affect these entities, as well as the net amount of distributions payable to Unitholders. Taxes and other constraints that would apply to the Brookfield Renewable entities in such jurisdictions may not apply to local institutions or other parties, and such parties may therefore have a significantly lower effective cost of capital and a corresponding competitive advantage in pursuing such acquisitions.

BEP’s ability to make distributions depends on it receiving sufficient cash distributions from its underlying operations, and BEP cannot assure Unitholders that it will be able to make cash distributions to them in amounts that are sufficient to fund their tax liabilities, in which case certain Unitholders may be required to pay income taxes on their share of BEP’s income even though they have not received sufficient cash distributions from BEP to do so.

The Holding Entities and Operating Entities of BEP may be subject to local taxes in each of the relevant territories and jurisdictions in which they operate, including taxes on income, profits or gains and withholding taxes. As a result, BEP’s cash available for distribution is indirectly reduced by such taxes, and the post-tax return to Unitholders is similarly reduced by such taxes. BEP intends for future acquisitions to be assessed on a case-by-case basis and, where possible and commercially viable, structured so as to minimize any adverse tax consequences to Unitholders as a result of making such acquisitions.

In general, an LP Unitholder that is subject to income tax in Canada or the U.S. or a Preferred Unitholder that is subject to income tax in Canada, must include in income its allocable share of BEP’s items of income, gain, loss, and deduction (including, so long as it is treated as a partnership for tax purposes, BEP’s allocable share of those items of BRELP) for each of BEP’s fiscal years ending with or within such Unitholder’s tax year. See Item 10.E “Taxation — Certain Material Canadian Federal Income Tax Considerations” and “Taxation — Material U.S. Federal Income Tax Considerations”. However, the cash distributed to a Unitholder may not be sufficient to pay the full amount of such Unitholder’s tax liability in respect of its investment in BEP, because each Unitholder’s tax liability depends on such holder’s particular tax situation. If BEP is unable to distribute cash in amounts that are sufficient to fund our Unitholders’ tax liabilities, each of our Unitholders will still be required to pay income taxes on its share of BEP’s taxable income.

Page 40

As a result of holding Units, Unitholders may be subject to U.S. state, local or non-U.S. taxes and return filing obligations in jurisdictions in which they are not resident for tax purposes or otherwise not subject to tax.

Unitholders may be subject to U.S. state, local, and non-U.S. taxes, including unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which BEP entities do business or own property now or in the future, even if Unitholders do not reside in any of those jurisdictions. Unitholders may be required to file income tax returns and pay income taxes in some or all of these jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with these requirements. Although BEP will attempt, to the extent reasonably practicable, to structure BEP operations and investments so as to minimize income tax filing obligations by Unitholders in such jurisdictions, there may be circumstances in which BEP is unable to do so. It is the responsibility of each Unitholder to file all U.S. federal, state, local, and non-U.S. tax returns that may be required of such Unitholder.

Unitholders may be exposed to transfer pricing risks.

To the extent that BEP, BRELP, the Holding Entities or the Operating Entities enter into transactions or arrangements with parties with whom they do not deal at arm’s length, including Brookfield, pursuant to the applicable law relating to transfer pricing, the relevant tax authorities may seek to adjust the quantum or nature of the amounts received or paid by such entities if they consider that the terms and conditions of such transactions or arrangements differ from those that would have been made between persons dealing at arm’s length and could impose penalties for failing to comply with applicable law relating to transfer pricing. This could result in more tax (and penalties and interest) being paid by such entities, and therefore the return to investors could be reduced. For Canadian tax purposes, a transfer pricing adjustment may in certain circumstances result in additional income being allocated to a Unitholder with no corresponding cash distribution or in a dividend being deemed to be paid by a Canadian resident to a non-arm’s length non-resident, which deemed dividend is subject to Canadian withholding tax.

The Managing General Partner and the BRELP General Partner believe the fees charged by or paid to non-arm’s length persons are consistent with applicable law relating to transfer pricing, however, no assurance can be given in this regard.

The IRS or the CRA may not agree with certain assumptions and conventions that BEP uses in order to comply with applicable U.S. and Canadian federal income tax laws or that BEP uses to report income, gain, loss, deduction, and credit to Unitholders.

BEP will apply certain assumptions and conventions in order to comply with applicable tax laws and to report income, gain, deduction, loss, and credit to a Unitholder in a manner that reflects such Unitholder’s beneficial ownership of partnership items, taking into account variation in ownership interests during each taxable year because of trading activity. However, these assumptions and conventions may not be in compliance with all aspects of the applicable tax requirements. A successful IRS or CRA challenge to such assumptions or conventions could adversely affect the amount of tax benefits available to Unitholders and could require that items of income, gain, deduction, loss, or credit be adjusted, reallocated or disallowed in a manner that adversely affects Unitholders. See Item 10.E “Taxation”.

United States

If either BEP or BRELP were to be treated as a corporation for U.S. federal income tax purposes, the value of LP Units might be adversely affected.

The value of LP Units to LP Unitholders will depend in part on the treatment of BEP and BRELP as partnerships for U.S. federal income tax purposes. However, in order for BEP to be treated as a partnership for U.S. federal income tax purposes, under present law, 90% or more of BEP’s gross income for every taxable year must consist of qualifying income, as defined in Section 7704 of the U.S. Internal Revenue Code, and the partnership must not be required to register, if it were a U.S. corporation, as an investment company under the Investment Company Act and related rules. Although the Managing General Partner intends to manage BEP’s affairs so that BEP will not need to be registered as an investment company if it were a U.S. corporation and so that it will meet the 90% test described above in

Page 41

each taxable year, there can be no assurance that BEP will meet these requirements, or current law may change so as to cause, in either event, BEP to be treated as a corporation for U.S. federal income tax purposes. If BEP (or BRELP) were treated as a corporation for U.S. federal income tax purposes, adverse tax consequences could result for LP Unitholders and BEP (or BRELP, as applicable), as described in greater detail in Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations — Partnership Status of BEP and BRELP”.

BEP may be subject to U.S. backup withholding tax if any LP Unitholder fails to comply with U.S. federal tax reporting rules, and such excess withholding tax cost will be an expense borne by BEP and, therefore, by all of our LP Unitholders on a pro rata basis.

BEP may become subject to U.S. backup withholding tax with respect to any LP Unitholder who fails to timely provide BEP (or the applicable intermediary) with an IRS Form W-9 or IRS Form W-8, as applicable. See Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations — Administrative Matters — Backup Withholding”. To the extent that any LP Unitholder fails to timely provide the applicable form (or such form is not properly completed), BEP might treat such U.S. backup withholding taxes as an expense, which would be borne indirectly by all LP Unitholders on a pro rata basis (including LP Unitholders that fully comply with their U.S. tax reporting obligations).

Tax-exempt organizations may face certain adverse U.S. tax consequences from owning LP Units.

The Managing General Partner and the BRELP General Partner intend to use commercially reasonable efforts to structure the activities of BEP and BRELP, respectively, to avoid generating income connected with the conduct of a trade or business (which income generally would constitute “unrelated business taxable income” (“UBTI”) to the extent allocated to a tax-exempt organization). However, no assurance can be provided that neither BEP nor BRELP will generate UBTI in the future. In particular, UBTI includes income attributable to debt-financed property, and neither BEP nor BRELP is prohibited from financing the acquisition of property with debt. In addition, even if indebtedness were not used by BEP or BRELP to acquire property but were instead used to fund distributions to LP Unitholders, if a tax-exempt organization were to use such proceeds to make an investment outside BEP, the IRS could assert that such investment constituted debt-financed property to such LP Unitholder. The potential for income to be characterized as UBTI could make LP Units an unsuitable investment for a tax-exempt organization. Each tax-exempt organization should consult an independent tax adviser to determine the U.S. federal income tax consequences with respect to an investment in LP Units.

If BEP were engaged in a U.S. trade or business, non-U.S. persons would face certain adverse U.S. tax consequences from owning LP Units.

The Managing General Partner and the BRELP General Partner intend to use commercially reasonable efforts to structure the activities of BEP and BRELP, respectively, to avoid generating income treated as effectively connected with a U.S. trade or business, including effectively connected income attributable to the sale of a “United States real property interest”, as defined in the U.S. Internal Revenue Code. If, contrary to the Managing General Partner’s expectations, BEP is considered to be engaged in a U.S. trade or business or realizes gain from the sale or other disposition of a U.S. real property interest, non-U.S. Unitholders generally would be required to file U.S. federal income tax returns and could be subject to U.S. federal withholding tax at the highest marginal U.S. federal income tax rates applicable to ordinary income. Under the Tax Cuts and Jobs Act, if, contrary to expectation, BEP were engaged in a U.S. trade or business, then gain or loss from the sale of LP Units by a Non-U.S. Holder would be treated as effectively connected with such trade or business to the extent that such Non-U.S. Holder would have had effectively connected gain or loss had BEP sold all of its assets at their fair market value as of the date of such sale. In such case, any such effectively connected gain generally would be taxable at the regular graduated rates, and the amount realized from such sale generally would be subject to a 10% U.S. federal withholding tax. Each Non-U.S. Holder should consult an independent tax adviser to determine the U.S. federal income tax consequences with respect to an investment in LP Units.

To meet U.S. federal income tax and other objectives, BEP and BRELP may invest through U.S. and non-U.S. Holding Entities that are treated as corporations for U.S. federal income tax purposes, and such Holding Entities may be subject to corporate income tax.

Page 42

To meet U.S. federal income tax and other objectives, BEP and BRELP may invest through U.S. and non-U.S. Holding Entities that are treated as corporations for U.S. federal income tax purposes, and such Holding Entities may be subject to corporate income tax. Consequently, items of income, gain, loss, deduction, or credit realized in the first instance by the Operating Entities will not flow, for U.S. federal income tax purposes, directly to BRELP, BEP, or LP Unitholders, and any such income or gain may be subject to a corporate income tax, in the U.S. or other jurisdictions, at the level of the Holding Entity. Any such additional taxes may adversely affect BEP’s ability to maximize its cash flow.

LP Unitholders taxable in the U.S. may be viewed as holding an indirect interest in an entity classified as a PFIC for U.S. federal income tax purposes.

U.S. Holders may face adverse U.S. tax consequences arising from the ownership of a direct or indirect interest in a PFIC. Based on the organizational structure of BEP, as well as BEP’s expected income and assets, the Managing General Partner and the BRELP General Partner currently believe that a U.S. Holder is unlikely to be regarded as owning an interest in a PFIC solely by reason of owning LP Units during the taxable year ending December 31, 2018. However, there can be no assurance that an existing BEP entity or a future entity in which BEP acquires an interest will not be classified as a PFIC with respect to a U.S. Holder, because PFIC status is a factual determination that depends on the assets and income of a given entity and must be made on an annual basis. In general, gain realized by a U.S. Holder from the sale of stock of a PFIC is subject to tax at ordinary income rates, and an interest charge generally applies. Alternatively, a U.S. Holder that makes certain elections with respect to a direct or indirect interest in a PFIC may be required to recognize taxable income prior to the receipt of cash relating to such income. The adverse consequences of owning an interest in a PFIC, as well as certain tax elections for mitigating these adverse consequences, are described in greater detail in Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations — Consequences to U.S. Holders — Passive Foreign Investment Companies”. Each U.S. Holder should consult an independent tax adviser regarding the implication of the PFIC rules for an investment in LP Units.

Tax gain or loss from the disposition of LP Units could be more or less than expected.

Upon the sale of LP Units, a U.S. Holder generally will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and such holder’s adjusted tax basis in those LP Units. Prior distributions to a U.S. Holder in excess of the total net taxable income allocated to such holder will have decreased such holder’s tax basis in its LP Units. Therefore, such excess distributions will increase a U.S. Holder’s taxable gain or decrease such holder’s taxable loss when our LP Units are sold, and may result in a taxable gain even if the sale price is less than the original cost. A portion of the amount realized, whether or not representing gain, could be ordinary income to such U.S. Holder.

The Brookfield Renewable structure involves complex provisions of U.S. federal income tax law for which no clear precedent or authority may be available. The tax characterization of the Brookfield Renewable structure is also subject to potential legislative, judicial, or administrative change and differing interpretations, possibly on a retroactive basis.

The U.S. federal income tax treatment of LP Unitholders depends in some instances on determinations of fact and interpretations of complex provisions of U.S. federal income tax law for which no clear precedent or authority may be available. LP Unitholders should be aware that the U.S. federal income tax rules, particularly those applicable to partnerships, are constantly under review by the Congressional tax-writing committees and other persons involved in the legislative process, the IRS, the U.S. Treasury Department and the courts, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to regulations and other modifications and interpretations, any of which could adversely affect the value of LP Units and be effective on a retroactive basis. For example, changes to the U.S. federal tax laws and interpretations thereof could make it more difficult or impossible for BEP to be treated as a partnership that is not taxable as a corporation for U.S. federal income tax purposes, change the character or treatment of portions of BEP’s income, reduce the net amount of distributions available to LP Unitholders, or otherwise affect the tax considerations of owning LP Units. In addition, BEP’s organizational documents and agreements permit the Managing General Partner to modify the limited partnership agreement of BEP from time to time, without the consent of our LP

Page 43

Unitholders, to address such changes. In some circumstances, such revisions could have a material adverse impact on some or all LP Unitholders.

BEP’s delivery of required tax information for a taxable year may be subject to delay, which could require an LP Unitholder who is a U.S. taxpayer to request an extension of the due date for such LP Unitholder’s income tax return.

BEP has agreed to use commercially reasonable efforts to provide U.S. tax information (including IRS Schedule K-1 information needed to determine an LP Unitholder’s allocable share of BEP’s income, gain, losses and deductions) no later than 90 days after the close of each calendar year. However, providing this U.S. tax information to LP Unitholders will be subject to delay in the event of, among other reasons, the late receipt of any necessary tax information from lower-tier entities. It is therefore possible that, in any taxable year, an LP Unitholder will need to apply for an extension of time to file such LP Unitholder’s tax returns. See Item 10.E “Taxation — Material U.S. Federal Income Tax Considerations — Administrative Matters — Information Returns and Audit Procedures”.

If the IRS makes an audit adjustment to BEP’s income tax returns, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from BEP, in which case cash available for distribution to LP Unitholders might be substantially reduced.

Under the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes an audit adjustment to BEP’s income tax returns, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from BEP instead of LP Unitholders (as under prior law). BEP may be permitted to elect to have the Managing General Partner and LP Unitholders take such audit adjustment into account in accordance with their interests in BEP during the taxable year under audit. However, there can be no assurance that BEP will choose to make such election or that it will be available in all circumstances. If BEP does not make the election, and it pays taxes, penalties, or interest as a result of an audit adjustment, then cash available for distribution to Unitholders might be substantially reduced. As a result, current LP Unitholders might bear some or all of the cost of the tax liability resulting from such audit adjustment, even if current LP Unitholders did not own LP Units during the taxable year under audit. The foregoing considerations also apply with respect to BEP’s interest in BRELP.

Under FATCA, certain payments made or received by BEP could be subject to a 30% federal withholding tax, unless certain requirements are met.

Under FATCA, a 30% withholding tax may apply to certain payments of U.S.-source income made to BEP, BRELP, the Holding Entities, or the Operating Entities, or by BEP to an LP Unitholder under certain circumstances, unless certain requirements are met, as described in greater detail in Item 10.E “Taxation – Material U.S. Federal Income Tax Considerations – Administrative Matters – Foreign Account Tax Compliance”. The 30% withholding tax may also apply to certain payments made on or after January 1, 2019 that are attributable to U.S. source income or that constitute gross proceeds from the disposition of property that could produce U.S. source dividends or interest. To ensure compliance with FATCA, information regarding certain LP Unitholders’ ownership of our LP Units may be reported to the U.S. Internal Revenue Service or to a non-U.S. governmental authority. Each of our LP Unitholders should consult an independent tax adviser regarding the consequences under FATCA of an investment in LP Units.

The effect of comprehensive U.S. tax reform legislation on Brookfield Renewable and Unitholders, whether adverse or favorable, is uncertain.

In December 2017, the U.S. President signed into law H.R. 1, “An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018” (informally titled the “Tax Cuts and Jobs Act”). Among a number of significant changes to the U.S. federal income tax laws, the Tax Cuts and Jobs Act reduces the marginal U.S. corporate income tax rate from 35% to 21%, limits the deduction for net interest expense, shifts the United States toward a modified territorial tax system, and imposes taxes to combat erosion of the U.S. federal income tax base. The effect of the Tax Cuts and Jobs Act on Brookfield Renewable and Unitholders, whether adverse or favorable, is uncertain, and may not become evident for some period of time. Unitholders are urged to consult an independent tax adviser regarding the implications of the Tax Cuts and Jobs Act for an investment in LP Units.

Page 44

Canada

The Canadian federal income tax consequences to Unitholders could be materially different in certain respects from those described in this Form 20-F if BEP or BRELP is a “specified investment flow-through partnership” or “SIFT partnership”, as defined in the Income Tax Act (Canada)  (together with the regulations thereunder, the “Tax Act”).

Under the rules in the Tax Act applicable to a “SIFT partnership” (the “SIFT Rules”), certain income and gains earned by a “SIFT partnership” will be subject to income tax at the partnership level at a rate similar to a corporation, and allocations of such income and gains to its partners will be taxed as a dividend from a “taxable Canadian corporation” (as defined in the Tax Act). In particular, a “SIFT partnership” will be required to pay a tax on the total of its income from businesses carried on in Canada, income from “non-portfolio properties” (as defined in the Tax Act) other than taxable dividends, and taxable capital gains from dispositions of “non-portfolio properties”. “Non-portfolio properties” include, among other things, equity interests or debt of corporations, trusts or partnerships that are resident in Canada, and of non-resident persons or partnerships the principal source of income of which is one or any combination of sources in Canada (other than a “portfolio investment entity”, as defined in the Tax Act), that are held by the “SIFT partnership” and have a fair market value that is greater than 10% of the equity value of such entity, or that have, together with debt or equity that the “SIFT partnership” holds of entities affiliated (within the meaning of the Tax Act) with such entity, an aggregate fair market value that is greater than 50% of the equity value of the “SIFT partnership”. The tax rate that is applied to the above mentioned sources of income and gains is set at a rate equal to the “net corporate income tax rate”, plus the “provincial SIFT tax rate” (each as defined in the Tax Act).

A partnership will be a “SIFT partnership” throughout a taxation year if at any time in the taxation year (i) it is a “Canadian resident partnership” (as defined in the Tax Act), (ii) “investments” (as defined in the Tax Act) in the partnership are listed or traded on a stock exchange or other public market, and (iii) it holds one or more “non-portfolio properties”. For these purposes, a partnership will be a “Canadian resident partnership” at a particular time if (a) it is a “Canadian partnership” (as defined in the Tax Act) at that time, (b) it would, if it were a corporation, be resident in Canada (including, for greater certainty, a partnership that has its central management and control located in Canada), or (c) it was formed under the laws of a Canadian province. A “Canadian partnership” for these purposes is a partnership all of whose members are resident in Canada or are partnerships that are “Canadian partnerships”.

Under the SIFT Rules, BEP and BRELP could each be a “SIFT partnership” if it is a “Canadian resident partnership”. However, BRELP would not be a “SIFT partnership” if BEP is a “SIFT partnership” regardless of whether BRELP is a “Canadian resident partnership” on the basis that BRELP would be an “excluded subsidiary entity” (as defined in the Tax Act).

BEP and BRELP will be a “Canadian resident partnership” if the central management and control of these partnerships is located in Canada. This determination is a question of fact and is expected to depend on where the Managing General Partner and the BRELP General Partner are located and exercise central management and control of the respective partnerships. The Managing General Partner and the BRELP General Partner will each take appropriate steps so that the central management and control of these entities is not located in Canada such that the SIFT Rules should not apply to BEP or BRELP at any relevant time. However, no assurance can be given in this regard. If BEP or BRELP is a “SIFT partnership”, the Canadian federal income tax consequences to our Unitholders could be materially different in certain respects from those described in Item 10.E. “Taxation – Certain Material Canadian Federal Income Tax Considerations”. In addition, there can be no assurance that the SIFT Rules will not be revised or amended in the future such that the SIFT Rules will apply.

If the subsidiaries that are corporations and that are not resident or deemed to be resident in Canada for purposes of the Tax Act (“Non-Resident Subsidiaries”) and that are “controlled foreign affiliates” (as defined in the Tax Act and referred to herein  as “CFAs”) in which BRELP directly invests earned income that is “foreign accrual property income” (as defined in the Tax Act and referred to herein  as “FAPI”), our Unitholders may be required to include amounts allocated from BEP in computing their income for Canadian federal income tax purposes even though there may be no corresponding cash distribution.

Page 45

Any Non-Resident Subsidiaries in which BRELP directly invests are expected to be CFAs of BRELP. If any CFA of BRELP or any direct or indirect subsidiary thereof that is itself a CFA of BRELP (an “Indirect CFA”) earns income that is characterized as FAPI in a particular taxation year of the CFA or Indirect CFA, the FAPI allocable to BRELP must be included in computing the income of BRELP for Canadian federal income tax purposes for the fiscal period of BRELP in which the taxation year of that CFA or Indirect CFA ends, whether or not BRELP actually receives a distribution of that FAPI. BEP will include its share of such FAPI of BRELP in computing its income for Canadian federal income tax purposes and Unitholders will be required to include their proportionate share of such FAPI allocated from BEP in computing their income for Canadian federal income tax purposes. As a result, Unitholders may be required to include amounts in their income for Canadian federal income tax purposes even though they have not and may not receive an actual cash distribution of such amounts. The Tax Act contains anti-avoidance rules to address certain foreign tax credit generator transactions (the “Foreign Tax Credit Generator Rules”). Under the Foreign Tax Credit Generator Rules, the “foreign accrual tax” (as defined in the Tax Act) applicable to a particular amount of FAPI included in BRELP’s income in respect of a particular “foreign affiliate” (as defined in the Tax Act) of BRELP may be limited in certain specified circumstances. See Item 10.E “Taxation – Certain Material Canadian Federal Income Tax Considerations”.

Unitholders may be required to include imputed amounts in their income for Canadian federal income tax purposes in accordance with section 94.1 of the Tax Act.

Section 94.1 of the Tax Act contains rules relating to interests in entities that are not resident or deemed to be resident in Canada for purposes of the Tax Act or not situated in Canada, other than a CFA of the taxpayer (the “Non-Resident Entities”), that could in certain circumstances cause income to be imputed to Unitholders for Canadian federal income tax purposes, either directly or by way of allocation of such income imputed to BEP or to BRELP. See Item 10.E “Taxation – Certain Material Canadian Federal Income Tax Considerations”.

Our Units may or may not continue to be “qualified investments” under the Tax Act for registered plans.

Provided that our Units are listed on a “designated stock exchange” (as defined in the Tax Act, which includes the NYSE and the TSX), our Units will be “qualified investments” under the Tax Act for a trust governed by a registered retirement savings plan (“RRSP”), deferred profit sharing plan, registered retirement income fund (“RRIF”), registered education savings plan (“RESP”), registered disability savings plan (“RDSP”) and a tax-free savings account (“TFSA”). However, there can be no assurance that our Units will continue to be listed on a “designated stock exchange”. There can also be no assurance that tax laws relating to “qualified investments” will not be changed. Taxes may be imposed in respect of the acquisition or holding of non-qualified investments by such registered plans and certain other taxpayers and with respect to the acquisition or holding of “prohibited investments” (as defined in the Tax Act) by an RRSP, RRIF or TFSA.

Notwithstanding the foregoing, a holder of a TFSA or an RDSP, a subscriber of an RESP or an annuitant under an RRSP or RRIF, as the case may be, will be subject to a penalty tax if our Units are a “prohibited investment” (as defined in the Tax Act) for the TFSA, RDSP, RESP,RRSP or RRIF.  Our Units generally will not be a “prohibited investment” on the date hereof if the holder of the TFSA or RDSP, the subscriber of the RESP or the annuitant under the RRSP or RRIF, as applicable: (i) deals at arm’s length for the purposes of the Tax Act with BEP; and (ii) does not have a “significant interest” (as defined in the Tax Act for purposes of the “prohibited investment” rules) in BEP. Unitholders who hold our Units in a TFSA, RDSP, RESP, RRSP or RRIF should consult their own tax advisors regarding the application of the foregoing “prohibited investment” rules having regard to their particular circumstances.

Unitholders’ foreign tax credits for Canadian federal income tax purposes will be limited if the Foreign Tax Credit Generator Rules apply in respect of the foreign “business-income tax” or “non-business-income tax” (each as defined in the Tax Act) paid by BEP or BRELP to a foreign country.

Under the Foreign Tax Credit Generator Rules, the foreign “business-income tax” or “non-business-income tax” for Canadian federal income tax purposes for any taxation year may be limited in

Page 46

certain circumstances. If the Foreign Tax Credit Generator Rules apply, the allocation to a Unitholder of foreign “business-income tax” or “non-business-income tax” paid by BEP or BRELP, and therefore such Unitholder’s foreign tax credits for Canadian federal income tax purposes, will be limited. See Item 10.E “Taxation - Certain Material Canadian Federal Income Tax Considerations”.

Unitholders who are not and are not deemed to be resident in Canada for purposes of the Tax Act and who do not use or hold,  and are not deemed to use or hold,  their Units in connection with a business carried on in Canada (“Non-Resident Unitholders”) may be subject to Canadian federal income tax with respect to any Canadian source business income earned by BEP or BRELP if BEP or BRELP were considered to carry on business in Canada.

If BEP or BRELP were considered to carry on business in Canada for purposes of the Tax Act, Non-Resident Unitholders would be subject to Canadian federal income tax on their proportionate share of any Canadian source business income earned or considered to be earned by BEP, subject to the potential application of the safe harbour rule in section 115.2 of the Tax Act and any relief that may be provided by any relevant income tax treaty or convention.

The Managing General Partner and the BRELP General Partner intend to manage the affairs of BEP and BRELP, to the extent possible, so that they do not carry on business in Canada and are not considered or deemed to carry on business in Canada for purposes of the Tax Act. Nevertheless, because the determination of whether BEP or BRELP is carrying on business and, if so, whether that business is carried on in Canada, is a question of fact that is dependent upon the surrounding circumstances, the CRA might contend successfully that either or both of BEP and BRELP carries on business in Canada for purposes of the Tax Act.

If BEP or BRELP is considered to carry on business in Canada or is deemed to carry on business in Canada for the purposes of the Tax Act, Non-Resident Unitholders that are corporations would be required to file a Canadian federal income tax return for each taxation year in which they are a Non-Resident Unitholder regardless of whether relief from Canadian taxation is available under an applicable income tax treaty or convention. Non-Resident Unitholders who are individuals would only be required to file a Canadian federal income tax return for any taxation year in which they are allocated income from BEP from carrying on business in Canada that is not exempt from Canadian taxation under the terms of an applicable income tax treaty or convention.

Non-Resident Unitholders may be subject to Canadian federal income tax on capital gains realized by BEP or BRELP on dispositions of “taxable Canadian property” (as defined in the Tax Act).

A Non-Resident Unitholder will be subject to Canadian federal income tax on its proportionate share of capital gains realized by BEP or BRELP on the disposition of “taxable Canadian property” other than “treaty-protected property” (as defined in the Tax Act). “Taxable Canadian property” includes, but is not limited to, property that is used or held in a business carried on in Canada and shares of corporations that are not listed on a “designated stock exchange” if more than 50% of the fair market value of the shares is derived from certain Canadian properties during the 60-month period immediately preceding the particular time. Property of BEP and BRELP generally will be “treaty-protected property” to a Non-Resident Unitholder if the gain from the disposition of the property would, because of an applicable income tax treaty or convention, be exempt from tax under the Tax Act. The Managing General Partner and the BRELP General Partner do not expect BEP and BRELP to realize capital gains or losses from dispositions of “taxable Canadian property”. However, no assurance can be given in this regard. Non-Resident Unitholders will be required to file a Canadian federal income tax return in respect of a disposition of “taxable Canadian property” by BEP or BRELP unless the disposition is an “excluded disposition” for the purposes of section 150 of the Tax Act. However, Non-Resident Unitholders that are corporations will still be required to file a Canadian federal income tax return in respect of a disposition of “taxable Canadian property” that is an “excluded disposition” for the purposes of section 150 of the Tax Act if tax would otherwise be payable under Part I of the Tax Act by such Non-Resident Unitholders in respect of the disposition but is not because of an applicable income tax treaty or convention (otherwise than in respect of a disposition of “taxable Canadian property” that is “treaty-protected property” of the corporation). In general, an “excluded disposition” is a disposition of property by a taxpayer in a taxation year where (a) the taxpayer is a non-resident of Canada at the time of the disposition; (b) no tax is payable by the taxpayer under Part I of the Tax Act for the taxation year; (c) the taxpayer is not liable to

Page 47

pay any amounts under the Tax Act in respect of any previous taxation year (other than certain amounts for which the CRA holds adequate security); and (d) each “taxable Canadian property” disposed of by the taxpayer in the taxation year is either (i) “excluded property” (as defined in subsection 116(6) of the Tax Act) or (ii) property in respect of the disposition of which a certificate under subsection 116(2), (4) or (5.2) of the Tax Act has been issued by the CRA. Non-Resident Unitholders should consult their own tax advisors with respect to the requirements to file a Canadian federal income tax return in respect of a disposition of “taxable Canadian property” by BEP or BRELP.

Non-Resident Unitholders may be subject to Canadian federal income tax on capital gains realized on the disposition of Units that are considered “taxable Canadian property”.

Any capital gain arising from the disposition or deemed disposition of our Units by a Non-Resident Unitholder will be subject to taxation in Canada, if, at the time of the disposition or deemed disposition, our Units are “taxable Canadian property” of the Non-Resident Unitholder, unless our Units are “treaty-protected property” to such Non-Resident Unitholder. In general, our Units will not constitute “taxable Canadian property” of any Non-Resident Unitholder at the time of disposition or deemed disposition, unless (a) at any time in the 60-month period immediately preceding the disposition or deemed disposition, more than 50% of the fair market value of our Units was derived, directly or indirectly (excluding through a corporation, partnership or trust, the shares or interests in which were not themselves “taxable Canadian property”), from one or any combination of:  (i) real or immovable property situated in Canada;  (ii) “Canadian resource properties” (as defined in the Tax Act);  (iii) “timber resource properties” (as defined in the Tax Act); and (iv) options in respect of, or interests in, or for civil law rights in, such property, whether or not such property exists, or (b) our Units are otherwise deemed to be “taxable Canadian property”. Since BEP’s assets will consist principally of units of BRELP, our Units would generally be “taxable Canadian property” at a particular time if the units of BRELP held by BEP derived, directly or indirectly (excluding through a corporation, partnership or trust, the shares or interests in which were not themselves “taxable Canadian property”), more than 50% of their fair market value from properties described in (i) to (iv) above, at any time in the 60-month period preceding the particular time. The Managing General Partner and the BRELP General Partner donot expect our Units to be “taxable Canadian property” of any Non-Resident Unitholder at any time but no assurance can be given in this regard. See Item 10.E “Taxation – Certain Material Canadian Federal Income Tax Considerations”. Even if our Units constitute “taxable Canadian property”, our Units will be “treaty-protected property” if the gain on the disposition of our Units is exempt from tax under the Tax Act under the terms of an applicable income tax treaty or convention. If our Units constitute “taxable Canadian property”, Non-Resident Unitholders will be required to file a Canadian federal income tax return in respect of a disposition of our Units unless the disposition is an “excluded disposition” (as discussed above). If our Units constitute “taxable Canadian property”, Non-Resident Unitholders should consult their own tax advisors with respect to the requirement to file a Canadian federal income tax return in respect of a disposition of Units.

Non-Resident Unitholders may be subject to Canadian federal income tax reporting and withholding tax requirements on the disposition of “taxable Canadian property”.

Non-Resident Unitholders who dispose of “taxable Canadian property”, other than “excluded property” and certain other property described in subsection 116(5.2) of the Tax Act, (or who are considered to have disposed of such property on the disposition of such property by BEP or BRELP) are obligated to comply with the procedures set out in section 116 of the Tax Act and obtain a certificate pursuant to the Tax Act. In order to obtain such certificate, the Non-Resident Unitholder is required to report certain particulars relating to the transaction to CRA not later than 10 days after the disposition occurs. The Managing General Partner and the BRELP General Partner do not expect our Units to be “taxable Canadian property” of any Non-Resident Unitholder and do not expect BEP or BRELP to dispose of property that is “taxable Canadian property” but no assurance can be given in these regards.

Payments of dividends or interest (other than interest not subject to Canadian federal withholding tax) by residents of Canada to BRELP will be subject to Canadian federal withholding tax and we  may be unable to apply a reduced rate taking into account the residency or entitlement to relief under an applicable income tax treaty or convention of our Unitholders.

BEP and BRELP will be deemed to be a non-resident person in respect of certain amounts paid or credited or deemed to be paid or credited to them by a person resident or deemed to be resident in

Page 48

Canada, including dividends or interest. Dividends or interest (other than interest not subject to Canadian federal withholding tax) paid or deemed to be paid by a person resident or deemed to be resident in Canada to BRELP will be subject to withholding tax under Part XIII of the Tax Act at the rate of 25%. However, the CRA’s administrative practice in similar circumstances is to permit the rate of Canadian federal withholding tax applicable to such payments to be computed by looking through the partnership and taking into account the residency of the partners (including partners who are resident in Canada) and any reduced rates of Canadian federal withholding tax that any non-resident limited partners may be entitled to under an applicable income tax treaty or convention, provided that the residency status and entitlement to treaty benefits can be established. In determining the rate of Canadian federal withholding tax applicable to amounts paid by the Holding Entities to BRELP, the Managing General Partner and the BRELP General Partner expect the Holding Entities to look-through BRELP and BEP to the residency of BEP’s partners (including partners who are resident in Canada) and to take into account any reduced rates of Canadian federal withholding tax that non-resident partners may be entitled to under an applicable income tax treaty or convention in order to determine the appropriate amount of Canadian federal withholding tax to withhold from dividends or interest paid to BRELP. However, there can be no assurance that the CRA will apply its administrative practice in this context. If the CRA’s administrative practice is not applied and the Holding Entities withhold Canadian federal withholding tax from applicable payments on a look-through basis, the Holding Entities may be liable for additional amounts of Canadian federal withholding tax plus any associated interest and penalties. Under the Canada-United States Tax Convention (1980) (the “Treaty”), a Canadian-resident payer is required in certain circumstances to look-through fiscally transparent partnerships, such as BEP and BRELP, to the residency and Treaty entitlements of their partners and take into account the reduced rates of Canadian federal withholding tax that such partners may be entitled to under the Treaty. Under the Amended and Restated Limited Partnership Agreement of BEP, the amount of any taxes withheld or paid by BEP, BRELP or the Holding Entities in respect of our Units may be treated either as a distribution to our Unitholders or as a general expense of BEP as determined by the Managing General Partner in its sole discretion. However, it is the current intention of the Managing General Partner to treat all such amounts as a distribution to our Unitholders.

While the Managing General Partner and the BRELP General Partner expect the Holding Entities to look-through BEP and BRELP in determining the rate of Canadian federal withholding tax applicable to amounts paid or deemed to be paid by the Holding Entities to BRELP, we may be unable to accurately or timely determine the residency of our Unitholders for purposes of establishing the extent to which Canadian federal withholding taxes apply or whether reduced rates of withholding tax apply to some or all of our Unitholders. In such a case, the Holding Entities will withhold Canadian federal withholding tax from all payments made to BRELP that are subject to Canadian federal withholding tax at the rate of 25%. Canadian-resident Unitholders will be entitled to claim a credit for such taxes against their Canadian federal income tax liability but Non-Resident Unitholders will need to take certain steps to receive a refund or credit in respect of any such Canadian federal withholding taxes withheld equal to the difference between the withholding tax at a rate of 25% and the withholding tax at the reduced rate they are entitled to under an applicable income tax treaty or convention. See Item 10.E. “Taxation – Certain Material Canadian Federal Income Tax Considerations” for further detail. Unitholders should consult their own tax advisors concerning all aspects of Canadian federal withholding taxes.

ITEM 4.       INFORMATION ON THE COMPANY

4.A              HISTORY AND DEVELOPMENT OF THE COMPANY

Overview

Brookfield Renewable owns one of the world’s largest, publicly-traded, pure-play renewable power portfolios.  Brookfield Renewable invests in renewable assets directly, as well as with institutional partners, joint venture partners and in other arrangements.  Our portfolio of assets has approximately 16,400 MW of installed capacity and an approximate 7,000 MW development pipeline, diversified globally.

Our objective is to pay distributions to our LP Unitholders that are sustainable on a long-term basis while retaining within our operations sufficient liquidity for recurring growth capital expenditures and general purposes. This is the basis for our long-term target payout ratio of approximately 70% of Funds

Page 49

From Operations.  We also target an annual distribution growth rate of 5% to 9% that is forecast to be fully funded by organic growth embedded in the portfolio today.  These organic growth initiatives include the potential commercialization of our approximate 7,000 MW development pipeline at premium returns, margin expansion through revenue growth and cost reduction initiatives, and through inflation escalations in our contracts.

In addition to organic growth, we continue to grow the business with an acquisition strategy that has a proven track record, and we have consistently demonstrated our ability to acquire high-quality assets by applying our disciplined and selective underwriting approach. Our acquisition strategy is being implemented globally and we believe that our scale, significant capitalization and sound investment-grade ratings will continue to enhance our ability to secure and fund new transactions globally.

We anticipate that our organic growth initiatives can support an attractive distribution and growth target, which will be meaningfully enhanced by our acquisition strategy. Approximately 90% of our 2018 proportionate generation is contracted with a weighted-average remaining duration of 15 years (on a proportionate basis) with creditworthy counterparties, including Brookfield.

We anticipate that the only distributions we will receive in respect of our limited partnership interests in BRELP will consist of amounts that are intended to assist us in making distributions to our LP Unitholders in accordance with our distribution policy, to our Preferred Unitholders in accordance with the terms of our Preferred Units and to allow us to pay expenses as they become due. See Item 4.B “Business Overview – our LP Unit Distribution Policy”.

Our LP Units are listed on the TSX under the symbol “BEP.UN” and on the NYSE under the symbol “BEP”.   

History and Development of Our Business

BEP is a Bermuda exempted limited partnership that was established on June 27, 2011 under the provisions of the Exempted Partnerships Act 1992 of Bermuda and the Limited Partnership Act 1883 of Bermuda. Our registered and head office is located at 73 Front Street, 5th Floor, Hamilton HM 12, Bermuda, our website is https://bep.brookfield.com and our telephone number is +441-294-3304. BEP was established to serve as the primary vehicle through which Brookfield acquires renewable power assets on a global basis. Brookfield owns approximately 60% of BEP on a fully-exchanged basis and the public holds the remaining approximately 40%.

Recent Developments

The following is a summary of the material developments affecting our business from January 1, 2017 up to the date of this Form 20-F.

Construction and Development

In January 2017, we achieved commercial operation of our approximately R$222 million ($70 million), 25 MW Serra dos Cavalinhos I hydroelectric project in Brazil.

In March 2017, we achieved commercial operation of our approximately R$278 million ($88 million), 55 MW Santa Candida II biomass project in Brazil.

In May 2017, we reached commercial operation of our approximately £26 million ($35 million), 15 MW Crockandun wind project in Northern Ireland.

In August 2017, we reached commercial operation of our approximately £27 million ($36 million) 16 MW Shantavny wind project in Northern Ireland.

In December 2017, we completed construction of our approximately €36 million ($41 million), 19 MW Ballyhoura wind project in the Republic of Ireland with commercial operation expected in Q1 2018.

We continue to advance construction of our approximately R$314 million ($100 million), 28 MW Verde 4A hydro project in Brazil with commercial operation expected in Q1 2018.

We continue to advance construction of our approximately €49 million ($55 million), 28 MW Slievecallan wind project in the Republic of Ireland with commercial operation expected in Q1 2018.

Page 50

We continue to advance construction of our approximately R$252 million ($80 million), 19 MW Verde 4 hydroelectric project in Brazil with commercial operation expected in Q4 2018.

We continue to advance construction of our approximately £31 million ($41 million), 19 MW Tralorg wind project in Scotland with commercial operation expected in Q4 2019.

We continue to advance construction of our approximately R$260 million ($82 million), 30 MW Foz do Estrella hydro project in Brazil with commercial operation expected in 2020.

Acquisitions and Dispositions

In February 2017, Brookfield Renewable, together with its institutional partners, disposed of two wind farms in the Republic of Ireland with a combined 137 MW of operating wind capacity. The acquisition closed for $155 million of aggregate consideration to Brookfield Renewable and its institutional partners. Brookfield Renewable had an approximate 40% controlling interest prior to the disposition.

In March 2017, Brookfield Renewable together with its institutional partners, entered into agreements with TerraForm Power and TerraForm Global to acquire a 51% interest in TerraForm Power and 100% of the outstanding shares in TerraForm Global. The acquisition of TerraForm Power closed on October 16, 2017, and the acquisition of TerraForm Global closed on December 28, 2017.  TerraForm Power remains a Nasdaq listed public company and is now sponsored by Brookfield.  TerraForm Global has been delisted and privatized. Brookfield Renewable’s total net investment in TerraForm Power was $203 million for an approximate 16% non-controlling interest, and its total net investment in Terraform Global was $230 million for an approximate 31% controlling interest.

In July 2017, Brookfield Renewable, together with its institutional partners, completed the acquisition of a 25% interest in First Hydro, which holds the United Kingdom’s largest pumped storage portfolio with 2,088 MW of capacity.  The acquisition closed for $248 million of aggregate consideration.  Brookfield Renewable retains an approximate 7% non-controlling interest.

In August 2017, Brookfield Renewable, together with its institutional partners, completed the acquisition of the 16 MW Shantavny wind development project in Northern Ireland, which we expect to achieve commercial operation in August 2018. The acquisition closed for $32 million of aggregate consideration. Brookfield Renewable retains an approximate 40% controlling interest.

Project and Operating Entity Financings

In March 2017, we completed the financing of a $60 million bank loan associated with a 417 MW hydroelectric facility in Pennsylvania, U.S.

In May 2017, we completed a $65 million refinancing associated with a 44 MW hydroelectric facility in New England, U.S.

In June 2017, we completed the refinancing of a $11 million bank loan associated with a 11 MW wind asset in Arizona, U.S.

In June 2017, we completed a C$55 million ($43 million) financing associated with a 17 MW hydroelectric facility in Quebec, Canada.

In July 2017, we extended the maturity of a $100 million credit facility associated with Isagen by one year to July 2020.

In July 2017, we completed a $475 million refinancing of a 360 MW hydroelectric portfolio in New England, U.S.

In October 2017, we completed a €78 million ($92 million) construction and term financing associated with a 47 MW wind portfolio in the Republic of Ireland.

In December 2017, we completed a $305 million refinancing associated with an 872 MW hydroelectric portfolio in New York, U.S.

In December 2017, we secured an additional £17 million ($22 million) construction and term financing associated with the addition of 16MW to our 29 MW portfolio in Northern Ireland.

Page 51

In December 2017, we completed a R$166 million ($50 million) construction and term financing associated with a 28 MW hydroelectric facility in Brazil.

In January 2018, we completed a £60 million ($83 million) non-recourse financing and £90 million ($125 million) letter of credit facility associated with our 2,088 MW pumped storage hydroelectric investment in the United Kingdom.

In January 2018, we signed a R$130 million ($40 million) construction and term financing agreement associated with a 19 MW hydroelectric facility in Brazil.

In February 2018, we completed a $350 million refinancing associated with a 296 MW hydroelectric portfolio in Pennsylvania, U.S.

In October 2017, TerraForm Power Operating, LLC secured a $450 million revolving credit facility at LIBOR plus 3%, maturing in October 2021.

In November 2017, TerraForm Power Operating, LLC secured a $350 million term loan at LIBOR plus 2.75%, maturing in November 2022.

In December 2017, TerraForm Power Operating, LLC issued an aggregate of $1.2 billion of senior notes. The issuance was comprised of $500 million of 4.25% senior notes due January 2023 and $700 million of 5.00% senior notes due January 2028.

In February 2018, TerraForm Global Operating, LLC issued $400 million of senior notes at 6.125%, maturing in January 2026.

In February 2018, TerraForm Global Operating, LLC secured a $45 million revolving credit facility at LIBOR plus 2.50%, maturing in February 2021.

In February 2018, we completed a COP 750 billion ($262 million) bond refinancing associated with Isagen.

Corporate Financings

In February 2017, BEP issued 10,000,000 Series 11 Preferred Units at a price of C$25.00 per unit, for gross proceeds of C$250 million ($190 million).  

In February 2017, Brookfield Renewable and Brookfield agreed to increase the committed unsecured revolving credit facility provided by Brookfield to $400 million.

In June 2017, BEP extended the maturity of $1,600 million of its corporate credit facilities by one year to June 30, 2022.

In July 2017, BEP issued 8,304,000 LP Units at a price of C$42.15 per unit. Concurrently, Brookfield purchased 4,943,000 LP Units in a private placement. The aggregate gross proceeds of these transactions were C$550 million ($422 million).

In December 2017, Brookfield Renewable and Brookfield agreed to amend the $400 million credit facility provided by Brookfield to extend its maturity by one year to December 31, 2018.

In January 2018, BEP issued 10,000,000 Series 13 Preferred Units at a price of C$25.00 per unit, for gross proceeds of C$250 million ($201 million).

Other

In June 2017, the TSX accepted a notice of BRP Equity’s intention to renew its normal course issuer bid, which permits BRP Equity to repurchase up to 10% of the total public float (calculated on June 14, 2017) of each series of its issued and outstanding Class A Preference Shares for a one year period.

In December 2017, the TSX accepted a notice of BEP’s intention to renew its normal course issuer bid, which permits BEP to repurchase up to 9,000,000 of its issued and outstanding LP Units for a one year period.

Page 52

4.B              BUSINESS OVERVIEW

Our Operations

We invest in renewable assets directly, as well as with institutional partners, joint venture partners and through other arrangements. Our portfolio of assets has approximately 16,400 megawatts (“MW”) of capacity and annualized long-term average (“LTA”) generation of approximately 50,100 gigawatt hours (“GWh”), in addition to a development pipeline of approximately 7,000 MW, making us one of the largest pure-play public renewable companies in the world. We leverage our extensive operating experience to maintain and enhance the value of assets, grow cash flows on an annual basis and cultivate positive relations with local stakeholders. The table below outlines our portfolio as at December 31, 2017:

											Storage
			River				Capacity		LTA(1)		Capacity
				Systems	Facilities		(MW)		(GWh)		(GWh)
Hydroelectric
	North America(2)
		United States		30		136		2,886		11,982		2,523
		Canada		19		33		1,361		5,177		1,261
				49		169		4,247		17,159		3,784
	Colombia(3)			6		6		2,732		14,476		3,703
	Brazil(4)			26		42		899		4,647		-
				81		217		7,878		36,282		7,487
Wind(5)
		United States		-		24		1,888		6,426		-
		Canada		-		4		484		1,435		-
				-		28		2,372		7,861		-
	Europe			-		23		513		1,313		-
	Brazil			-		19		457		1,777		-
	Other			-		6		250		412		-
				-		76		3,592		11,363		-
Solar(6)				-		537		1,511		2,492		-
Storage(7)				2		4		2,698		-		5,220
Other(8)				-		7		690		-		-
				83		841		16,369		50,137		12,707

⁽¹⁾LTA is calculated on a consolidated and an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date. See Item 5.A “Financial Performance Review on Proportionate Information”  for an explanation on the Solar and Storage segment introduced this year, why we do not consider long-term average generation for our Storage and Other facilities, and explanation on the calculation and relevance of proportionate information.

⁽²⁾North America hydroelectric LTA is the expected average level of generation based on the results of a simulation based on historical inflow data performed over a period of typically 30 years.

⁽³⁾Colombia hydroelectric LTA is the expected average level of generation based on the results of a simulation based on historical inflow data performed over a period of typically 20 years. Colombia includes generation from both hydroelectric and Co-gen facilities.

⁽⁴⁾Hydroelectric assets located in Brazil benefit from a market framework which levelizes generation risk across producers.

⁽⁵⁾Wind LTA is the expected average level of generation based on the results based on simulated historical wind speed data performed over a period of typically 10 years.

⁽⁶⁾Solar LTA is the expected average level of generation based on the results of a simulation using historical irradiance levels in the locations of our projects from the last 14 to 20 years combined with actual generation data during the operational period.

⁽⁷⁾Includes pumped storage in North America (600 MW) and Europe (2,088 MW) and battery storage in North America (10 MW).

⁽⁸⁾Includes four biomass facilities in Brazil (175 MW), one Co-gen plant in Colombia (300 MW), and two Co-gen plants in North America (215 MW).

Page 53

The following table presents the annualized long-term average generation of our portfolio as at December 31, 2017 on a consolidated and quarterly basis:

GENERATION (GWh)(1)			Q1	Q2	Q3	Q4	Total
Hydroelectric
	North America(2)
		United States	3,404	3,474	2,178	2,926	11,982
		Canada	1,228	1,508	1,223	1,218	5,177
			4,632	4,982	3,401	4,144	17,159
	Colombia(3)		3,508	3,509	3,571	3,888	14,476
	Brazil(4)		1,147	1,159	1,170	1,171	4,647
			9,287	9,650	8,142	9,203	36,282
Wind(5)
	North America
		United States	1,738	1,728	1,288	1,672	6,426
		Canada	400	345	273	417	1,435
			2,138	2,073	1,561	2,089	7,861
	Europe		393	283	252	385	1,313
	Brazil		334	393	588	462	1,777
	Other		113	117	75	107	412
			2,978	2,866	2,476	3,043	11,363
Solar(6)			521	720	747	504	2,492
Total			12,786	13,236	11,365	12,750	50,137

⁽¹⁾LTA is calculated on a consolidated and an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date.

⁽²⁾North America hydroelectric LTA is the expected average level of generation, as obtained from the results of a simulation based on historical inflow data performed over a period of typically 30 years.

⁽³⁾Colombia hydroelectric LTA is the expected average level of generation, as obtained from the results of a simulation based on historical inflow data performed over a period of typically 20 years. Colombia includes generation from both hydroelectric and Co-gen facilities.

⁽⁴⁾Hydroelectric assets located in Brazil benefit from a market framework which levelizes generation risk across producers.

⁽⁵⁾Wind LTA is the expected average level of generation, as obtained from the results based on simulated historical wind speed data performed over a period of typically 10 years. 

⁽⁶⁾Solar LTA is the expected average level of generation based on the results of a simulation using historical irradiance levels in the locations of our projects from the last 14 to 20 years combined with actual generation data during the operational period.

Page 54

The following table presents the annualized long-term average generation of our portfolio as at December 31, 2017 on a proportionate  and quarterly basis:

GENERATION (GWh)(1)			Q1	Q2	Q3	Q4	Total
Hydroelectric
	North America(2)
		United States	2,225	2,361	1,470	1,953	8,009
		Canada	1,214	1,461	1,184	1,192	5,051
			3,439	3,822	2,654	3,145	13,060
	Colombia(3)		844	844	859	935	3,482
	Brazil(4)		958	968	978	978	3,882
			5,241	5,634	4,491	5,058	20,424
Wind(5)
	North America
		United States	361	416	300	337	1,414
		Canada	336	300	243	355	1,234
			697	716	543	692	2,648
	Europe		155	112	100	153	520
	Brazil		111	132	203	163	609
	Other		35	36	23	33	127
			998	996	869	1,041	3,904
Solar(6)			94	130	142	91	457
Total			6,333	6,760	5,502	6,190	24,785

⁽¹⁾LTA is calculated on a proportionate and an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date.

⁽²⁾North America hydroelectric LTA is the expected average level of generation, as obtained from the results of a simulation based on historical inflow data performed over a period of typically 30 years.

⁽³⁾Colombia hydroelectric LTA is the expected average level of generation, as obtained from the results of a simulation based on historical inflow data performed over a period of typically 20 years. Colombia includes generation from both hydroelectric and Co-gen facilities.

⁽⁴⁾Hydroelectric assets located in Brazil benefit from a market framework which levelizes generation risk across producers.

⁽⁵⁾Wind LTA is the expected average level of generation, as obtained from the results based on simulated historical wind speed data performed over a period of typically 10 years. 

⁽⁶⁾Solar LTA is the expected average level of generation based on the results of a simulation using historical irradiance levels in the locations of our projects from the last 14 to 20 years combined with actual generation data during the operational period.

We have comprehensive power operations and development capabilities located in each of our core markets that position us to maintain and increase the value of our asset base while competitively positioning us for continued growth.

Operating Philosophy

We employ a hands-on, operations-oriented, long-term owner’s approach to managing our portfolio. We believe this approach ensures that we maintain and, where possible, enhance the value of our assets by being able to quickly identify and manage any technical, economic or stakeholder issue that may arise.  The operation of our generating facilities is largely decentralized across North America, South America, Europe and Asia. We support our operators with a strong corporate team that provides oversight on a global basis of the functions of BEP and, among other things, establishes consistent global

Page 55

policies on compliance, information technology, health, safety and security, human resources, stakeholder relations, procurement, governance and anti-bribery and anti-corruption.

We also benefit from the expertise of Brookfield which provides strategic direction, corporate oversight, commercial and business development expertise, and oversees decisions regarding the funding and growth of our business. We believe this approach leads to a strong decision-making culture and long-term owner-oriented investment philosophy to build value.

The cornerstones of our operational philosophy are:

Operating expertise. In each of North America, Brazil, Colombia and Europe, which are currently our core markets, we have strong operating businesses with full construction, development and operational capabilities. Each of these businesses benefits from centralized, automated plant dispatch and control centers allowing remote operation of most of our facilities and a central interface with regulatory and market authorities, as well as offtakers. These capabilities allow us to leverage our operating expertise when growing our business. 

Culture of health, safety, security and environmental leadership. We strive to achieve excellence in safety performance and to be recognized as an industry leader in accident prevention. Our overall objective is to incur zero high risk safety incidents and zero lost time injuries. We have adopted written Health, Safety, Security and Environmental (“HSS&E”) policies that include frameworks for oversight, compliance, compliance audits and the sharing of best practices both within our operations and the global Brookfield group. We maintain an HSS&E Steering Committee, consisting of, among others, the Chief Executive Officer of the Service Provider and the Chief Executive Officer of each operating business, and require all employees, contractors, agents and others involved in our operations to comply with our established HSS&E practices.

Disciplined management of operating costs. Our operations are focused on maintaining the cost competitive position of our portfolio through disciplined management of operating costs with the objective of annually offsetting the costs of inflation. In addition, the scalability of our operating businesses allows us to grow the portfolio while only minimally increasing incremental fixed costs thus ensuring a stable and predictable cost profile over the long-term.

Focus on asset reliability and availability. Maintaining high reliability and availability of our plants is critical because if we are not able to generate and deliver energy we will not maximize the benefit of our long-term contracts. To the greatest extent possible, our operating teams perform all periodic and planned maintenance activities during periods of low hydrology, wind or sun, in order to minimize lost revenue opportunities and take advantage of excess capacity at our plants.

Long-term ownership and asset reinvestment. We seek to preserve and enhance the productivity, reliability and longevity of each of our generating facilities. The cornerstone of our asset maintenance and enhancement program is a 20-year forward-looking capital reinvestment plan. Our operating teams work closely with independent engineering firms recognized as industry leaders in renewable energy production and maintenance to develop a detailed capital plan for each asset. We develop and implement our plans by taking a long-term owner’s perspective and, in particular, believe the low capital expenditure maintenance requirements and long useful life are attractive attributes of our predominantly hydroelectric assets. Hydroelectric power generation is a mature, efficient and relatively simple technology that has not changed significantly over the past century.

Positive local stakeholder relationships. We strive to maintain transparent and well-established relationships with local stakeholder groups and the communities in which we operate, which we believe is a key element of successfully operating and developing renewable power facilities. In order to ensure the successful renewal and implementation of our water power licenses, land leases, permits and other licenses and concessions, we consult and work proactively with local stakeholders and communities potentially affected by our operations.

We maintain a performance-based culture and use annual performance targets in each of the above areas to measure the performance of our operating teams.

Page 56

North American Business

The principal office of our North American business is located in Gatineau, Québec and oversees our operations in the United States and Canada.Our North American business employs approximately 925 employees.

United States

Our main office in the United States is located in Marlborough, Massachusetts. Our U.S. National System Control Center is also located in Marlborough, Massachusetts and allows for the remote

Page 57

monitoring and control of nearly all of our assets in the country. In the United States we have full hydroelectric and wind operating capabilities, as well as development and construction oversight expertise. We employ approximately 545 people, approximately 45% of whom are covered by collective agreements. We have experienced positive relations with our unionized work force in the United States.

We are strategically focused on power markets in the Northeast, Mid-Atlantic, Southeast and California, with additional operations in Arizona, Minnesota and Louisiana. The majority of our capacity in the United States is located in New York, Pennsylvania and New England. In New York, we are one of the largest independent power producers with 74 hydroelectric facilities with an aggregate installed capacity of 711 MW. In Pennsylvania, we have four hydroelectric facilities with an aggregate installed capacity of 742 MW. In New England, we have 47 hydroelectric facilities and one pumped storage facility with an aggregate installed capacity of 1,274 MW.

A number of our U.S. hydroelectric assets have water storage reservoirs that can collectively store approximately 2,500 GWh, or approximately 21% of their annualized long-term average generation. We also benefit from a 50% joint-venture interest in a 600 MW hydroelectric pumped storage facility located in Massachusetts. Pumped storage is a form of hydroelectric power which allows energy to be stored by pumping water up into a reservoir, and then producing power by releasing the water when power prices are higher.

We also own seven wind farms located in California, New Hampshire and Arizona with an aggregate installed capacity of 434 MW. The California wind farms account for the majority of this capacity and are primarily located in the Tehachapi area, which has one of the most proven wind resources in the United States and is attractively located near the Los Angeles load center. We also own one combined cycle, natural gas-fired facility in Syracuse, New York, which sells its power output on a merchant basis and is predominantly used at times of peak demand. 

Our rights to operate our hydroelectric facilities in the United States are secured primarily through long-term licenses from the Federal Energy Regulatory Commission (“FERC”), the federal agency that regulates the licensing of substantially all hydroelectric power plants in the United States. FERC has oversight of substantially all of our ongoing hydroelectric project operations, including dam safety inspections, environmental monitoring, compliance with license conditions, and the license renewal process. Our ability to sell power from certain of our generation facilities is also subject to the receipt and maintenance of certain approvals from FERC, including the authority to sell power at market-based rates.

Canada

Our main offices in Canada are located in Gatineau, Québec and Toronto, Ontario. Our Canadian National System Control Center is located in Gatineau and allows for the remote monitoring and control of all of our assets in the country. In Canada, we have full hydroelectric and wind operating capabilities, as well as development and construction oversight expertise.We employ approximately 380 people in the country and approximately 22% of these employees are covered by collective agreements. We have experienced positive relations with our unionized work force in Canada.

Canada has a strong hydropower tradition and is one of the largest hydropower generators in the world.  Our facilities are situated in Québec and Ontario – the two largest power markets in Canada – as well as in British Columbia.  These three provinces account for approximately three-quarters of Canada’s population. Each of these provinces has adopted policies to increase the contribution of renewables in the supply mix by offering long-term contracts with government-owned utilities through competitive requests for proposals or feed-in-tariffs.

Most of our Canadian hydroelectric assets are larger utility-scale facilities with water storage reservoirs that can together store approximately 1,300 GWh, or approximately 24% of their annualized long-term average generation.

We entered the Canadian wind business in 2004 and since then have completed the development, construction and operation of three wind farms in Ontario, with a combined installed capacity of 406 MW. We also have several projects in various stages of development. In addition to our renewable power assets, we own a 110 MW gas-fired plant that has been temporarily suspended and we have entered into an agreement to sell it, subject to customary closing conditions.

Page 58

We hold a variety of long-term waterpower licenses issued by the provinces where our operations are situated. These waterpower licenses permit us to use land, water and waterways for the generation of electricity. These licenses also contain terms that deal with water management, land use, public safety, recreation and the environment. At the end of the license period, license holders can apply to the requisite government body to have their licenses renewed.

TerraForm Power

The acquisition, with our institutional partners, of a 51% equity interest in TerraForm Power in October 2017 marked our entry into the solar market with scale operations in solar energy in certain of our core markets and a platform for future growth. TerraForm Power’s principal office in 2017 was located in Bethesda, Maryland and is being transitioned to New York, New York. TerraForm Power employs approximately 120 employees, of which none are covered by collective agreements.

            TerraForm Power, together with its subsidiaries, is a dividend growth-oriented company formed to own and operate contracted clean power generation assets in North America and Western Europe.  TerraForm Power’s business objective is to acquire assets with high quality contracted cash flows, primarily from owning clean power generation assets serving utility and commercial customers.  TerraForm Power’s portfolio consists of renewable energy facilities in the United States (including Puerto Rico), Canada, Chile and the United Kingdom with a combined nameplate capacity of approximately 2,600 MW. Pursuant to a relationship agreement between TerraForm Power and Brookfield Asset Management, TerraForm Power will serve as Brookfield’s primary vehicle through which it will acquire operating solar and/or wind assets in North America and Western Europe. Accordingly, Brookfield Renewable will invest in operating solar and/or wind assets in these regions by way of investment in TerraForm Power. 

Colombian Business

The Isagen Acquisition in January 2016 marked our entry into the Colombian market. Isagen’s principal office is located in Medellín and the company employs approximately 680 full time employees, of which approximately 85% are covered by collective agreements. 

During 2017, we closed a delisting tender offer for the issued and outstanding shares of Isagen, completed a merger between BRE Colombia Holding S.A.S. and Isagen. As a result of prior mandatory tender offers, open market purchases, and the aforementioned transactions, our consortium’s current ownership interest is 99.49% of the company of which our share is approximately 24%. Over the course of 2017, the business has performed in line with our expectations and has strong long-term growth prospects in an undersupplied market. Isagen is Colombia’s third-largest power generation company and owns and operates a 3,032 MW portfolio with an annual average generation of approximately 14,500 GWh. This portfolio accounts for approximately 18% of Colombia’s installed generating capacity and consists of six, largely reservoir-based, hydroelectric facilities and a 300 MW Co-gen plant. The hydroelectric assets include the largest reservoir by volume in Colombia and are collectively able to store approximately 26% of their annualized long-term average generation. Isagen’s portfolio also includes over 800 MW of attractive medium to long-term development projects.

Isagen owns all of its power generating assets in perpetuity and holds requisite water usage and other rights in respect of each of its assets. For each hydroelectric project built prior to 1993, it holds water usage rights that are granted by the appropriate regional or national environmental authority in addition to a number of minor licenses and approvals. Each project built after 1993 benefits from a streamlined environmental licensing regime under which it receives a single environmental license that contains all necessary permits, including water usage rights. Water usage rights granted prior to 1993 and environmental licenses granted after 1993 are generally granted for a term of approximately 50 years and can be renewed through an administrative process.

Brazilian Business

The principal office of our Brazil business is located in Rio de Janeiro and oversees our operations in Brazil, with approximately 435 employees. Our Brazilian National System Control Center is also located in Rio de Janeiro and allows for the remote monitoring and control of nearly all of our

Page 59

hydroelectric assets in the country. In Brazil, we have full hydroelectric, wind and biomass operating capabilities, as well as development and construction oversight expertise. All of our employees in Brazil are covered by collective agreements. We have experienced positive relations with our work force in Brazil.

Brookfield first invested in Brazil over 100 years ago. Recognizing Brazil’s growing demand for power and strong renewable resource base, Brookfield re-entered the Brazilian power market in 2003 and, since then, has grown its hydroelectric asset base significantly to 42 facilities on 26 river systems totaling approximately 899 MW of installed capacity.

We entered the wind and biomass businesses in Brazil in 2015 with the acquisition of five wind farms and four biomass facilities, all operational. The wind farms are located in the northeastern province of Rio Grande do Norte, one of the most proven wind resource areas in Brazil, and the biomass facilities are located in Mato Grosso do Sul and Sao Paulo, proximate to our hydroelectric portfolio. As part of the acquisition of TerraForm Global in December 2017, we acquired 307 MW of wind facilities located in the State of Bahia.

Considering all technologies, we own facilities totaling 1,531 MW located in 11 Brazilian states representing approximately 70% of the country’s population and 80% of the economic activity (in GDP terms). As such, we believe our business in Brazil is particularly well positioned to participate in a large and diversified economy with further developmental potential.

Since 2003, we have developed and built 16 facilities totaling 393 MW of capacity and we have several projects in various stages of development. As of the date of this Form 20-F, we continue to advance the construction of 77 MW of hydroelectric development projects in Brazil.

Rights to hydroelectric sites are secured in Brazil by obtaining authorizations (such as water use leases) and concessions from the Brazilian Ministry of Mines and Energy through the National Agency for Electric Energy (“ANEEL”). We generally focus on SHPPs, a category of hydroelectric power plant with less than 30 MW of capacity. SHPP plants can be secured directly from ANEEL, whereas sites for hydroelectric plants above 50 MW can only be granted by public auction, requiring developers to bid the lowest tariff in order to win the concession and a PPA with local utilities. Of our authorizations and concessions, 94% have remaining terms of more than 10 years. Generally, concessions provide for an initial term of 30 years with the possibility to renew the concession for an additional 20-year period. Similarly, authorizations provide for an initial term of 35 years and the possibility to renew for an additional 30-year period subject to payment of certain amounts under a water lease.

European Business

The principal office of our European operations is located in London, in the United Kingdom. Our European business, including our offices in London and Edinburgh in the United Kingdom and Cork in the Republic of Ireland, employs approximately 125 employees comprising operating, finance, project development, market research,power marketing and support functions. 

Republic of Ireland and Northern Ireland

Our 21 wind energy facilities, with 391 MW of installed capacity are located across the Republic of Ireland and Northern Ireland, which have among the strongest onshore wind resources in Europe and markets with stable contractual frameworks for renewables. We employ approximately 110 people in Ireland and none of these employees are unionized.

Brookfield Renewable has full wind development and construction oversight capabilities in Ireland. In 2017, we achieved commercial operation on our 15 MW and 16 MW wind projects in Northern Ireland and on our 19 MW wind project in Republic of Ireland. In addition to these projects we have an Irish wind development pipeline of more than 200 MW, which positions the portfolio for continued growth. Since we acquired our Irish wind portfolio in 2014, we have commissioned 202 MW of wind projects and expect to commission an additional 47 MW over the next two years.

The majority of wind farms in the Republic of Ireland are underpinned by the REFIT program. This program ensures that generators receive a minimum fixed annual electricity price, indexed by inflation annually over a contract term of 15 years, providing a revenue stream that is the higher of market prices

Page 60

or the REFIT price. The REFIT payments are guaranteed under legislation for eligible assets commissioned prior to the end of 2019. Recently, the Irish government issued a report on a new renewable support scheme confirming its long-term renewable power goals and therefore we expect a new auction-type regime to be announced for installations commissioned after 2019. We have 72 MW of non-REFIT wind assets, 52 MW of which were contracted at below market prices to 2019; during 2015, we restructured these PPAs with the Irish Energy Supply Board to preserve the existing below-market contracted price floor but include participation in approximately 90% of market prices. The wind farm assets in Northern Ireland earn British pound sterling denominated revenues by receiving a fixed price Renewable Obligation Certificate for twenty years, in addition to the market price. 

In 2017, we continued to enhance our power marketing capabilities in Europe, by increasing the focus on securing long-term contracts with corporate buyers of power, the sale of green credits, and expanding our capability to sell power across interconnections. In the U.K., we continue to explore opportunities to establish new routes to market through corporate buyers of power.

The land on which our wind farms are situated is typically leased or owned outright.  Where we hold leases, we typically hold a long-term lease for an initial 25 to 30 year term with a further right to renew. Additional licenses relevant to the wind farms include both electricity grid connection agreements with the national and distribution level grid system operators and planning permissions from the relevant local planning authorities.

Portugal & Scotland 

Our European business also includes a 123 MW wind portfolio in Portugal and approximately 600 MW wind development portfolio in Scotland. The Scottish portfolio includes a mix of permitted and earlier stage development projects as well as an six-person project development team located in Edinburgh. In February 2017, we commenced construction on an approximately 19 MW wind project in Scotland that will benefit from a 15-year government-backed contract for difference. In Portugal we have three employees who manage our wind portfolio in the country. None of these employees are unionized.

Wales

Our European business also includes a 25% stake in First Hydro, the U.K.’s largest pumped storage asset.  First hydro manages and operates 2.1 GW of pumped storage facilities at the Dinorwig and Ffestiniog power stations in the Snowdonia region of Wales and represents 75% of the U.K.’s pumped storage capacity and 50% of its hydro capacity. With the U.K. facing tightening supply margins, First Hydro provides an opportunity to invest in facilities providing critical back-up power and grid stabilization services.

Other Businesses

India

Our acquisition, with our institutional partners, of TerraForm Global marked our entry into the wind and solar markets in India. TerraForm Global employs approximately 27 employees in India, of which none are covered by collective agreements. The Indian portfolio consists of 302 MW of installed capacity, comprised of three wind energy facilities with an aggregate capacity of 102 MW and eleven solar energy facilities with an aggregate capacity of 200 MW. The assets are spread across the Indian provinces of Gujarat, Rajasthan, Madhya, Pradesh, Tamil Nadu and Karnataka. India represents a growth opportunity for Brookfield Renewable as it is a sizeable market with ambitious energy targets and significant potential for renewable power development.

China

Our acquisition, with our institutional partners, of TerraForm Global marked our entry into the renewable energy market in China. TerraForm Global employs approximately 56 employees in China, of which none are covered by collective agreements. The Chinese portfolio consists of two assets: a 149 MW wind energy facility in Inner Mongolia province; and an 18 MW solar energy facility in Gansu province. Similar to the Indian market, the size of the market in China coupled with ambitious targets for the expansion of renewable energy represents a significant growth opportunity for Brookfield Renewable.

Other Emerging Markets

Page 61

With the acquisition, with our institutional partners, of TerraForm Global, we acquired 99 MW in South Africa (this includes 33 MW in respect of which TerraForm Global receives the economic benefit, but has not yet acquired), 39 MW in Thailand, 26 MW in Uruguay, and 12 MW in Malaysia.

See Item 3.D “Risk Factors — Risks Related to our Operations and the Renewable Power Industry — Our operations are highly regulated and may be exposed to increased regulation which could result in additional costs to Brookfield Renewable” and Item 3.D “Risk Factors — Risks Related to our Operations and the Renewable Power Industry — There is a risk that our concessions and licenses will not be renewed”.

Registered and Head Office

Our registered and headoffice is in Hamilton, Bermuda.

Corporate Office

Our main corporate office is in Toronto, Ontario and provides oversight on a global basis of Brookfield Renewable. Our corporate group has approximately 125 employees, including both the corporate office and the Service Provider, who are located in North America, Brazil, Europe and China.  

Page 62

BEP is a globally diversified, multi-technology, owner and operator of renewable power assets.

Our business model is to utilize our global reach to acquire and develop high quality renewable power assets below intrinsic value, finance them on a long-term, low-risk and investment grade basis through a conservative financing strategy and then optimize cash flows by applying our operating expertise to enhance value.

One of the largest, public pure play renewable businesses globally.Brookfield Renewable operates and invests in a large, multi-technology and globally diversified portfolio. Brookfield Renewable invests in renewable assets directly, as well as with institutional partners, joint venture partners and in other arrangements. Our portfolio consists of 16,369 MW of installed capacity largely across four continents, a development pipeline of approximately 7,000 MW, and annualized long-term average generation on a proportionate basis of 24,785 GWh.

The following charts illustrate annualized long-term average generation on a proportionate basis:

Source of Energy	Region

Diverse and high quality assets with hydroelectric focus.Brookfield Renewable has a complementary portfolio of hydroelectric, wind, solar and storage facilities. Our portfolio includes utility-scale facilities, back-up storage power, and localized power generation. Hydroelectric power comprises the significant majority of our portfolio, and is the highest value renewable asset class as one of the longest life, lowest-cost and most environmentally-preferred forms of power generation. Hydroelectric plants have high cash margins, storage capacity with the capability to produce power at all hours of the day, and the ability to sell multiple products in the market including energy, capacity and ancillaries. Our wind and solar facilities provide exposure to two of the fastest growing renewable power sectors, with high cash margins, zero fuel input cost, and diverse and scalable applications including distributed generation. Our storage facilities provide the markets in which they are located with critical services to the grid and dispatchable generation. With our scale, diversity and the quality of our assets, we are competitively positioned relative to other power generators, providing significant scarcity value to our investors.

Stable, high quality cash flows with attractive long-term value for LP Unitholders.We intend to maintain a highly stable, predictable cash flow profile sourced from a diversified portfolio of low operating cost, long-life hydroelectric, wind and solar assets that sell electricity under long-term, fixed price contracts with creditworthy counterparties. Approximately 90% of our 2018 proportionate generation output is contracted to public power authorities, load-serving utilities, industrial users or to Brookfield. Our PPAs have a weighted-average remaining duration of 15 years, on a proportionate basis, providing long-term cash flow visibility.

Strong financial profile and conservative financing strategy. Brookfield Renewable maintains a robust balance sheet and access to global capital markets to ensure cash flow resiliency through the cycle. Our debt to total capitalization is 39% and approximately 70% of our borrowings are non-recourse. Corporate borrowings and subsidiary borrowings have weighted-average terms of approximately six and

Page 63

ten years, respectively. Our available liquidity as at December 31, 2017 is approximately $1.5 billion of cash and cash equivalents, available-for-sale securities and the available portions of credit facilities.

Well positioned for cash flow growth. We are focused on driving cash flow growth from existing operations, fully funded by internally generated cash flow, including inflation escalations in our contracts, margin expansion through revenue growth and cost reduction initiatives, and building out our approximately 7,000 MW proprietary development pipeline at premium returns. While we do not rely on acquisitions to achieve our growth targets, our business has upside from mergers and acquisitions on an opportunistic basis. We employ a contrarian strategy, and look for capital scarcity to earn strong returns. We take a disciplined approach to allocating capital into development and acquisitions with a focus on downside protection and preservation of capital. Over the last ten years, we have invested in, acquired, or commissioned 66 hydroelectric facilities totaling approximately 5,000 MW, 85 wind facilities totaling approximately 3,600 MW, 537 solar facilities totaling approximately 1,500 MW, four biomass facilities totaling 175 MW, two hydroelectric pumped storage and one battery storage totaling 2,098 MW and one 300 MW Co-gen plant. Our ability to develop and acquire assets is strengthened by our established operating and project development teams, strategic relationship with Brookfield, and our liquidity and capitalization profile. We have, in the past, and may continue in the future to pursue the acquisition or development of assets through arrangements with institutional investors in Brookfield sponsored or co-sponsored partnerships.

Attractive distribution profile.We pursue a strategy which we expect will provide for highly stable, predictable cash flows sourced from predominantly long-life hydroelectric assets ensuring a sustainable distribution yield. We target a long-term distribution payout ratio of approximately 70% of Funds From Operations and a long-term distribution growth rate in a range of 5% to 9% annually.

Renewable Power Growth Opportunity

Demand for renewable energy continues to grow around the world due to its positive environmental profile, the benefits of supply diversification and its increasing cost-competitiveness with traditional technologies. By the end of 2016, global installed renewable power capacity exceeded 1,800 GW. Total investment in new ‘clean energy’ facilities in that year has been estimated at around $280 billion (this figure excludes investments in large hydro plants). Over the last five years up to 2016, an average of approximately 125 GW of new renewable generation capacity has been added each year – primarily hydro, wind and solar photovoltaic.  The following chart illustrates the global growth in various renewable power generation sectors from 2000 to 2016.

Page 64

 

Sources:  BP Statistical Review of World Energy - June 2016 (for wind, geothermal and solar capacity 2000-2015); U.S. Energy Information Administration - International Energy Statistics (for hydroelectric capacity 2000-2014); hydro capacity for 2015 is assumed to increase in line with the growth in hydro generation in this year (from the 2016 BP Statistical Review).

Global Renewable Power Drivers

We believe that strong continuing growth in renewable power generation will be driven by the following:

Renewable energy is an increasingly cost-effective way of diversifying fuel risk. Continuous improvements in technology and economies of scale continue to reduce the costs of renewable power, enhancing its position as a cost competitive complement to gas-fired generation and as a means to meeting increasingly stringent environmental standards. While natural gas continues to make major gains in generation market share, we expect that utilities will increasingly seek to limit exposure to potential fuel cost volatility by looking to renewable technologies that offer stable price terms, particularly hydroelectric and wind energy. 

Consistent policy and supportive regulation. Regulatory support for the development of renewable power resources typically includes renewable portfolio standards (“RPS”) (requiring electricity distributors to obtain a minimum percentage of their power from renewable energy resources by specified target dates) and tax incentives or direct subsidies. Globally, at least 70 countries, including the Republic of Ireland, the United Kingdom, Portugal and the other 25 E.U. countries, have national targets for renewable energy supply. Similarly, 37 U.S. states, the District of Columbia, Puerto Rico and nine Canadian provinces have either RPS targets or other policy goals that require load-serving utilities to offer long-term PPAs for new renewable supply.

Mainstreamrecognition of climate change risk and serious commitment to action.Global support for de-carbonization – and by implication the further promotion of renewable technologies – was reinforced in December 2015 as 197 countries agreed at the COP21 Conference in Paris to develop national strategies consistent with limiting the increase in global temperature by 2050 to less than two degrees Celsius above pre-industrial levels. The Paris Agreement has been ratified by over 120 countries, although the United States has recently withdrawn from the agreement.

Page 65

Intensifying challenges for conventional coal and nuclear generation. Successive regulatory initiatives requiring significant environmental compliance expenditures are accelerating the retirement of coal plants, which will need to be replaced by new capacity. At the same time, cost uncertainties, public concern over new construction and nuclear waste disposal and intensified competition from gas-fired generation has delayed or halted many new nuclear development activities, and has led some countries to increase their renewable targets in order to satisfy supply requirements resulting from plant retirements and demand growth.

Our Core Markets

We have focused on North America, Colombia, Brazil and Europe as our core markets and we will continue to focus on using our operating expertise to expand our operations in these markets to meet our growth objectives. In addition, our relationship with Brookfield gives us access to Brookfield’s investment platforms in Australia, India and China as well as to Brookfield’s more established platforms in South America and Europe, which enhances our ability to source transactions globally.

North America

United States

Over the last decade, the United States has maintained consistent, broad-based policy momentum to transition the country’s electricity production to cleaner generation and promote increased energy independence. The United States is the world’s second largest wind market with approximately 85,000 MW of installed wind capacity as of 2017. One of the most significant drivers of renewable power growth in the United States has been the adoption of RPS targets in 29 states and the District of Columbia, with renewable mandates set to as high as 33% of the total supply mix by 2020 and with even more ambitious targets – 50% in the case of California and New York – by 2030. In addition, growth has been driven by various government incentive programs and Fortune 100 companies supporting investment in new renewables.

The U.S. government is taking steps to amend certain federal environmental regulation for thermal (and in particular, coal-fired) generation, which may result in those regulations becoming less stringent, however, policies promoting renewables were maintained in the recently enacted U.S. Tax Cuts and Jobs Act. We do not expect these changes to have a materially adverse effect on our business. Renewable energy policy in the United States is largely set at the state level and federal action will not change the long term trend of de-carbonization. In fact, much of the growth in demand for renewables has come from consumers and any reductions or cuts to federal subsidies for wind and solar could make these asset classes more attractive to investors, like ourselves, at the expense of low cost of capital financial investors.  In January 2018, the government of the United States imposed certain tariffs on solar equipment manufactured abroad. We expect that these tariffs will modestly slow the pace of the development of solar projects in the near term and will increase installed system costs. We do not expect that these tariffs will have significant long-term impact on the adoption of solar technology generally given how costs have declined in the last decade, the simplicity of the technology, the speed at which it can be developed and its obvious environmental attributes.

In the United States, we are strategically focused on power markets in the northeast (New York, New England), the mid-Atlantic (including the PJM ISO and north SERC regions) and California, with operations in other Mid-Continent ISO states including Minnesota and Louisiana. Together these markets cover approximately 70% of the U.S. population, and most have strong competitive wholesale markets and RPS targets, aging electricity infrastructure and/or pressure to retire coal generation, providing clear opportunities for sustained renewable generation growth.

Canada

In Canada, renewable energy policy is predominantly implemented at the provincial level. We are currently active in Ontario, Québec and British Columbia and each of these provinces has adopted policies to increase the contribution of renewables in the supply mix, which presents attractive opportunities for both project development and asset acquisition.

Most Canadian provinces are developing strategies pursuant to the December 2016 accord with the federal government addressing carbon pricing, efforts to eliminate coal-fired power generation and

Page 66

planned investments in renewable energy. Under the federal government’s guidelines, the provinces have until the end of 2018 to submit their own carbon pricing plans before a national scheme is implemented to establish a floor price for emissions allowances (previously indicated to follow a rising path, in $10 per tonne annual increments, to reach $50 per tonne in 2022). While this is positive news for the renewable industry in general, we do not expect it to materially impact our business.

Colombia

Colombia is an investment-grade rated country with an established competitive electricity market and we believe that the country will require new power supply after 2025 to meet demand growth. Colombia’s hydroelectric potential of approximately 93 GW is second only to Brazil among South American countries. As of December 2017, Colombia had a total installed capacity of almost 17 GW with hydro accounting for almost 70% of the supply mix and the remainder being supplied by natural gas, coal, and diesel. Colombia benefits from significant undeveloped hydroelectric potential and power prices remain relatively low on a global basis. We expect power prices to increase over the long-term as new supply is needed to meet demand growth.

Brazil

With the world’s fifth largest country by population and eighth largest economy, Brazil retains strong long-term growth potential despite the near term economic challenges. Electricity demand has sustained an average annual growth rate of approximately 4% over the last 30 years, a trend which is likely to continue in the long-term given that per capita consumption is still less than one-fifth of per capita consumption in the United States. By 2026, Brazil’s energy planning agency projects that around 68,000 MW of new supply will be needed, while only approximately 27,000 MW of capacity is already contracted.  We accordingly expect Brazil will require over 4,600 MW of new supply annually to meet growing demand and renewables will be the main sources to diversify supply, as costs of large-scale hydroelectric projects are rising due to development in remote locations with increasing costs and environmental and labor challenges. 

In line with the government’s ten-year planning projections, the renewable power industry is growing, notably wind power and solar. Brazil has approximately 12,200 MW of installed wind capacity, with 3,700 MW under development. Solar PV power generation is also being developed and while current installed solar PV capacity is relatively small (660 MW), there are approximately 1,800 MW of solar PV capacity under development in Brazil.

We believe there are two additional aspects of the Brazilian market that make our business compelling. First, substantially all of our hydroelectric facilities participate in the MRE which significantly reduces the impact of variations in hydrology on our cash flows. Through this pool, hydroelectric power generators are paid on the basis of “assured energy”, which is based on long-term average generation (established through government-approved hydrological studies) rather than on actual production. Participating generators effectively share hydrology risk as generators experiencing above-average generation conditions make this excess available to those experiencing below-average conditions, with any aggregate shortfall allocated pro-rata across the pool. Second, SHPPs under 30 MW operate in a segment of the market that benefits from certain preferred economic and regulatory rights. Customers that purchase power from these plants benefit from a special discount for the use of the distribution system which, in turn, enables generators like us, since we have 50% of our portfolio contracted with final consumers, to capture a portion of this discount through higher prices with end-use customers.

Europe

Europe is the largest renewable energy market in the world and a significant growth opportunity for our business. Within the European Union, a population of approximately 500 million is served by a power system with a capacity of approximately 1,000 GW, generating approximately 3,100 TWh annually. Renewable generation technologies account for over one third of total installed capacity, including approximately 150 GW of hydroelectric, 150 GW of wind and 100 GW of solar PV capacity. Our investment and growth strategy in Europe focuses on larger, low-sovereign risk markets that have both a record of reliable renewable policies and renewable assets with attractive long-term fundamental value and scarcity attributes.

Page 67

Europe has long been at the forefront in adopting policies to support renewables development and address climate change. For 2020, the E.U. has committed to cutting its greenhouse gas emissions by 20% relative to 1990 levels, and to raising the share of total final energy consumed from renewables to 20%. Brookfield estimates that approximately 45 GW of additional wind-equivalent power capacity is required between 2018-2020 across the E.U. to achieve the 2020 target. In the longer term, the E.U. has recently committed to a 40% reduction in greenhouse gas emissions by 2030 (relative to 1990) and at least a 27% share of renewables in final energy consumption.

Individual member states have sought to meet their binding E.U. targets through incentive programs supporting renewable power development.  The most common incentive structure involves the use of long-term (typically 15 or 20-year) index-linked contracts for differences, as in the case of the United Kingdom and Germany. Most support programs are funded by a levy on retail electricity rates rather than a direct payment from the government.

The E.U.’s carbon emissions cap-and-trade program and national policies like the United Kingdom’s carbon price floor mechanism enhance the competitive position of renewables generators by increasing the operating costs of conventional thermal generators. In addition, conventional generation and especially coal-fired plants face tightening nitrogen oxide and sulfur dioxide limits under the E.U. Industrial Emissions Directive. For older non-compliant coal plants, the majority of which are in the United Kingdom and Spain, this is likely to accelerate retirements. As in the United States, this supply will need to be replaced by new capacity likely in the form of renewable and gas-fired generation. Following a referendum in 2016, the United Kingdom initiated proceedings to leave the European Union. Subsequent trade negotiations will determine the terms of the United Kingdom’s access to the E.U. internal energy market which may include subscribing to similar long-term environmental targets. Regardless of these negotiations, the United Kingdom is expected to maintain its long-term national de-carbonization targets.

Ireland

Ireland has among the best onshore wind resources in Europe, and both the Republic of Ireland and Northern Ireland markets have stable and favorable contractual frameworks for renewables.  Owners of renewable assets in the Republic of Ireland typically benefit from the REFIT program, which ensures that generators receive a minimum fixed annual electricity price, indexed by inflation annually over a contract term of 15 years, providing a revenue stream that is the higher of market prices or the REFIT tariff. The REFIT payments are guaranteed under legislation for eligible assets and currently apply to assets commissioned prior to the end of 2019. The Irish Department of Communications, Energy and Natural Resources is currently working on the design of a new renewable procurement mechanism.  In Northern Ireland, our facilities generally receive both the prevailing market electricity price and a Renewable Obligation Certificate.

Portugal

Portugal offers feed-in-tariff contracts that fix payment terms for the duration of the contract. For contracts awarded in 2006 and 2007, the contract term is the shorter of 15 years or after cumulative generation of 33 GWh per MW of installed capacity. During the EU bailout following the financial crisis the Portuguese government sought to raise funds to reduce its electricity tariff deficit by offering wind generators the option to extend their initial feed-in-tariff period in return for upfront payment. Incentives are also in place for re-powering existing capacity at a lower rate. Continued fiscal consolidation allowed Portugal’s sovereign rating to be upgraded towards the end of 2017 to investment grade with a stable outlook (Fitch and Standard & Poor’s).

Scotland

In Scotland, existing generation is supported via the Renewable Obligation Certificate scheme. A new contract for difference was introduced and first issued via auction in 2015 with recent auctions focusing on less established technologies (such as offshore wind, biomass combined heat and power and energy from waste schemes).  The United Kingdom faces a significant shortfall to meet its overall renewable energy target for 2020. It also has longer-term carbon targets to reduce greenhouse gas emissions by at least 80% from 1990 levels by 2050, with intermediate milestones set out in 5-year carbon budgets (currently set to 2032) and written into law.

Page 68

Other Markets

India and China are markets with significant potential for renewable power development, as the countries seek to satisfy strong demand growth and offset their heavy reliance on coal-fired generation. Persistent air pollution in both countries provides a strong incentive to reduce coal-fired generation and increase reliance on renewable generation. In connection with the acquisition of TerraForm Global, we acquired assets in India and China, and Brookfield Renewable is monitoring opportunities in each of these countries. Assets in Thailand, Malaysia, South Africa and Uruguay were also acquired as part of the acquisition of TerraForm Global.

Other Potential Markets

Australia is a market where Brookfield has a significant real estate and infrastructure presence and where we may invest in the future. Nearly 50% of the 47 GW of installed capacity in Australia’s National Electricity Market is coal-fired. Australia has experienced strong economic growth driven by Asian demand for natural resources, and the country’s carbon footprint is a recurring topic of national debate. We expect support for the development of new renewable power resources to increase over the next decade as policy makers seek to offset the country’s dependence on fossil-fuel based generation.

Our Growth Opportunity 

We believe that the current environment offers attractive opportunities to invest in renewable power acquisitions or developments that we expect will allow us to deploy capital, on an accretive basis, in the following ways:

·Privatizations.  We believe that governments will continue to engage the private sector in providing funding solutions for infrastructure requirements which could increasingly involve sales of existing assets. Our proven operating track record, global scale and ability to partner with local pension funds and institutional investors position us well to participate in such opportunities.

·Asset monetization and divestitures. Significant renewable power generation capacity is owned by industrial companies, smaller independent power producers, private equity investors and foreign companies. These types of owners sell renewable power assets either because power generation is not their core business, their investment horizons are shorter, or a particular market ceases to be strategic. In addition, some large independent power producers may seek, or be forced, to sell assets to bolster their balance sheets. Certain capital constrained or distressed companies may also seek to sell assets.

·Development cycle divestitures. Renewable power assets are often developed or built by smaller developers or construction companies who, in our experience, seek to capture development-stage returns or who have insufficient capital to develop projects. Because of our extensive project development expertise we are well positioned to evaluate these sorts of assets and therefore have been, and believe we will continue to be, a logical acquirer of, or partner in, such projects.

·Brookfield Renewable’s development project portfolio. In addition to growing our business through acquisitions, we intend to pursue organic growth by developing our over 7,000 MW pipeline of greenfield projects.

Revenue and Cash Flow Profile

Our portfolio offers high quality cash flows derived from predominantly hydroelectric assets. Our cash flow profile, which we believe will continue to be highly stable and predictable, is derived from the combination of long-term, fixed-price contracts, a unique hydro-focused portfolio with a low cost structure, and a prudent financing strategy focused on non-recourse debt with an investment grade balance sheet. Accordingly, we believe that we have a high degree of predictability in respect of revenue and costs on a per MWh basis.

Page 69

Our pricing profile is predictable because of our long-term PPAs which have a weighted average remaining duration of 15 years on a proportionate basis. This, combined with a well-diversified portfolio that reduces variability in our generation volumes, enhances the stability of our cash flow profile.

The majority of our long-term PPAs are with investment-grade rated or creditworthy counterparties. The overall composition of our contracted generation under PPAs on a proportionate basis is Brookfield (42%), public power authorities (21%), industrial users (19%) and distribution companies (18%). On a proportionate basis, Brookfield Renewable has contracted 90% of 2018 generation at an average price of $73 per MW.  

As at December 31, 2017, over the next five years Brookfield Renewable has on average approximately 7,071 GWh on a proportionate basis and 18,588 GWh on a consolidated basis of energy annually which is uncontracted. This energy can be sold into wholesale or bilateral markets and we intend to maintain flexibility in re-contracting to position ourselves to achieve optimal pricing.

Page 70

The following table presents, on a proportionate basis, revenues, Adjusted EBITDA and Funds From Operations on a segmented basis for the fiscal years ended December 31, 2017, 2016, and 2015 by hydroelectric, wind and other facilities. Hydroelectric and wind information is further segmented by region.

	Hydroelectric						Wind						Solar		Storage		Other(1)		Corporate		Total
	North						North
(MILLIONS)	America		Colombia		Brazil		America		Europe		Brazil
For the year ended December 31, 2017:
Revenues	$	945	$	191	$	243	$	161	$	46	$	26	$	9	$	43	$	15	$	-	$	1,679
Adjusted EBITDA(2)		665		99		178		119		26		22		7		30		2		(6)		1,142
Funds From Operations(2)		486		52		148		74		15		16		3		17		1		(231)		581
For the year ended December 31, 2016:
Revenues	$	819	$	192	$	187	$	151	$	56	$	17	$	-	$	27	$	31	$	1	$	1,481
Adjusted EBITDA(2)		548		88		130		115		32		13		-		14		17		(15)		942
Funds From Operations(2)		367		46		97		74		18		6		-		3		16		(208)		419
For the year ended December 31, 2015:
Revenues	$	819	$	-	$	203	$	150	$	56	$	9	$	-	$	36	$	23	$	-	$	1,296
Adjusted EBITDA(2)		557		-		164		124		44		8		-		21		7		(18)		907
Funds From Operations(2)		373		-		136		76		32		5		-		17		6		(178)		467

⁽¹⁾Includes Co-gen and biomass

⁽²⁾Non-IFRS measures. See “Cautionary Statement Regarding Use of Non-IFRS Measures”.

Page 71

As described in Item 5.A “Operating Results — Presentation to Stakeholders and Performance Measurement”, Adjusted EBITDA and Funds From Operations do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be similar to measures presented by other companies. For additional information, see Item 5.A “Operating Results — PART 4 – Financial Performance Review on Proportionate Information.”

As at year end, our portfolio benefits from significant hydrology diversification, with assets distributed on 81 river systems in four countries. Our North American, Colombian and European assets have the ability to store water in reservoirs approximating 24% of their annualized long-term average generation. Our assets in Brazil benefit from a framework that levelizes generation risk across hydroelectric producers. The ability to store water in reservoirs in North America, Colombia and Europe as well as benefit from levelized generation in Brazil allows us to mitigate hydrological fluctuations, optimize production and minimize losses due to outages.

North America. In North America, we generate revenues primarily through energy sales secured through long-term PPAs with creditworthy counterparties such as government-owned entities or power authorities (including for example, Ontario’s Independent Electricity System Operator, the Ontario Electricity Financial Corporation, Hydro-Québec, BC Hydro and the Long Island Power Authority), load-serving utilities (such as Entergy Louisiana), Brookfield, and in some cases industrial power users. Our North American portfolio is largely contracted pursuant to long-term PPAs that are generally structured on a “take or pay” basis without fixed or minimum volume commitments. As a result, we are exposed to minimal risk of having to supply power from the market to customers when we are experiencing low water or wind conditions. Most of our PPAs also provide for an annual price escalation that is typically linked to inflation. Brookfield will, in some cases, have entered into back-to-back power resale agreements for output purchased from Brookfield Renewable (see Item 4.B “Business Overview — The Service Provider — Energy Marketing”). Our North American portfolio has a weighted average remaining contract term of 21 years.

Colombia. In Colombia, revenues are typically secured through one to five year bi-lateral contracts with local distribution companies in the “regulated market” and large industrial users. These contracts reduce the exposure of both suppliers and end-users to price volatility in the spot market by fixing the price payable for given amount of committed energy. Isagen’s PPAs take this approach and its 2018 revenues are approximately 70% contracted.  In addition to its hydroelectric assets, Isagen has a 300 MW Co-gen facility which can be used to provide additional generating capacity. 

Brazil. In the Brazilian electricity market, energy is typically sold under long-term contracts to either load-serving distribution companies in the regulated market or smaller “free customers” in the free customer market. In the regulated market we have typically entered into 20 to 30 year PPAs with distribution companies. In the “free customer” market, we have typically entered into three to eight year PPAs with industrial and commercial customers primarily engaged in strong industries like telecommunications, food services and pharmaceuticals. “Free customers” include consumers of electricity with more than 0.5 MW of annual demand. Free customers whose load is between 0.5 MW and 3 MW can only buy power from renewable sources. Our PPAs in Brazil typically provide a fixed price that is fully indexed to inflation annually. Our Brazilian portfolio has a weighted average remaining contract term of approximately 8 years.

Europe. Our European assets are principally located in the Republic of Ireland with additional assets located in Northern Ireland and Portugal. We also have a pipeline of development projects located in Scotland. In the Republic of Ireland, we generate revenues primarily through energy sales secured by long-term PPAs under the REFIT program. In the Republic of Ireland’s electricity market, renewable energy is typically sold under a 15 year REFIT contract which allows for any above-market costs to be paid directly to generators through a levy on final consumer bills. The REFIT tariff also provides generators with potentially attractive upside to market prices above an established contract floor, which would allow us to benefit from any increase in power prices. Our Republic of Ireland operating assets are underpinned by a 9 year remaining average life contracted revenue stream. Our wind farms in Northern Ireland earn British pound sterling denominated revenues by receiving a fixed price Renewable Obligation Certificate for twenty years in addition to the market price.  In Portugal, similar to the Republic of Ireland, assets are contracted are based on an approximately 15 year feed-in-tariff regime and feature a floor and

Page !Unexpected End of Formula

cap price for 7 years after the expiry of the feed-in-tariff. Our Portuguese operating assets are underpinned by a 7 year remaining average life contracted revenue stream.

Our Growth Strategy

We expect to continue focusing on long-life renewable power assets that provide stable, long-term contracted cash flows, or, where uncontracted, are acquired on a value basis and located in high-value power markets where rising power prices offer strong prospects to generate growing cashflows and can appreciate in value over time. We combine our industry, operating, development and transaction execution expertise with our ability to commit capital to transactions in order to secure opportunities at attractive returns for Unitholders. To grow Brookfield Renewable, we maintain a proactive and focused business development program in each of our markets which is augmented by access to Brookfield’s global investment platform that may lead to originating attractive opportunities for investment. We expect that our growth will be focused on the following:

·Acquisitions of assets within core markets. We expect to continue our growth in North America, Colombia, Brazil and Europe, where our existing renewable power businesses allows us to efficiently integrate operating or development-stage renewable power assets and capture economies of scale. Within each of these operating businesses, our growth strategy is focused on the higher-value and higher-growth regional electricity markets.

·Diversification into new markets. We intend to establish an operating presence in new markets that offer attractive opportunities to enhance the geographic diversification of our operations by adding businesses that we can grow over time by investing capital at attractive risk-adjusted returns. With the acquisition of TerraForm Global, we acquired assets in India, China, South Africa, Thailand, Uruguay and Malaysia. Our European business and London-based management team will allow us to continue expanding into Europe beyond our existing portfolios. Additionally, our Brazil experience and team provides an excellent springboard to continue to expand into other South American countries, as was the case when we completed the Isagen Acquisition in early 2016 and the acquisition of TerraForm Global in December 2017. We also benefit from Brookfield’s investment teams in Australasia, India, China and elsewhere that, together with our existing capabilities in North America, South America and Europe, give us the ability to transact on a global basis.

·Organic development growth. We intend to continue to grow our business by pursuing organic development growth, either through the acquisition of development-stage assets or by building projects from our approximate 7,000 MW development pipeline. We intend to focus on development-stage acquisition opportunities that are in high-value sites in our core markets, positioning us to leverage the development, construction and operating expertise of our operating businesses. We expect that a relatively small portion of our cash flows will be allocated during the early stages of project development, but that meaningful capital commitments would be made once a project has sound commercial arrangements that limit construction risk and secures long-term stable cash flows.

·Diversification of renewable power technologies. While we intend to maintain our predominantly hydroelectric focus, we also intend to direct some of our efforts to acquiring select assets using other renewable power technologies that share similar fundamental characteristics to our hydroelectric portfolio of long-life, predictable operating costs and cash flows and sustainable competitive cost advantages. For example, in addition to wind, we have invested in solar generating assets through TerraForm Power and TerraForm Global.

Our LP Unit Distribution Policy

We believe our high-quality assets and long-term PPAs will provide BEP with stable and predictable annual cash flow to fund our distributions on our LP Units:

·In 2013, BEP increased its regular quarterly distribution to $0.3625 ($1.45 annually) per LP Unit commencing with the first quarter distribution of that year.   

Page 73

·In 2014, BEP increased its regular quarterly distribution to $0.3875 ($1.55 annually) per LP Unit commencing with the first quarter distribution of that year.   

·In 2015, BEP increased its regular quarterly distribution to $0.415 ($1.66 annually) per LP Unit commencing with the first quarter distribution of that year.

·In 2016, BEP increased its regular quarterly distribution to $0.445 ($1.78 annually) per LP Unit commencing with the first quarterly distribution of that year. 

·In 2017, BEP increased its regular quarterly distribution to $0.4675 ($1.87  annually) per LP Unit commencing with the first quarterly distribution of that year. 

·In February 2018, BEP announced an increase in its regular quarterly distribution to $0.49 ($1.96 annually) per LP unit commencing with the first quarterly distribution of 2018.

We intend to continue to operate as a growth-oriented entity with a focus on increasing the amount of cash available for distributions on each LP Unit.

The declaration and payment of distributions on our LP Units are subject to the discretion of the board of directors of the Managing General Partner. Distributions on our LP Units will be paid quarterly on the last day of March, June, September and December of each year, to LP Unitholders of record on the last business day of February, May, August and November.  In addition, registered and beneficial LP Unitholders who are resident in Canada or the United States may opt to receive their distributions in either U.S. dollars or the Canadian dollar equivalent, based on the Bank of Canada daily average exchange rate on the applicable record date or, if such record date falls on a weekend or holiday, on the Bank of Canada daily average exchange rate of the preceding business day.Distributions will be evaluated periodically, and may be revised subject to business circumstances and expected capital requirements depending on, among other things, our earnings, financial requirements for our operations, growth opportunities, the satisfaction of applicable solvency tests for the declaration and payment of distributions and other conditions existing from time to time (see Item 10.B “Memorandum and Articles of Association – Description of Our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP — Distributions”). BEP will not be permitted to make a distribution on our LP Units unless all accrued distributions have been paid in respect of the Class A Preferred Units and all other units of BEP ranking prior to or on a parity with the Class A Preferred Units, with respect to the payment of distributions.

Our ability to continue paying or growing cash distributions is impacted by the cash we generate from our operations. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend on various factors, several of which are outside our control, including hydrology and the weather in the jurisdictions in which we operate, the level of certain operating costs and prevailing economic conditions. As a result, cash distributions to the LP Unitholders are not guaranteed. Refer to Item 3.D “Risk Factors — Risks Related to Our Units” for a list of the primary risks that impact our ability to continue paying comparable or growing cash distributions.

We target a long-term payout ratio of approximately 70% of Funds From Operations, allowing us to reinvest surplus cash flow in attractive and accretive opportunities in the renewable power sector and position us to grow our distributions per LP Unit over time.Our long-term LP Unit annual distribution growth rate target is 5% to 9% annually.

Our LP Unit Distribution Reinvestment Plan

In February 2012, BEP adopted a DRIP for LP Unitholders who are residents of Canada. Subject to regulatory approval and U.S. securities law registration requirements, we may in the future expand the DRIP to include LP Unitholders resident in the United States. LP Unitholders who are not residents of Canada or the United States may participate in the DRIP provided that there are not any laws or governmental regulations that prohibit them from participating in the DRIP. The following is a summary description of the principal terms of the DRIP.

Pursuant to the DRIP, Canadian holders of our LP Units are able to elect to have LP Unit distributions automatically reinvested in additional LP Units to be held for the account of the LP Unitholder in accordance with the terms of the DRIP.

Page 74

Distributions due to DRIP participants will be paid to the plan agent, for the benefit of the DRIP participants. If a DRIP participant has elected to have his or her distributions automatically reinvested, or applied to the purchase of additional LP Units, such purchases will be made from BEP on the distribution date at the Market Price.

As soon as reasonably practicable after each distribution payment date, a statement of account will be mailed to each participant setting out the amount of the relevant cash distribution reinvested, the applicable Market Price, the number of LP Units purchased under the DRIP on the distribution payment date and the total number of LP Units, computed to four decimal places, held for the account of the participant under the DRIP (or, in the case of CDS participants, CDS will receive such statement on behalf of beneficial owners participating in the DRIP). While BEP will not issue fractional LP Units, a DRIP participant’s entitlement to LP Units purchased under the DRIP may include a fraction of an LP Unit and such fractional LP Units shall accumulate. A cash adjustment for any fractional LP Units will be paid by the plan agent upon the termination by a DRIP participant of his or her participation in the DRIP or upon termination of the DRIP. A registered holder may, at any time, obtain a Direct Registration System statement (a “DRS Statement”) for any number of whole LP Units held for the participant’s account under the DRIP by notifying the plan agent. DRS Statements for LP Units acquired under the DRIP will not be issued to participants unless specifically requested. Prior to pledging, selling or otherwise transferring LP Units held for a participant’s account (except for a sale of LP Units through the plan agent), a registered holder must request a DRS Statement be issued. The automatic reinvestment of distributions under the DRIP will not relieve participants of any income tax obligations applicable to such distributions. No brokerage commissions will be payable in connection with the purchase of our LP Units under the DRIP and all administrative costs will be borne by BEP.

LP Unitholders can end their participation in the DRIP by giving notice to the plan agent. Such notice, if actually received by the plan agent no later than five business days prior to a record date, will have effect in respect of the distribution to be made as of such date. Thereafter, distributions to such LP Unitholders will be paid directly to the LP Unitholder. In addition, LP Unitholders may request that all or part of their LP Units held under the DRIP in cash be sold. When LP Units are sold through the plan agent, a holder will receive the proceeds less any handling charges and brokerage trading fees. BEP will be able to terminate the DRIP, in its sole discretion, upon notice to the DRIP participants and the plan agent, but such action will have no retroactive effect that would prejudice a participant’s interest. BEP will also be able to amend, modify or suspend the DRIP at any time in its sole discretion, provided that the plan agent gives written notice of that amendment, modification or suspension to our LP Unitholders, for any amendment, modification or suspension to the DRIP that in BEP’s opinion may materially prejudice participants.

BRELP has a corresponding distribution reinvestment plan in respect of distributions made to BEP and Brookfield on its limited partnership units. BEP does not intend to reinvest distributions it receives from BRELP in BRELP’s distribution reinvestment plan except to the extent that holders of our LP Units elect to reinvest distributions pursuant to BEP’s DRIP. Brookfield has advised BEP that it may from time-to-time reinvest distributions it receives from BEP or BRELP pursuant to the DRIP or BRELP’s distribution reinvestment plan. The limited partnership units of BRELP to be issued to Brookfield under the distribution reinvestment plan will become subject to the Redemption-Exchange Mechanism and may therefore result in Brookfield acquiring additional LP Units of BEP. See Item 10.B “Memorandum and Articles of Association – Description of the Amended and Restated Limited Partnership Agreement of BRELP — Redemption–Exchange Mechanism”.

Distributions to Preferred Unitholders

BEP will pay distributions to the holders of its Preferred Units, as and when declared by the board of directors of the Managing General Partner. BEP’s Preferred Units are guaranteed by the Preferred Unit Guarantors under the Preferred Unit Guarantees described under Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”.

The holders of Series 5 Preferred Units are entitled to receive fixed cumulative preferential cash distributions as and when declared by the board of directors of the Managing General Partner, payable

Page 75

quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.3976 per unit. A total annual distribution of C$1.3976 per share was paid in 2017. 

For the initial five-year period commencing on November 25, 2015 and ending on and including January 31, 2021, the holders of Series 7 Preferred Units are entitled to receive fixed cumulative preferential cash distributions as and when declared by the board of directors of the Managing General Partner, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.375 per unit. A total annual distribution of C$1.375 per unit was paid in 2017.

For the initial five-year period commencing on May 25, 2016 and ending on and including July 31, 2021, the holders of Series 9 Preferred Units are entitled to receive fixed cumulative preferential cash distributions as and when declared by the board of directors of the Managing General Partner, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.4375 per unit. A total annual distribution of C$1.4375 per unit was paid in 2017.

For the initial five-year period commencing on February 14, 2017 and ending on and including April 30, 2022, the holders of Series 11 Preferred Units are entitled to receive fixed cumulative preferential cash distributions as and when declared by the board of directors of the Managing General Partner, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.25 per unit. A total annual distribution of C$0.8818 per unit was paid in 2017 and an initial distribution of C$0.2568 per unit was paid on April 30, 2017.

For the initial five-year period commencing on January 16, 2018 and ending on and including April 30, 2023, the holders of Series 13 Preferred Units are entitled to receive fixed cumulative preferential cash distributions as and when declared by the board of directors of the Managing General Partner, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.25 per unit. An initial distribution of C$0.3562 per unit will be payable on April 30, 2018.

BRP Equity

Distributions to Preferred Shareholders

BRP Equity will pay dividends to the holders of its Preferred Shares, as and when declared by the board of directors of BRP Equity. BRP Equity’s Preferred Shares are guaranteed by BEP and the other Preference Share Guarantors under the Preference Share Guarantees described under Item 10.B “Memorandum and Articles of Association — BRP Equity — Preference Share Guarantees”.

For the initial five-year period commencing on May 1, 2015 and ending on and including April 30, 2020, the holders of Series 1 Shares are entitled to receive fixed cumulative preferential cash dividends as and when declared by the board of directors of BRP Equity, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.3125 per share. A total dividend of C$1.3125 per share was paid in each of 2011, 2012, 2013 and 2014, C$1.075625 per share in 2015 and C$0.83875 per share in 2016 and 2017.

In April 2015, certain holders of Series 1 Shares elected to convert their Series 1 Shares into Series 2 Shares on a one-for-one basis. The holders of Series 2 Shares are entitled to receive floating cumulative preferential cash dividends as and when declared by the board of directors of BRP Equity, payable quarterly on the last day of January, April, July and October in each year at the annual rate calculated for each quarter, of 2.62% over the annual yield on three month Government of Canada treasury bills. A total dividend of C$0.39976 per share was paid in 2015 (the conversion to Series 2 Shares occurred in April and accordingly the total 2015 dividend per share reflects two quarterly dividend payments). A total dividend of C$0.773698 per share was paid in 2016 and a total distribution C$0.792786 per share was paid in 2017.

For the initial seven-year period commencing on October 11, 2012 and ending on and including July 31, 2019, the holders of Series 3 Shares are entitled to receive fixed cumulative preferential cash dividends as and when declared by the board of directors of BRP Equity, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.10 per share. The initial dividend of C$0.3375 per share was paid on January 31, 2013, a total dividend of C$1.1625 per share was paid in 2013, C$1.10 per share was paid in each of 2014, 2015, 2016 and 2017.

Page 76

The holders of Series 5 Shares are entitled to receive fixed cumulative preferential cash dividends as and when declared by the board of directors of BRP Equity, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.25 per share. The initial dividend on the Series 5 Shares of C$0.3116 per share was declared by the board of directors of BRP Equity on February 6, 2013 and was paid to holders of the Series 5 Shares on April 30, 2013. A total dividend of C$0.9366 per share was paid in 2013, and a total dividend of C$1.25 per share was paid in each of 2014, 2015, 2016 and 2017.

The holders of Series 6 Shares are entitled to receive fixed cumulative preferential cash dividends as and when declared by the board of directors of BRP Equity, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to C$1.25 per share. The initial dividend on the Series 6 Shares of C$0.3116 per share was declared by the board of directors of BRP Equity on May 7, 2013 and was paid to holders of the Series 6 Shares on July 31, 2013.  A total dividend of C$0.6241 per share was paid in 2013, and a total dividend of C$1.25 per share was paid in each of 2014, 2015, 2016 and 2017.

The Service Provider

Brookfield Asset Management

Brookfield is a global alternative asset manager with more than $285 billion in assets under management. It has an over 100-year history of owning and operating assets with a focus on property, renewable power, infrastructure and private equity. It has a range of public and private investment products and services, which leverage its expertise and experience and provide it with a competitive advantage in the markets where it operates. Brookfield Asset Management is listed on the NYSE, TSX and NYSE Euronext under the symbol “BAM”, “BAM.A” and “BAMA”, respectively.

We are Brookfield’s primary vehicle through which it will acquire renewable power assets on a global basis and we benefit from its reputation and global platform to grow our business.

The Service Provider complements our operating businesses in three key areas:

·Leadership:  The Service Provider provides leadership to our operating businesses and oversees the implementation of our annual and long-term operating plans, capital expenditure plans, and our power marketing plans to ensure compliance with our performance-based operating objectives and applicable laws. The Service Provider also oversees the implementation of our operational policies, and our management, accounting, regulatory reporting, legal and treasury functions.

·Growth:  We also benefit from the strategic advice, transaction origination capabilities and corporate development services of the Service Provider to grow our business. In particular, we benefit from the Service Provider’s renewable power acquisition experience focused in our target markets as well as market research capabilities that support evaluating opportunities to grow our business in existing and new markets.

·Funding:  The Service Provider recommends and oversees the implementation of funding strategies for our existing business and in connection with our acquisitions and development projects. In doing so, the Service Provider advises upon and assists in the execution of our equity and debt financings. The Service Provider also arranges for our tax planning and the filing of our tax returns.

Energy Marketing

BEM LP is responsible for selling all energy and energy related products generated by our assets in North America. In addition, BEM LP acts as counterparty to various agreements with us pursuant to which BEM LP purchases, supports or guarantees the price that we receive for power generation in North America.

With approximately 94 employees and 24 hours/day, 365 days/year operations, BEM LP performs transaction execution, risk management, settlement, information technology, regulatory, legal and human resource functions. These groups provide us with valuable market intelligence regarding pricing

Page 77

dynamics, regulatory regimes and market participants. In 2017, BEM LP was responsible for the sale of approximately 20 TWh of generation in North America.

BEM LP and NA Holdco have entered into the Energy Marketing Agreement pursuant to which BEM LP provides energy marketing services to NA Holdco. See Item 7.B “Related Party Transactions — Energy Marketing Agreement”.

Competition and Marketing

We operate in various North American, South American, European and Asian power markets. The nature and extent of competition we face varies from jurisdiction to jurisdiction. Brookfield Renewable’s main competition in its electricity markets are coal, nuclear, oil and natural gas electricity generators as well as other renewable energy suppliers who use hydro, wind, geothermal and solar PV technologies. The market price of commodities, such as natural gas and coal, are important drivers of energy pricing and competition in most energy markets, especially in North America.

Our marketing efforts focus on leveraging our competitive advantages described in Item 4.B “Business Overview” and our world class operating businesses described in Item 4.B “Business Overview — Operating Philosophy”.

We also leverage our relationship with Brookfield, which we believe provides a unique competitive advantage considering Brookfield’s strong reputation in the energy marketing, asset management, infrastructure and global real estate industries. See Item 7.B “Related Party Transactions — Licensing Agreement”.

Employees

Members of Brookfield Renewable’s core senior management team are all employees of Brookfield, and their services are provided for the benefit of Brookfield Renewable under the Master Services Agreement. For a discussion of the individuals from Brookfield’s management team that are expected to be involved in our business, see Item 6.A. “Directors and Senior Management — Our Management” and for a discussion of our employees see Item 6.D “Employees”.

Intellectual Property

Brookfield Renewable, as licensee, entered into the Licensing Agreement with Brookfield pursuant to which Brookfield granted us a non-exclusive, royalty-free license to use the name “Brookfield” and the Brookfield logo worldwide. Other than under this limited license, we do not have a legal right to the “Brookfield” name and the Brookfield logo. Brookfield may terminate the Licensing Agreement immediately upon termination of our Master Services Agreement and it may be terminated in the circumstances described under Item 7.B “Related Party Transactions — Licensing Agreement”.

Governmental, Legal and Arbitration Proceedings

We have not been and are not currently subject to any material governmental, legal or arbitration proceedings which may have or have had a significant impact on our financial position or profitability nor are we aware of any such proceedings that are pending or threatened.

We are occasionally named as a party in various claims and legal proceedings which arise during the normal course of our business. With respect to claims and proceedings, we review each of these matters, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. Although there can be no assurance as to the resolution of any particular matter, we do not believe that the outcome of any matters or potential matters of which we are currently aware will have a material adverse effect on us.

Regulation

Various activities of Brookfield Renewable require registrations, permits, licenses, inspections and approvals from governmental agencies and regulatory authorities and we strive to comply with all regulations applicable to our operations. Water rights are generally owned or controlled by governments that reserve the right to control water levels or may impose water-use requirements. We hold concessions, licenses and permits to operate our facilities, which generally include rights to the land and

Page 78

water required for power generation. Wholesale market structures or rules provide us with rights to access the power grid.

We are also subject to various laws and regulations relating to health, safety, security and environmental matters. These laws and regulations may change and we may become subject to more stringent laws and regulations in the future. Compliance with more stringent laws and regulations could have an adverse effect on our business, financial condition or results of operations. We have established policies and procedures for environmental management and compliance, and we have incurred and will continue to incur significant capital and operating expenditures to comply with health, safety, security and environmental laws and to obtain and comply with licenses, permits and other approvals and to assess and manage potential liability exposure. See also information contained under Item 3.D “Risk Factors — Risks Related to our Operations and the Renewable Power Industry”.

Environmental Protection and Corporate Social Responsibility

We are an owner and operator of a diversified portfolio of high quality assets that produce electricity from renewable resources. Our assets are predominantly hydroelectric and represent one of the most environmentally preferred forms of power generation. We may benefit from future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of greenhouse gases to address climate change.

Our goal is to be responsible stewards of our resources and a good corporate citizen. We have adopted written environmental policies that include frameworks for oversight, compliance, compliance audits and sharing best practices both within our operations and the global Brookfield group. We require all employees, contractors, agents and others involved in our operations to comply with our established environmental practices. We seek to have transparent and well-established relationships with local stakeholder groups and the communities in which we operate, which we believe is a key element of successfully operating and developing renewable power facilities. We consult and work proactively with local stakeholders and communities potentially affected by our operations.

Over 50 of our North American hydro facilities are now certified by the Low Impact Hydropower Institute (“LIHI”). The LIHI is a non-profit organization dedicated to reducing the impact of hydropower generation through the certification of hydropower projects that have avoided or reduced their environmental impacts, such as water quality protection, upstream and downstream fish passages, and threatened and endangered species protection.

We are an active contributor in the communities where we conduct business. We are proud of the commitment we have made to corporate social responsibility. The initiatives we undertake and the investments we make in building our business are guided by our core set of values around sustainable development, as we create a culture and organization that we believe can be successful today and in the future.

4.C              ORGANIZATIONAL STRUCTURE

Organizational Chart

The simplified chart below presents a summary of our ownership and organizational structure. Please note that on this chart all interests are 100% unless otherwise indicated. “GP Interest” denotes a general partnership interest and “LP Interest” denotes a limited partnership interest. BEP’s sole material asset is a 58% LP Interest in BRELP and preferred limited partnership interests in BRELP. Brookfield indirectly holds the remaining 41% LP Interest in BRELP, a 31% LP Interest in BEP and a 0.01% and 1% GP Interest in BEP and BRELP, respectively, for an aggregate indirect ownership interest in BEP of approximately 60% on a fully-exchanged basis. For more details on the exchange mechanism see Item 10.B “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Redemption-Exchange Mechanism”. Brookfield’s indirect 1% GP Interest in BRELP entitles it to receive incentive distributions linked to the growth of BRELP’s distributions. This simplified chart should be read in conjunction with the explanation of our ownership and organizational structure below and the information included under Item 6.A “Directors and Senior Management” and Item 7. “Major Shareholders and Related Party Transactions”.

Page 79

Page 80

Page 81

Brookfield Renewable Partners L.P.

BEP is a Bermuda exempted limited partnership that was established on June 27, 2011 under the provisions of the Exempted Partnerships Act 1992 of Bermuda and the Limited Partnership Act 1883 of Bermuda. Our registered and head office is 73 Front Street, 5th Floor, Hamilton HM 12, Bermuda, and the telephone number is 441-294-3304. On May 3, 2016, BEP changed its name from Brookfield Renewable Energy Partners L.P. to Brookfield Renewable Partners L.P.

BEP’s sole material asset is its limited partnership interest in BRELP. BEP anticipates that the only distributions we will receive in respect of its limited partnership interests in BRELP will consist of amounts to assist us in making distributions to our LP Unitholders in accordance with our distribution policy, to our Preferred Unitholders in accordance with the terms of our Preferred Units and to allow us to pay expenses as they become due. The declaration and payment of cash distributions by BEP is at the discretion of the Managing General Partner which is not required to make such distributions. In addition, BEP will not be permitted to make a distribution on our LP Units unless all accrued distributions have been paid in respect of the Class A Preferred Units and all other units of BEP ranking prior to or on a parity with the Class A Preferred Units. See Item 4.B “Business Overview — Our LP Unit Distribution Policy”.

The Service Provider and Brookfield

The Service Recipients have engaged the Service Provider, an affiliate of Brookfield, to provide management and administration services pursuant to our Master Services Agreement. See Item 4.B “Business Overview — The Service Provider” and Item 6.A “Directors and Senior Management — Our Master Services Agreement” for more information on Brookfield and these arrangements.

The Managing General Partner

The Managing General Partner serves as BEP’s general partner and has sole authority for the management and control of BEP, which is exercised exclusively by its board of directors. BEP’s only interest in BRELP consists of limited partnership and preferred limited partnership interests, which by law do not entitle the holders thereof to participate in partnership decisions. Pursuant to the Voting Agreement, however, BEP, through the Managing General Partner, has a number of voting rights, including the right to direct all eligible votes in the election of the directors of the BRELP General Partner. See Item 10.B “Memorandum and Articles of Association — Description of Our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP” and Item 7.B “Related Party Transactions — Voting Agreement”.

BRELP and the Holding Entities

BEP indirectly holds its interests in the Operating Entities through BRELP and through the Holding Entities. BRELP owns all of the common shares of the Holding Entities. Brookfield has provided an aggregate of $5 million of working capital to LATAM Holdco through a subscription for shares of LATAM Holdco. These shares are entitled to receive a cumulative preferential dividend equal to 6% of their redemption value as and when declared by the board of directors of LATAM Holdco and will be redeemable at the option of LATAM Holdco, subject to certain limitations, at any time after the tenth anniversary of their issuance. The shares are not entitled to vote, except as required by law.

BRELP GP LP and the BRELP General Partner

The BRELP GP LP serves as the general partner of BRELP and has sole authority for the management and control of BRELP. The general partner of BRELP GP LP is the BRELP General Partner, a corporation owned indirectly by Brookfield but controlled by BEP, through the Managing General Partner, pursuant to the Voting Agreement. See Item 7.B “Related Party Transactions — Voting Agreement”. BRELP GP LP is entitled to receive incentive distributions from BRELP as a result of its ownership of the general partnership interests of BRELP. See Item 7.B “Related Party Transactions — Incentive Distributions”.

See also the information contained in this Form 20-F under Item 3.D “Risk Factors — Other Risks Related to BEP” and Item 3.D “Risk Factors — Risks Related to our Relationship with Brookfield”, Item 6.A “Directors and Senior Management”, Item 7.B “Related Party Transactions” and Item 10.B

Page 82

“Memorandum and Articles of Association—Description of Our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”, Item 10.B “Memorandum and Articles of Association—Description of the Amended and Restated Limited Partnership Agreement of BRELP”, and Item 7.A “Major Shareholders”.

BRP Equity

BRP Equity is an indirect wholly-owned subsidiary of BEP incorporated under the CBCA on February 10, 2010. Other than a receivable from an indirect wholly-owned subsidiary of BEP, BRP Equity has no significant assets or liabilities, no subsidiaries and no operations of its own. BRP Equity has C$136,241,875 Series 1 Shares outstanding, guaranteed by the Preference Share Guarantors. The Series 1 Shares are listed on the TSX under the symbol “BRF.PR.A”. BRP Equity has C$112,759,725 of Series 2 Shares outstanding, guaranteed by the Preference Share Guarantors. The Series 2 Shares are listed on the TSX under the symbol “BRF.PR.B”.  BRP Equity has C$249,034,975 of Series 3 Shares outstanding, guaranteed by the Guarantors. The Series 3 Shares are listed on the TSX under the symbol “BRF.PR.C”. BRP Equity has C$102,862,600 of Series 5 Shares outstanding, guaranteed by the Preference Share Guarantors. The Series 5 Shares are listed on the TSX under the symbol “BRF.PR.E”. BRP Equity has C$175,000,000 of Series 6 Shares, which are guaranteed by the Preference Share Guarantors and are listed on the TSX under the symbol “BRF.PR.F”. See Item 10.B “Memorandum and Articles of Association — BRP Equity”. 

Finco

Finco is an indirect wholly-owned subsidiary of BEP incorporated under the ABCA on September 14, 2011. On May 3, 2016, Finco changed its name from Brookfield Renewable Energy Partners ULC to Brookfield Renewable Partners ULC. Other than approximately C$2.1 billion aggregate principal amount of publicly-issued Finco Bonds and notes and a receivable from an indirect wholly-owned subsidiary of BEP, Finco has no significant assets or liabilities, no subsidiaries and no operations of its own. The Finco Bonds are guaranteed by the Finco Bond Guarantors. See Item 10.B “Memorandum and Articles of Association”.

Inter-Corporate Relationships

The following table provides the name, the percentage of voting securities owned, or controlled or directed, directly or indirectly, by us, and the jurisdiction of incorporation, continuance, formation or organization of our significant subsidiaries as at December 31, 2017.

Page 83

	Jurisdiction of	Percentage of
	Incorporation	Voting Securities
Name of Subsidiary	or Organization	Owned or Controlled
Alta Wind VIII LLC	Delaware	100.0% (1)
BIF II Safe Harbor Holdings LLC	Delaware	100.0% (1)
BIF III Holtwood LLC	Delaware	100.0% (1)
BRE GLBL Holdings L.P.	Bermuda	100.0% (1)
BRI Green Energy Limited	Republic of Ireland	100.0% (1)
Brookfield BRP Canada Corp.	Alberta	100.0%
Brookfield Energia Comercializadora Ltda	Brazil	100.0%
Brookfield Power US Holding America Co.	Delaware	100.0%
Brookfield Power Wind Prince LP	Ontario	100.0%
Brookfield Renewable UK Hydro Limited	England and Wales	100.0% (1)
Brookfield Smoky Mountain Hydropower LLC	Delaware	100.0% (1)
Brookfield White Pine Hydro LLC	Delaware	100.0% (1)
Catalyst Old River Hydroelectric Limited Partnership	Louisiana	75.0% (2)
Erie Boulevard Hydropower, L.P.	Delaware	100.0%
Granite Reliable Power, LLC	Delaware	89.5% (1)
Great Lakes Hydro America, LLC	Delaware	100.0%
Great Lakes Power Limited	Ontario	100.0%
Hawks Nest Hydro LLC	Delaware	100.0%
Isagen S.A. E.S.P	Colombia	99.5%
Itiquira Energética S.A.	Brazil	100.0%
Kwagis Power Limited Partnership	British Columbia	75.0%
Lièvre Power L.P.	Québec	100.0%
Mississagi Power Trust	Québec	100.0%
Orion Canadian Holdings 1 AIV L.P.	Ontario	100.0%
PEA - Parque Eólico da Serra, Unipessola S.A.	Portugal	100.0%
Powell River Energy Inc.	Canada	100.0%
Rumford Falls Hydro LLC	Delaware	100.0%
Safe Harbor Water Power Corporation	Pennsylvania	100.0% (1)
Tangará Energia S.A.	Brazil - São Paulo	100.0% (1)
Windstar Energy, LLC	California	100.0%
2016 Comber Wind Limited Partnership	Ontario	100.0%

⁽¹⁾Voting control held through voting agreements with Brookfield.

⁽²⁾Non-voting economic interest held through preferred shares and secured notes.

Page 84

4.D              PROPERTY, PLANT AND EQUIPMENT

BEP’s registered and head office is located at 73 Front Street, 5th Floor, Hamilton HM 12, Bermuda. BEP does not directly own any real property and its sole material asset is a 58% limited partnership interest in BRELP and preferred limited partnership interests in BRELP. See also the information contained in this Form 20-F under Item 3.D “Risk Factors—Risks Related to Our Operations and the Renewable Power Industry” and Item 5. “Operating and Financial Review and Prospects”.

ITEM 4A.     UNRESOLVED STAFF COMMENTS         

Not applicable.

ITEM 5.            OPERATING AND FINANCIAL REVIEW AND PROSPECTS

5.a                   OPERATING RESULTS

Basis of Presentation

Brookfield Renewable’s financial statements are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), which require estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as at the date of the financial statements and the amounts of revenue and expense during the reporting periods.

Certain comparative figures have been reclassified to conform to the current year’s presentation.

Organization of the Management’s Discussion and Analysis

PART 1 – 2017 Highlights	86	PART 6 - Selected Quarterly Information
PART 2 – Financial Performance Review on		Summary of historical quarterly results	128
Consolidated Information	89	Proportionate Results for the Fourth Quarter	129
PART 3 – Additional Consolidated Financial
Information
Property, plant and equipment	91
Related party transactions	91	PART 7 - Business Risks and Risk Management
Equity	93	Risk management and financial instruments	131
PART 4 – Financial Performance Review on
Proportionate Information	95	PART8 - Critical Estimates, Accounting Policies and	134
Proportionate Results for the year	98	Internal Controls
ended December 31, 2017 and 2016
Proportionate Results for the year	105	PART 9 - Presentation to Stakeholders and	139
ended December 31, 2016 and 2015		Performance Measurement
Reconciliation of non-IFRS measures	111
Contract profile	118
PART 5 – Liquidity and Capital Resources
Capitalization, long-term borrowings and
available liquidity	120
Consolidated statements of cash flows	124
Shares and units outstanding	126
Dividends and distributions	127
Contractual obligations	127
Off-statement of financial position arrangements	127

Page 85

PART 1 –  2017 HIGHLIGHTS

YEAR ENDED DECEMBER 31
(MILLIONS, EXCEPT AS NOTED)		2017	2016
Operational information
Capacity (MW)		16,369	10,731
Total generation (GWh)
	Long-term average generation	42,334	38,982
	Actual generation	43,385	34,071
Proportionate generation (GWh)
	Long-term average generation	23,251	22,362
	Actual generation	23,968	20,222
	Average revenue ($ per MWh)	70	73
Selected financial information(1)
Net Loss attributable to Unitholders		(56)	(65)
Basic loss per LP Unit		(0.18)	(0.23)
Consolidated Adjusted EBITDA(2)		1,751	1,499
Proportionate Adjusted EBITDA(2)		1,142	942
Funds From Operations(2)		581	419
Adjusted Funds From Operations(2)		513	352
Funds From Operations per Unit(1)(2)		1.90	1.45
Distribution per LP Unit		1.87	1.78

⁽¹⁾Holders of the GP interest, Redeemable/Exchangeable partnership units, and LP Units will be collectively referred to throughout as “Unitholders”, “Units”, or as “per Unit”. The LP Units and Redeemable/Exchangeable partnership units have the same economic attributes in all respects. For the year ended December 31, 2017, weighted average LP Units, Redeemable/Exchangeable partnership units and GP interest totaled 305.8 million (2016: 288.7 million).

⁽²⁾Non-IFRS measures. For reconciliations to the most directly comparable IFRS measure. See “Cautionary Statement Regarding Use of Non-IFRS Measures” and “PART 4 - Financial Performance Review on Proportionate Information - Reconciliation of Non-IFRS Measures”.

AS AT DECEMBER 31
(MILLIONS, EXCEPT AS NOTED)			2017		2016
Liquidity and Capital Resources
Available liquidity		$	1,539	$	1,191
Debt to capitalization(1)			39%		38%
Borrowings non-recourse to Brookfield Renewable(1)			70%		69%
Floating rate debt exposure(1)			13%		18%
Corporate borrowings
	Average debt term to maturity		6.4 years		7.4 years
	Average interest rate		4.5%		4.5%
Subsidiary borrowings on a proportionate basis(1)
	Average debt term to maturity	10.5 years			9.5 years
	Average interest rate		5.8%		6.1%

⁽¹⁾For 2017, adjusted to reflect the financing initiatives, associated with a hydroelectric and a storage facility, finalized subsequent to year-end.

Page 86

Operating Results

Net loss attributable to Unitholders of $56 million decreased from $65 million in the prior year as the increase in Funds From Operations was partially offset by the impact of a significant deferred tax expense as a result of the recently enacted U.S. Tax Cuts and Jobs Act enacted at the end of 2017 (“U.S. tax reform”). The Basic loss per LP Unit of $0.18 per LP Unit decreased from a loss of $0.23 per LP Unit in the prior year primarily due to the above mentioned decrease in Net loss attributable to Unitholders.

Funds From Operations increased 39% to $581 million supported by return to proportionate long-term average generation, advancement of our organic initiatives and contributions from new investments and acquisitions.

Funds From Operations per Unit of $1.90 increased 31% from the prior year.

Proportionate generation increased by 19% to 23,968 GWh over the prior year due primarily to strong hydrological conditions in North America and Colombia. In the current year, we were ahead of proportionate long-term average generation by 3% compared to 2016 where we were 10% below.

In 2017, we deployed approximately $625 million of equity in new transactions and development, that provide approximately an additional 2.1 TWh of proportionate generation and $95 million of Funds From Operations on a run-rate basis (contributed approximately 415 GWh and $18 million of generation and Funds From Operations, respectively, in 2017):

·$232 million for TerraForm Global, a 952 MW portfolio of recently constructed and contracted solar and wind assets, which includes 33 MW of assets in South Africa that are soon to be acquired;

·$221 million for TerraForm Power which is a 2,600 MW diversified portfolio of solar and wind assets located primarily in the United States;

·$73 million in a pumped storage facility in the U.K. with generating capacity of 2.1 GW, Brookfield Renewable retains an approximate 7.5% interest; and

·$98 million in development.

Equity transactions

In 2017, distributions to LP Unitholders were $1.87 per LP Unit, which represents a 5% increase over the prior year.  Including a full year contribution from acquisitions and development projects, this represents a 92% payout ratio.

During the year we completed the following:

·Issued Preferred LP Units for gross proceeds of C$250 million ($190 million);

·Issued LP Units at a price of C$42.15 per LP Unit. Concurrently, Brookfield purchased LP Units in a private placement. The aggregate gross proceeds received were C$550 million ($422 million).

Subsequent to the year-end, we completed an additional Preferred LP Unit issuance for gross proceeds of C$250 million ($201 million).

Liquidity and Capital Resources

Liquidity remains strong with $1.5 billion available at year-end.

Secured $3.1 billion of long-term debt at average rates of 4.5% reducing our floating rate exposure to 13% and extending our average term to maturity to 10 years.

Growth and Development

We continue to advance the construction, on scope, schedule and budget, of 77 MW of hydroelectric development projects in Brazil and 47 MW of wind projects in Ireland and Scotland. These projects have annualized long-term average generation of 456 GWh and 154 GWh, respectively, with

Page 87

commissioning dates expected between 2018 and 2020 and we expected to generate Funds From Operations on a run-rate basis of $20 million.

Page 88

PART 2 –  FINANCIAL PERFORMANCE REVIEW ON CONSOLIDATED INFORMATION

The following table reflects key financial data for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)		2017		2016		2015
Revenues	$	2,625	$	2,452	$	1,628
Other income		47		64		122
Direct operating costs		(978)		(1,038)		(552)
Management service costs		(82)		(62)		(48)
Interest expense – borrowings		(632)		(606)		(429)
Depreciation		(782)		(781)		(616)
Current income tax expense		(39)		(44)		(18)
Deferred income tax (expense) recovery		(49)		97		78
Net (loss) income attributable to Unitholders	$	(56)	$	(65)	$	3
	Average FX rates to USD
C$		1.30		1.33		1.28
€		0.89		0.90		0.90
R$		3.19		3.49		3.33
£		0.78		0.74		0.65
COP		2,951		3,045		N/A

Current Year Variance Analysis (2017 vs 2016)

For the year ended December 31, 2017, we reported a net loss attributable to Unitholders of $56 million compared to a net loss attributable to Unitholders of $65 million for the year ended December 31, 2016.

Revenues totaling $2,625 million in the year ended December 31, 2017 represents an increase of $173 million over the prior year, driven primarily by a return to long-term average generation, and the contribution from our growth initiatives. Revenues increased $121 million as consolidated generation increased by 27% or 9.3 TWh due primarily to strong hydrological conditions in North America and Colombia.  Our recent growth initiatives contributed 3.8 TWh in generation which amounted to $100 million in revenues. Partially offsetting those increases was a decrease in our average realized revenue per MWh (from $72 per MWh to $61 per MWh) driving a $57 million decrease in revenue, as weaker pricing in Colombia due to average above inflows was partially offset by strong pricing in Brazil caused by the impact of low hydrology. The depreciation of the U.S. dollar versus most of the foreign currencies in which we operate contributed an additional $57 million of revenues. This also affected operating and borrowing costs. The above noted increase in revenues, was partially offset by the impact of the sale of one of our Irish wind facilities in the first quarter of 2017 (contributed $28 million in revenues in the prior year). The prior year included a $20 million settlement at our hydroelectric and Co-gen assets in Ontario pertaining to the price escalator for power sold under power purchase agreements.

Other income decreased by $17 million primarily due to a $23 million gain realized on the settlement of foreign currency hedging contracts in the prior year.

Direct operating costs totaling $978 million represent a decrease of $60 million. The decrease was primarily attributable to the reduction in power purchases in Colombia and the successful recovery of excess property taxes at one of our Canadian hydroelectric facilities that were paid in prior years.  This decrease was partially offset by growth in our portfolio.

Management service costs totaling $82 million represent an increase of $20 million, primarily attributable to the growth in our capitalization due to a 16% increase in Brookfield Renewable’s unit price.

Interest expense totaling $632 million represents an increase of $26 million. The increase is primarily attributable to the growth in our portfolio which contributed $22 million of additional interest expense.

Page 89

Deferred income tax expense of $49 million represents a $146 million increase from the prior year, due primarily to the U.S. tax reform.

Prior Year Variance Analysis (2016 vs 2015)

For the year ended December 31, 2016, we reported a net loss attributable to Unitholders of $65 million compared to a net income attributable to Unitholders of $3 million for the year ended December 31, 2015.

Revenues totaling $2,452 million represents an increase of $824 million. Relatively lower merchant power prices primarily in the Northeastern United States were partially offset by the annual escalations in our power purchase agreements and contributions from facilities with higher relative pricing for a $10 million net impact to revenues. At our Brazilian hydroelectric portfolio, relatively lower merchant power prices were partially offset by stronger generation for a net impact of $24 million. The appreciation of the U.S. dollar in 2016, compared to 2015, resulted in a $27 million decrease in revenues. This also affected operating and borrowing costs. The contribution to revenues from the growth in our portfolio was $882 million. Revenues in 2016 include a $20 million settlement pertaining to the price escalator for power sold under power purchase agreements in Ontario and $6 million in proceeds from a wake impact agreement with neighboring wind facilities in California. Revenues in 2015 included $10 million from the settlement of matters related to the delayed completion of a hydroelectric facility in Brazil. In addition, revenues relating to a wind facility sold in the third quarter of 2015 had contributed $13 million. The sale resulted in a total gain of $53 million with Brookfield Renewable’s share, net of non-controlling interests, of $12 million included in Other income.

Other income totaling $64 million represents a decrease of $58 million. The gain realized relating to the wind facility sale mentioned above along with compensation from a concession agreement impacted 2015. These were partially offset by increased interest income due to higher cash balances held throughout 2016.

Direct operating costs, interest expense and depreciation expense increased over the prior year primarily due to the growth in our portfolio.

Management service costs totaling $62 million represent an increase of $14 million, primarily attributable to the growth in our capitalization value.

Current income tax totaling $44 million represents an increase of $26 million, primarily relating to the acquisition in Colombia.

Deferred income tax recovery totaling $97 million represents an increase of $19 million, primarily attributable to lower income for tax purposes.

Page 90

PART 3 - ADDITIONAL consolidated FINANCIAL INFORMATION 

SUMMARY CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

The following table provides a summary of the key line items on the audited annual consolidated statements of financial position as at December 31:

(MILLIONS)	2017		2016
Current assets	$	1,666	$	907
Property, plant and equipment, at fair value		27,096		25,257
Goodwill		901		896
Total assets		30,904		27,737
Long-term debt and credit facilities		11,766		10,182
Deferred income tax liabilities		3,588		3,802
Total liabilities		16,622		15,065
Total equity		14,282		12,672
Total liabilities and equity		30,904		27,737

Our balance sheet remains strong and reflects the stable nature of the business and the integration of recent growth. 

property, plant and equipment

The fair value of property, plant and equipment totaled $27.1 billion as at December 31, 2017 compared to $25.2 billion as at December 31, 2016. During the year ended December 31, 2017, acquisitions of TerraForm Global and Shantavny totaled $1,245 million. The development and construction of power generating assets totaled $354 million. The 137 MW wind portfolio disposed in the first quarter of this year had a fair value of $338 million. Fair value of the operating property, plant and equipment increased by $854 million primarily recapturing depreciation on our hydro facilities and offsetting impact from changes in power prices and discount rates. The depreciation of the U.S. dollar increased property, plant and equipment by $506 million and was largely attributable to assets in Canada and Europe as the Canadian dollar appreciated 6% and Euro appreciated 12% over the same period of the previous year. We also recognized depreciation expense of $782 million which is significantly higher than what we are required to reinvest in the business as sustaining capital expenditures. 

See Note 12 – Property, plant and equipment, at fair value in our audited annual consolidated financial statements for information on the fair value revaluation assumptions used and sensitivity analysis.

Related Party Transactions

Brookfield Renewable’s related party transactions are in the normal course of business, and are recorded at the exchange amount. Brookfield Renewable’s related party transactions are primarily with Brookfield.

Brookfield Renewable sells electricity to Brookfield through long-term PPAs to provide contracted cash flow and reduce Brookfield Renewable’s exposure to electricity prices in deregulated power markets. Brookfield Renewable also benefits from a wind levelization agreement with Brookfield which reduces the exposure to the fluctuation of wind generation at certain facilities and thus improves the stability of its cash flow.

Page 91

In addition to these agreements, Brookfield Renewable and Brookfield have executed other agreements that are described in Note 27 - Related Party Transactions in our audited annual consolidated financial statements.

Brookfield Renewable has also entered into a number of voting agreements with Brookfield whereby Brookfield, as managing member of entities related to Brookfield Americas Infrastructure Fund, Brookfield Infrastructure Fund II and Brookfield Infrastructure Fund III, in which Brookfield Renewable holds investments in power generating operations with institutional partners, agreed to provide to Brookfield Renewable the authority to direct the election of the Boards of Directors of such entities.

Brookfield Renewable has entered into agreements with Brookfield Americas Infrastructure Fund, Brookfield Infrastructure Fund II, Brookfield Infrastructure Fund III and Brookfield Infrastructure Debt Fund (“Private Funds”), in which they provide Brookfield Renewable with access to short-term financing using the Private Funds’ credit facilities.

During the year, the committed unsecured revolving credit facility provided by Brookfield Asset Management was increased to $400 million. Brookfield Asset Management had also placed funds on deposit with Brookfield Renewable in the amount of $140 million during the first quarter of the current year, which was repaid prior to the end of the first quarter. The interest expense on the draws from the credit facility and the deposit totaled $1 million.   

In 2011, on formation of Brookfield Renewable, Brookfield Asset Management transferred certain development projects to Brookfield Renewable for no upfront consideration but is entitled to receive variable consideration on commercial operation or sale of these projects. During the year, an amount of $8 million has been paid relating to the commissioning of a 25 MW hydroelectric facility in Brazil.

The following table reflects the related party agreements and transactions in the audited annual consolidated statements of income, for the year ended December 31:

(MILLIONS)			2017		2016		2015
Revenues
	Power purchase and revenue agreements	$	601	$	527	$	469
	Wind levelization agreement		6		8		6
		$	607	$	535	$	475
Direct operating costs
	Energy purchases	$	(13)	$	(3)	$	(5)
	Energy marketing fee		(24)		(23)		(22)
	Insurance services		(19)		(20)		(30)
		$	(56)	$	(46)	$	(57)
Management service costs		$	(82)	$	(62)	$	(48)

Page 92

The following table reflects the impact of the related party agreements and transactions on the consolidated balance sheets as at December 31:

(MILLIONS)			Related party		2017		2016
Current assets
Due from related parties
	Amounts due from		Brookfield	$	54	$	47
			Equity-accounted investments and other		6		7
				$	60	$	54
Current liabilities
Due to related parties
	Amount due to		Brookfield	$	48	$	48
	Accrued distributions payable on LP
		Units and Redeemable/Exchangeable
		partnership units	Brookfield		32		26
	Amount due to		Equity-accounted investments and other		32		2
				$	112	$	76

EQUITY

General partnership interest in a holding subsidiary held by Brookfield

Brookfield, as the owner of the 1% GP interest in BRELP, is entitled to regular distributions plus an incentive distribution based on the amount by which quarterly LP Unit distributions exceed specified target levels. To the extent that LP Unit distributions exceed $0.375 per LP Unit per quarter, the incentive is 15% of distributions above this threshold. To the extent that LP Unit distributions exceed $0.4225 per LP Unit per quarter, the incentive distribution is equal to 25% of distributions above this threshold. Incentive distributions of $30 million were declared during the year ended December 31, 2017 (2016: $19 million).

Preferred limited partners’ equity

On February 14, 2017, Brookfield Renewable issued 10,000,000 Class A, Series 11 Preferred Limited Partnership Units (the “Series 11 Preferred Units”) at a price of C$25 per unit for gross proceeds of C$250 million ($190 million). The holders of the Series 11 Preferred Units are entitled to receive a cumulative quarterly fixed distribution yielding 5.0% for the initial period ending April 30, 2022. Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5-year Government of Canada bond yield plus 3.82%, and (ii) 5.00%.

The holders of Series 11 Preferred Units will have the right, at their option, to reclassify their Series 11 Preferred Units into Class A Preferred LP Units, Series 12 (the “Series 12 Preferred Units”), subject to certain conditions on April 30, 2022 and on April 30 every five years thereafter. The holders of Series 12 Preferred Units will be entitled to receive floating rate cumulative preferential cash distributions equal to the sum of the 90-day Canadian Treasury Bill Rate plus 3.82%.

The Preferred LP Units do not have a fixed maturity date and are not redeemable at the option of the holders. As at December 31, 2017, none of the Class A Preferred LP Units have been redeemed by Brookfield Renewable.

In January 2018, Brookfield Renewable issued 10,000,000 Class A, Series 13 Preferred Limited Partnership Units (the “Series 13 Preferred Units”) at a price of C$25 per unit for gross proceeds of C$250 million ($201 million). The holders of the Series 13 Preferred Units are entitled to receive a cumulative quarterly fixed distribution yielding 5.0% for the initial period ending April 30, 2023. Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5-year Government of Canada bond yield plus 3.00%, and (ii) 5.00%.

Page 93

The holders of Series 13 Preferred Units will have the right, at their option, to reclassify their Series 13 Preferred Units into Class A Preferred Limited Partnership Units, Series 14 (the “Series 14 Preferred Units”), subject to certain conditions, on April 30, 2023 and on April 30 every five years thereafter. The holders of Series 14 Preferred Units will be entitled to receive floating rate cumulative preferential cash distributions equal to the 90-day Canadian Treasury Bill Rate plus 3.00%.

Limited partners’ equity

On July 6, 2017, Brookfield Renewable completed the issuance of 8,304,000 non-voting LP Units on a bought deal basis at a price of C$42.15 per LP Unit for gross proceeds of C$350 million ($271 million). Concurrently, Brookfield Asset Management purchased 4,943,000 LP Units at the offering price (net of underwriting commission). The aggregate gross proceeds of the offering and the concurrent private placement was C$550 million ($422 million). Brookfield Renewable incurred C$15 million ($11 million) in related transaction costs inclusive of fees paid to underwriters.

Brookfield Asset Management owns, directly and indirectly 185,727,567 LP Units and Redeemable/Exchangeable partnership units, representing approximately 60% of Brookfield Renewable on a fully-exchanged basis and the remaining approximate 40% is held by public investors.

Page 94

PART 4 – FINANCIAL PERFORMANCE REVIEW ON PROPORTIONATE INFORMATION

Actual and Long-term Average Generation

For assets acquired or reaching commercial operation during the year, reported generation is calculated from the acquisition or commercial operation date and is not annualized. As it relates to Colombia only, generation includes both hydroelectric and Co-gen facilities. “Other” includes generation from North America Co-gen and Brazil biomass.

We compare actual generation levels against the long-term average to highlight the impact of an important factor that affects the variability of our business results. In the short-term, we recognize that hydrology, wind and irradiance conditions will vary from one period to the next; over time however, we expect our facilities will continue to produce in line with their long-term averages, which have proven to be reliable indicators of performance.

Our risk of a generation shortfall in Brazil continues to be minimized by participation in the MRE administered by the government of Brazil. This program mitigates hydrology risk by assuring that all participants receive, at any particular point in time, an assured energy amount, irrespective of the actual volume of energy generated. The program reallocates energy, transferring surplus energy from those who generated an excess to those who generate less than their assured energy, up to the total generation within the pool. Periodically, low precipitation across the entire country’s system could result in a temporary reduction of generation available for sale. During these periods, we expect that a higher proportion of thermal generation would be needed to balance supply and demand in the country potentially leading to higher overall spot market prices.

Generation from our North American pumped storage and Co-gen facilities is highly dependent on market price conditions rather than the generating capacity of the facilities. Our European pumped storage facility generates on a dispatchable basis when required by our contracts for ancillary services. Generation from our biomass facilities is dependent on the amount of sugar cane harvested in a given year. For these reasons, we do not consider a long-term average for these facilities.

Segment Information

Brookfield Renewable’s Chief Executive Officer and Chief Financial Officer (collectively, the chief operating decision maker or “CODM”) review the results of the business, manage operations, and allocate resources based on the type of technology.

     With effect from the fourth quarter of 2017, operations are segmented by technology – 1) hydroelectric, 2) wind, 3) solar, storage, and other (Co-gen and biomass), and 4) corporate – with hydroelectric and wind further segmented by geography (North America, Colombia, Brazil, Europe and Other). To reflect the way in which the CODM now reviews results, manage operations and allocate resources, following the investments in First Hydro, TerraForm Power and TerraForm Global and as Brookfield Renewable continues to build out its solar and storage businesses, the CODM has commenced reviewing these businesses along with its Co-gen and biomass businesses on an aggregate basis.  The Colombia segment aggregates the financial results of its hydroelectric and Co-gen facilities. A pumped storage facility in North America, that was previously included in the hydroelectric segment, is now included in the “Solar, storage and other” segment. The corporate segment represents all activity performed above the individual segments for the business.

     We report our results in accordance with these segments and presents prior period segmented information in a consistent manner. See Note 6 – Segmented information in our audited annual consolidated financial statements.

Page 95

One of our primary business objectives is to generate stable and growing cash flows while minimizing risk for the benefit of all stakeholders. We monitor our performance in this regard through four key metrics — i) Net Income (Loss), ii) Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”), iii) Funds From Operations, and iv) Adjusted Funds From Operations.

It is important to highlight that Adjusted EBITDA, Funds From Operations and Adjusted Funds From Operations do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies and have limitations as analytical tools. For the non-IFRS financial measures we use to explain our financial results, see “PART 9 - Presentation to Stakeholders and Performance Measurement – Performance Measurement”.  We provide additional information below on how we determine Adjusted EBITDA, Funds From Operations and Adjusted Funds From Operations. We also provide reconciliations to net income (loss). See “Reconciliation of Non-IFRS Measures”.

Proportionate Information

In addition, with the effect from the fourth quarter of 2017, reporting to the CODM on the measures utilized to assess performance and allocate resources are on a proportionate basis. Information on a proportionate basis reflects Brookfield Renewable’s share from facilities which it accounts for using consolidation and the equity method whereby Brookfield Renewable either controls or exercises significant influence or joint control over the investment, respectively. Proportionate information provides a Unitholder perspective that the CODM considers important when performing internal analyses and making strategic and operating decisions. The CODM also believes that providing proportionate information helps investors understand the impacts of decisions made by management and financial results allocable to Unitholders.

Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Tables reconciling IFRS data with data presented on a proportionate consolidation basis have been disclosed. Segment revenues, other income, direct operating costs, interest expense, depreciation, current and deferred income taxes, and other are items that will differ from results presented in accordance with IFRS as these items (1) include Brookfield Renewable’s proportionate share of earnings from equity-accounted investments attributable to each of the above-noted items, and (2) exclude the proportionate share of earnings (loss) of consolidated investments not held by us apportioned to each of the above-noted items.

The presentation of proportionate results has limitations as an analytical tool, including the following:

·The amounts shown on the individual line items were derived by applying our overall economic ownership interest percentage and do not necessarily represent our legal claim to the assets and liabilities, or the revenues and expenses; and

·Other companies may calculate proportionate results differently than we do.

Because of these limitations, our proportionate financial information should not be considered in isolation or as a substitute for our financial statements as reported under IFRS.

Segmented net income (loss) is not a measure the CODM uses to review the results of business and allocate resources. Brookfield Renewable does not control those entities that have not been consolidated and as such, have been presented as equity-accounted investments in its financial statements. The presentation of the assets and liabilities and revenues and expenses do not represent Brookfield Renewable’s legal claim to such items, and the removal of financial statement amounts that

Page 96

are attributable to non-controlling interests does not extinguish Brookfield Renewable’s legal claims or exposures to such items.

Page 97

PROPORTIONATE RESULTS FOR THE YEAR ENDED DECEMBER 31, 2017 AND 2016

The following chart reflects the generation and summary financial figures on a proportionate basis for the year ended December 31:

		(GWh)					(MILLIONS)
		Actual Generation		LTA Generation			Revenues				Adjusted EBITDA				Funds From Operations				Net Income (Loss)
		2017	2016	2017	2016		2017		2016		2017		2016		2017		2016		2017		2016
Hydroelectric
	North America	13,942	11,960	13,059	12,977	$	945	$	819	$	665	$	548	$	486	$	367	$	174	$	128
	Brazil	3,426	3,078	3,874	3,761		243		187		178		130		148		97		1		(26)
	Colombia	3,683	2,419	3,488	2,994		191		192		99		88		52		46		19		25
		21,051	17,457	20,421	19,732		1,379		1,198		942		766		686		510		194		127
Wind
	North America	1,765	1,421	2,019	1,780		161		151		119		115		74		74		26		47
	Europe	490	571	513	605		46		56		26		32		15		18		(20)		(8)
	Brazil	278	266	245	245		26		17		22		13		16		6		10		1
		2,533	2,258	2,777	2,630		233		224		167		160		105		98		16		40
Solar, Storage & Other		384	507	53	-		67		58		39		31		21		19		(13)		1
Corporate		-	-	-	-		-		1		(6)		(15)		(231)		(208)		(253)		(233)
Total		23,968	20,222	23,251	22,362	$	1,679	$	1,481	$	1,142	$	942	$	581	$	419	$	(56)	$	(65)

Page 98

HYDROELECTRIC OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for hydroelectric operations the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2017		2016
Generation (GWh) – LTA		20,421		19,732
Generation (GWh) – actual		21,051		17,457
Revenue	$	1,379	$	1,198
Other income		15		40
Direct operating costs		(452)		(472)
Adjusted EBITDA		942		766
Interest expense		(240)		(237)
Current income taxes		(16)		(19)
Funds From Operations	$	686	$	510
Depreciation		(389)		(400)
Deferred taxes and other		(103)		17
Net income	$	194	$	127

The following table presents our proportionate results by geography for hydroelectric operations for the year ended December 31:

			Average
	Actual		revenue				Adjusted				Funds From				Net
	Generation (GWh)		Per MWh				EBITDA				Operations				Income
(MILLIONS, EXCEPT AS NOTED)	2017	2016	2017		2016		2017		2016		2017		2016		2017		2016
North America
United States	8,030	6,745	$	71	$	74	$	360	$	284	$	248	$	165	$	20	$	32
Canada	5,912	5,215		64		61		305		264		238		202		154		96
	13,942	11,960		68		68		665		548		486		367		174		128
Brazil	3,426	3,078		71		61		178		130		148		97		1		(26)
Colombia	3,683	2,419		52		79		99		88		52		46		19		25
Total	21,051	17,457	$	66	$	69	$	942	$	766	$	686	$	510	$	194	$	127

Funds From Operations increased 35% or $176 million from the prior year to $686 million primarily due to improved hydrological conditions in North America and Colombia, strong pricing in the Brazilian energy market and a full year contribution from our Colombian business.

Net income attributable to Unitholders increased by $67 million over the prior year as the increase in Funds From Operations was partially offset by an increase in deferred tax expense primarily attributable to the impact of the U.S. tax reform.

North America

Funds From Operations increased by $119 million over the prior year primarily due to a 2.0 TWh (17%) increase in generation due to strong hydrology, specifically in Canada and New York where strong inflows persisted throughout the year. Average revenue per MWh was in-line with the prior year as the benefit of stronger market pricing was offset by the final step down in pricing at our Louisiana facility.

Net income attributable to Unitholders increased by $46 million over the prior year as the increase in Funds From Operations was partially offset by an increase in deferred tax expense primarily due to the aforementioned U.S. tax reform.

Page !Unexpected End of Formula

Brazil

Funds From Operations increased by $51 million over the prior year primarily due to increased revenues driven by an overall increase in generation. While hydrology in Brazil was lower than long-term average, our business benefitted from a 11% increase in generation which was driven by the contribution from a 25 MW development project commissioned in the first quarter as well as a 377 GWh outage that impacted one of our facilities in the prior year. Average revenue per MWh increased 16% due to strong market pricing.

Net income attributable to Unitholders increased by $27 million over the prior year due to the above noted increase in Funds From Operations was partially offset by increased depreciation on our growing asset base.

Colombia

Funds From Operations increased by $6 million over the prior year as 2017 benefited from a full year of ownership.

Same store Funds From Operations was in-line with the prior year as the benefit of generation that was 6% ahead of long-term average was offset by lower market prices.

Net income attributable to Unitholders decreased by $6 million over the prior year as deferred income taxes were impacted by a tax rate reduction that occurred in 2016.

Page 100

WIND OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for wind operations for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2017		2016
Generation (GWh) – LTA		2,777		2,630
Generation (GWh) – actual		2,533		2,258
Revenue	$	233	$	224
Direct operating costs		(66)		(64)
Adjusted EBITDA		167		160
Interest expense		(61)		(62)
Current income taxes		(1)		-
Funds From Operations	$	105	$	98
Depreciation		(121)		(122)
Deferred taxes and other		32		64
Net income	$	16	$	40

The following table presents our proportionate results by geography for wind operations for the year ended December 31:

			Average
	Actual		revenue				Adjusted				Funds From				Net
	Generation (GWh)		per MWh				EBITDA				Operations				Income
(MILLIONS, EXCEPT AS NOTED)	2017	2016	2017		2016		2017		2016		2017		2016		2017		2016
North America
United States	658	452	$	91	$	119	$	37	$	35	$	17	$	21	$	14	$	(7)
Canada	1,107	969		91		100		82		80		57		53		12		54
	1,765	1,421		91		106		119		115		74		74		26		47
Europe	490	571		94		98		26		32		15		18		(20)		(8)
Brazil	278	266		94		64		22		13		16		6		10		1
Total	2,533	2,258	$	92	$	99	$	167	$	160	$	105	$	98	$	16	$	40

Funds From Operations increased 7% or $7 million from the prior year to $105 million due to improved generation in North America and pricing at our Brazilian wind portfolio partially offset by the impact of the sale of a 137 MW wind portfolio in Ireland during 2017.

Net income attributable to Unitholders decreased by $24 million over the prior year as the increase in Funds From Operations was offset by unrealized hedging losses from our ongoing foreign currency hedging program in Europe.

North America

Funds From Operations were consistent with the prior year as a 24% increase in generation due to stronger wind resources in Canada and contributions from our investment in TerraForm Power was offset by a 14% decrease in average revenue per MWh. The average revenue per MWh decreased as the prior year included a $6 million settlement for lost revenue due to wake effect at one our facilities in the United States.

Net income attributable to Unitholders decreased by $21 million over the prior year due primarily to depreciation expense relating to the investment in TerraForm Power.

Europe

Adjusting for the 137 MW wind portfolio sold during the first quarter of 2017, Funds From Operations increased by $4 million over the prior year to $15 million as a result of the acquisition and

Page 101

development of 50 MW of additional capacity during the year. Generation of existing assets was slightly below prior year due to lower wind resources.

Generation and Funds From Operations were impacted by 106 GWh and $7 million, respectively, as a result of the aforementioned asset sale.

Net loss attributable to Unitholders decreased by $12 million over the prior year to $20 million as a result of unrealized hedging losses from our ongoing foreign currency hedging program.

Brazil

Funds From Operations at our Brazilian business was $16 million versus $6 million in the prior year. This increase was driven by a 5% increase in generation due to above average wind resource and a 47% increase in the average revenue per MWh due to strong market pricing.

Net income attributable to Unitholders increased by $9 million over the prior year primarily due to the above noted increase in Funds From Operations.

Page 102

SOLAR, STORAGE AND OTHER OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for solar, storage and other operations for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2017		2016
Generation (GWh) – LTA		53		-
Generation (GWh) – actual		384		507
Revenue	$	67	$	58
Other income		6		(1)
Direct operating costs		(34)		(26)
Adjusted EBITDA		39		31
Interest expense		(17)		(12)
Current income taxes		(1)		-
Funds From Operations	$	21	$	19
Depreciation		(29)		(18)
Deferred taxes and other		(5)		-
Net (loss) income	$	(13)	$	1

Funds From Operations at our pumped storage business increased $14 million over the prior year to $17 million due to the addition of our First Hydro facility and improved performance at our facility in New England.

Our solar business is operating in line with expectations after the acquisition completed during the fourth quarter of TerraForm Power.

In 2016, our Ontario Co-gen asset benefitted from a settlement pertaining to the price escalator for power sold under power purchases agreements contributing $18 million to Funds From Operations.

Net loss attributable to Unitholders decreased by $14 million over the prior year as the increase in Funds From Operations was offset by additional depreciation on our growing portfolios and deferred tax expenses attributable to the U.S. tax reform.

Page 103

CORPORATE

The following table presents our results for corporate for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2017		2016
Revenue	$	-	$	1
Other income		19		8
Direct operating costs		(25)		(24)
Adjusted EBITDA		(6)		(15)
Management service costs		(82)		(62)
Interest expense		(89)		(91)
Distributions on Preferred LP Units and Shares		(54)		(40)
Funds From Operations	$	(231)	$	(208)
Deferred taxes and other		(22)		(25)
Net (loss)	$	(253)	$	(233)

Realized gains on our toehold positions in the TerraForm companies contributed $15 million to Other income.

Management fees increased primarily due to a higher LP Unit price compared to the prior year.

Distributions on Preferred LP Units and Preferred Shares increased $14 million compared to the prior year as a result of the C$250 million ($190 million) Preferred LP Units issuance completed in the first quarter of 2017.

Page 104

PROPORTIONATE RESULTS FOR THE YEAR ENDED DECEMBER 31, 2016 AND 2015

The following chart reflects the generation and summary financial figures on a proportionate basis for the year ended December 31:

		(GWh)				(MILLIONS)
		Actual Generation		LTA Generation		Revenues				Adjusted EBITDA				Funds From Operations				Net (Loss) Income
		2016	2015	2016	2015		2016		2015		2016		2015		2016		2015		2016		2015
Hydroelectric
	North America	11,960	11,532	12,977	12,749	$	819	$	819	$	548	$	557	$	367	$	373	$	128	$	206
	Brazil	3,078	3,158	3,761	3,447		187		203		130		164		97		136		(26)		20
	Colombia	2,419	-	2,994	-		192		-		88		-		46		-		25		-
		17,457	14,690	19,732	16,196		1,198		1,022		766		721		510		509		127		226
Wind
	North America	1,421	1,437	1,780	1,778		151		150		115		124		74		76		47		(19)
	Europe	571	615	605	591		56		56		32		44		18		32		(8)		1
	Brazil	266	186	245	184		17		9		13		8		6		5		1		1
		2,258	2,238	2,630	2,553		224		215		160		176		98		113		40		(17)
Storage & Other		507	734	-	-		58		59		31		28		19		23		1		6
Corporate		-	-	-	-		1		-		(15)		(18)		(208)		(178)		(233)		(212)
Total		20,222	17,662	22,362	18,749	$	1,481	$	1,296	$	942	$	907	$	419	$	467	$	(65)	$	3

Page 105

HYDROELECTRIC OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for hydroelectric operations the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2016		2015
Generation (GWh) – LTA		19,732		16,196
Generation (GWh) – actual		17,457		14,690
Revenue	$	1,198	$	1,022
Other income		40		51
Direct operating costs		(472)		(352)
Adjusted EBITDA		766		721
Interest expense		(237)		(197)
Current income taxes		(19)		(15)
Funds From Operations	$	510	$	509
Depreciation		(400)		(331)
Deferred taxes and other		17		48
Net income	$	127	$	226

The following table presents our proportionate results by geography for hydroelectric operations for the year ended December 31:

			Average
	Actual		revenue				Adjusted				Funds From				Net
	Generation (GWh)		Per MWh				EBITDA				Operations				Income
(MILLIONS, EXCEPT AS NOTED)	2016	2015	2016		2015		2016		2015		2016		2015		2016		2015
North America
United States	6,745	6,839	$	74	$	75	$	284	$	305	$	165	$	183	$	32	$	94
Canada	5,215	4,693		61		66		264		252		202		190		96		112
	11,960	11,532		68		71		548		557		367		373		128		206
Brazil	3,078	3,158		61		64		130		164		97		136		(26)		20
Colombia	2,419	-		79		-		88		-		46		-		25		-
Total	17,457	14,690	$	69	$	70	$	766	$	721	$	510	$	509	$	127	$	226

Funds From Operations increased $1 million from the prior year to $510 million as the acquisition of our Colombian business and higher generation at our North American business was offset by lower realized pricing in North America and Brazil and the benefit of settlements received by our Brazilian business in 2015.

Net Income attributable to Unitholders decreased by $99 million over the prior year due primarily to depreciation expense on our growing asset base.

North America

Funds From Operations decreased by $6 million as a 4% increase in generation due to the benefit of acquisitions and improved hydrology at our existing facilities, was more than offset by a $3 decrease in average revenue per MWh. Our portfolio in Pennsylvania, which was acquired in 2016, contributed 150 GWh on a proportionate basis and $4 million in Funds From Operations.

Net income attributable to Unitholders decreased by $78 million due to higher depreciation expense on our growing asset base.

Page !Unexpected End of Formula

Brazil

Funds From Operations decreased by $39 million from the prior year. Growth in our portfolio contributed 343 GWh and $11 million in Funds From Operation.  An unplanned 377 GWh outage at one of our facilities and a 5% decrease in average revenue per MWh collectively and negatively impacted Funds From Operations by $23 million. In 2015, we benefited from a financial settlement relating to the delayed completion of a hydroelectric facility and received compensation in exchange for electing not to renew expired concession agreements at two facilities, collectively contributed $27 million.

Net loss attributable to Unitholders decreased by $46 million due primarily to the above noted decrease in Funds From Operations.

Colombia

            The addition of the hydroelectric portfolio in the first quarter of 2016 contributed Funds From Operations and Net income attributable to Unitholders by $46 million and $25 million, respectively. Overall the portfolio performed in-line with expectations.

Page 107

WIND OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for wind operations for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2016		2015
Generation (GWh) – LTA		2,630		2,258
Generation (GWh) – actual		2,258		2,238
Revenue	$	224	$	215
Other income		-		20
Direct operating costs		(64)		(59)
Adjusted EBITDA		160		176
Interest expense		(62)		(63)
Funds From Operations	$	98	$	113
Depreciation		(122)		(119)
Deferred taxes and other		64		(11)
Net income (loss)	$	40	$	(17)

The following table presents our proportionate results by geography for wind operations for the year ended December 31:

			Average
	Actual		revenue				Adjusted				Funds From				Net
	Generation (GWh)		per MWh				EBITDA				Operations				Income
(MILLIONS, EXCEPT AS NOTED)	2016	2015	2016		2015		2016		2015		2016		2015		2016		2015
North America
United States	452	421	$	119	$	107	$	35	$	40	$	21	$	20	$	(7)	$	(19)
Canada	969	1,016		100		103		80		84		53		56		54		-
	1,421	1,437		106		104		115		124		74		76		47		(19)
Europe	571	615		98		91		32		44		18		32		(8)		1
Brazil	266	186		64		48		13		8		6		5		1		1
Total	2,258	2,238	$	99	$	96	$	160	$	176	$	98	$	113	$	40	$	(17)

Funds From Operations decreased 13% or $15 million from the prior year to $98 million. While generation and average revenue per MWh were up from the prior year this was more than offset by a $12 million gain on the sale of our California wind facility and $8 million of hedging gains realized from our ongoing foreign currency program in Europe, both of which benefitted 2015.

Net income attributable to Unitholders increased by $57 million over the prior year due primarily to the benefit of a deferred tax recovery at our North American business.

North America

Adjusted for the sale of our 102 MW Californian wind facility which was sold in the third quarter of 2015, Funds From Operations increased by $11 million. The increase is due primarily to higher generation and lower interest costs due to the amortization of project-level debt. Additionally, 2016 benefitted from a $6 million settlement for lost revenue due to the wake effect at one of our facilities in the U.S.

As a result of the asset sale, generation and Funds From Operations declined by 27 GWh and $1 million, respectively.  2015 also benefitted from a $12 million gain from the sale.

Net income attributable to Unitholders increased by $66 million over the prior year due primarily to the benefit of a deferred tax recovery.

Page 108

Europe

Funds From Operations decreased by $14 million over the prior year to $18 million. Generation was 7% below prior year due to weaker wind resource and a planned outage at one of our facilities. Additionally, in 2015, we benefited from a $8 million hedging gain relating to our ongoing foreign currency program.

Net loss attributable to Unitholders decreased by $9 million over the prior year due primarily to the above noted decrease in Funds From Operations.

Brazil

Funds From Operations was $1 million ahead of the prior year. Generation in Brazil was above the long-term average and the prior year due to improved wind conditions and contribution from a full year of generation from the facilities acquired.

Net income attributable to Unitholders was consistent year over year at $1 million.

Page 109

STORAGE AND OTHER OPERATIONS ON PROPORTIONATE BASIS

The following table presents our proportionate results for storage and other operations for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2016		2015
Generation (GWh) – actual		507		734
Revenue	$	58	$	59
Other income		(1)		-
Direct operating costs		(26)		(31)
Adjusted EBITDA		31		28
Interest expense		(12)		(5)
Funds From Operations	$	19	$	23
Depreciation		(18)		(12)
Deferred taxes and other		-		(5)
Net income	$	1	$	6

Funds From Operations at our pumped storage business decreased by $13 million from the prior year due to weak market conditions.

Funds From Operations from our North American Co-gen and Brazilian biomass facilities increased by $10 million from the prior year. Generation decreased due to limited availability of our Co-gen facilities as a result of weak natural gas prices resulting in a $8 million decrease in Funds From Operations. This was more than offset by an $18 million settlement at our Ontario Co-gen asset pertaining to the price escalator for power sold under power purchase agreements.

Net income attributable to Unitholders decreased by $5 million due to the above noted decrease in Funds From Operations.

CORPORATE

The following table presents our results for corporate for the year ended December 31:

(MILLIONS, EXCEPT AS NOTED)	2016		2015
Revenue	$	1	$	-
Other income		8		5
Direct operating costs		(24)		(23)
Adjusted EBITDA		(15)		(18)
Management service costs		(62)		(48)
Interest expense		(91)		(81)
Distributions on preferred LP Units and preferred shares		(40)		(31)
Funds From Operations	$	(208)	$	(178)
Deferred taxes and other		(25)		(34)
Net (loss)	$	(233)	$	(212)

Management fees increased due primarily to a higher LP Unit price compared to the prior year.

Interest expense increased following the C$500 million ($383 million) medium-term notes issued in third quarter of 2016.

Distributions on Preferred LP Units and Preferred Shares increased $9 million compared to the prior year as a result of the C$200 million ($152 million) Preferred LP Unit issuance completed in the second quarter of 2016.

Page 110

reconciliation of non-ifrs measures

The following table reflects Adjusted EBITDA, Funds From Operations, Adjusted Funds From Operations and provides a reconciliation to net income (loss) for the year ended December 31, 2017:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Solar,		Corporate		Total	equity		to non-		As per
		North						North						Storage and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			945		191		243		161		46		26		67		-	1,679		(74)		1,020		2,625
Other income			1		2		12		-		-		-		6		19	40		(11)		18		47
Direct operating costs			(281)		(94)		(77)		(42)		(20)		(4)		(34)		(25)	(577)		28		(429)		(978)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		57		-		57
Adjusted EBITDA			665		99		178		119		26		22		39		(6)	1,142		-		609
Management service costs			-		-		-		-		-		-		-		(82)	(82)		-		-		(82)
Interest expense - borrowings			(180)		(42)		(18)		(45)		(10)		(6)		(17)		(89)	(407)		21		(246)		(632)
Current income taxes			1		(5)		(12)		-		(1)		-		(1)		-	(18)		1		(22)		(39)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(28)	(28)		-		-		(28)
	Preferred equity		-		-		-		-		-		-		-		(26)	(26)		-		-		(26)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(22)		-		(22)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(341)		(341)
Funds From Operations			486		52		148		74		15		16		21		(231)	581		-		-
Adjusted sustaining capital expenditures(2)			-		-		-		-		-		-		-		-	(68)		-		-
Adjusted Funds From Operations			486		52		148		74		15		16		21		(231)	513		-		-
Adjusted sustaining capital expenditures(2)			-		-		-		-		-		-		-		-	68		-		-
Depreciation			(222)		(26)		(141)		(89)		(24)		(8)		(29)		-	(539)		22		(265)		(782)
Unrealized financial instrument loss			(3)		(3)		-		(1)		(12)		-		-		(10)	(29)		1		(5)		(33)
Deferred income tax expense			(67)		(10)		2		45		6		-		1		(3)	(26)		(3)		(20)		(49)
Other			(20)		6		(8)		(3)		(5)		2		(6)		(9)	(43)		13		2		(28)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(33)		-		(33)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		288		288
Net income (loss) attributable to Unitholders(3)			174		19		1		26		(20)		10		(13)		(253)	(56)		-		-		(56)

⁽¹⁾Share of earnings from equity-accounted investments of $2 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $53 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Based on long-term sustaining capital expenditure plans.

⁽³⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

Page 111

Page 112

The following table reflects Adjusted EBITDA, Funds From Operations, Adjusted Funds From Operations and provides a reconciliation to net income (loss) for the year ended December 31, 2016:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		192		187		151		56		17		58		1	1,481		(37)		1,008		2,452
Other income			24		3		13		-		-		-		(1)		8	47		-		17		64
Direct operating costs			(295)		(107)		(70)		(36)		(24)		(4)		(26)		(24)	(586)		16		(468)		(1,038)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		21		-		21
Adjusted EBITDA			548		88		130		115		32		13		31		(15)	942		-		557
Management service costs			-		-		-		-		-		-		-		(62)	(62)		-		-		(62)
Interest expense - borrowings			(177)		(36)		(24)		(41)		(14)		(7)		(12)		(91)	(402)		12		(216)		(606)
Current income taxes			(4)		(6)		(9)		-		-		-		-		-	(19)		-		(25)		(44)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(15)	(15)		-		-		(15)
	Preferred equity		-		-		-		-		-		-		-		(25)	(25)		-		-		(25)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(12)		-		(12)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(316)		(316)
Funds From Operations			367		46		97		74		18		6		19		(208)	419		-		-
Adjusted sustaining capital expenditures(2)			-		-		-		-		-		-		-		-	(67)		-		-
Adjusted Funds From Operations			367		46		97		74		18		6		19		(208)	352		-		-
Adjusted sustaining capital expenditures(2)			-		-		-		-		-		-		-		-	67		-		-
Depreciation			(244)		(31)		(125)		(80)		(38)		(4)		(18)		-	(540)		11		(252)		(781)
Unrealized financial instrument loss			1		-		-		-		-		-		2		(6)	(3)		(2)		1		(4)
Deferred income tax expense			31		6		7		49		6		-		-		(21)	78		-		19		97
Other			(27)		4		(5)		4		6		(1)		(2)		2	(19)		-		(19)		(38)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(9)		-		(9)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		251		251
Net income (loss) attributable to Unitholders(3)			128		25		(26)		47		(8)		1		1		(233)	(65)		-		-		(65)

⁽¹⁾Share of earnings from equity-accounted investments of $nil is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $65 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Based on long-term sustaining capital expenditure plans.

⁽³⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

Page 113

The following table reflects Adjusted EBITDA, Funds From Operations, Adjusted Funds From Operations and provides a reconciliation to net income (loss) for the year ended December 31, 2015:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		-		203		150		56		9		59		-	1,296		(44)		376		1,628
Other income			23		-		28		12		8		-		-		5	76		-		46		122
Direct operating costs			(285)		-		(67)		(38)		(20)		(1)		(31)		(23)	(465)		18		(105)		(552)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		26				26
Adjusted EBITDA			557		-		164		124		44		8		28		(18)	907		-		317
Management service costs			-		-		-		-		-		-		-		(48)	(48)		-		-		(48)
Interest expense - borrowings			(179)		-		(18)		(48)		(12)		(3)		(5)		(81)	(346)		6		(89)		(429)
Current income taxes			(5)		-		(10)		-		-		-		-		-	(15)		-		(3)		(18)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(1)	(1)		-		-		(1)
	Preferred equity		-		-		-		-		-		-		-		(30)	(30)		-		-		(30)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(6)		-		(6)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(225)		(225)
Funds From Operations			373		-		136		76		32		5		23		(178)	467		-		-
Adjusted sustaining capital expenditures(2)																		(60)
Adjusted Funds From Operations			373		-		136		76		32		5		23		(178)	407		-		-
Adjusted sustaining capital expenditures(2)			-		-		-		-		-		-		-		-	60		-		-
Depreciation			(218)		-		(113)		(83)		(32)		(4)		(12)		-	(462)		9		(161)		(614)
Unrealized financial instrument loss			1		-		-		2		-		-		(1)		(15)	(13)		1		3		(9)
Deferred income tax expense (recovery)			36		-		4		16		2		-		-		20	78		-		2		80
Other			14		-		(8)		(30)		(1)		-		(4)		(39)	(67)		-		-		(67)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(10)		-		(10)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-				156		156
Net income (loss) attributable to Unitholders(3)			206		-		20		(19)		1		1		6		(212)	3		-		-		3

⁽¹⁾Share of earnings from equity-accounted investments of $10 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $69 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Based on long-term sustaining capital expenditure plans.

⁽³⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

Page 114

The following table reflects Adjusted EBITDA, Funds From Operations and provides reconciliation to net income (loss) for the three months ended December 31, 2017:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Solar,		Corporate		Total	equity		to non-		Total
		North						North						Storage and					accounted		controlling
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests
Revenues			217		51		64		53		12		7		26		-	430		(39)		266		657
Other income			-		-		2		-		-		-		6		18	26		(10)		6		22
Direct operating costs			(73)		(25)		(23)		(16)		(5)		(1)		(10)		(8)	(161)		13		(114)		(262)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		36		-		36
Adjusted EBITDA			144		26		43		37		7		6		22		10	295		-		158
Management service costs			-		-		-		-		-		-		-		(24)	(24)		-		-		(24)
Interest expense - borrowings			(44)		(10)		(6)		(15)		(1)		(1)		(8)		(23)	(108)		12		(59)		(155)
Current income taxes			-		(2)		(4)		-		-		-		-		-	(6)		-		(6)		(12)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(7)	(7)		-		-		(7)
	Preferred equity		-		-		-		-		-		-		-		(7)	(7)		-		-		(7)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(12)		-		(12)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(93)		(93)
Funds From Operations			100		14		33		22		6		5		14		(51)	143		-		-
Depreciation			(57)		(2)		(36)		(28)		(8)		(2)		(10)		-	(143)		13		(52)		(182)
Unrealized financial instrument gain			(2)		-		-		-		5		-		(1)		1	3		1		3		7
Deferred income tax expense			(62)		(1)		(1)		32		1		-		1		(2)	(32)		(3)		3		(32)
Other			(7)		(4)		(2)		(4)		(13)		-		(10)		2	(38)		14		(23)		(47)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(25)		-		(25)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		69		69
Net income (loss) attributable to Unitholders			(28)		7		(6)		22		(9)		3		(6)		(50)	(67)		-		-		(67)

Page 115

The following table reflects Adjusted EBITDA, Funds From Operations and provides reconciliation to net income (loss) for the three months ended December 31, 2016:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		Total
		North						North						and					accounted		controlling
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests
Revenues			162		56		46		38		15		5		10		1	333		(9)		247		571
Other income			-		-		3		-		-		-		-		1	4		-		5		9
Direct operating costs			(71)		(28)		(16)		(9)		(7)		(1)		(8)		(8)	(148)		5		(115)		(258)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		4		-		4
Adjusted EBITDA			91		28		33		29		8		4		2		(6)	189		-		137
Management service costs			-		-		-		-		-		-		-		(16)	(16)		-		-		(16)
Interest expense - borrowings			(44)		(10)		(5)		(10)		(5)		(2)		(3)		(23)	(102)		3		(60)		(159)
Current income taxes			-		(5)		(2)		-		-		-		-		-	(7)		-		(17)		(24)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(4)	(4)		-		-		(4)
	Preferred equity		-		-		-		-		-		-		-		(6)	(6)		-		-		(6)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(3)		-		(3)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(60)		(60)
Funds From Operations			47		13		26		19		3		2		(1)		(55)	54		-		-
Depreciation			(63)		(9)		(33)		(20)		(13)		(1)		(5)		-	(144)		3		(47)		(188)
Unrealized financial instrument gain			1		-		-		-		-		-		1		2	4		(1)		(1)		2
Deferred income tax recovery			13		12		4		49		1		-		-		(28)	51		-		44		95
Other			(19)		(1)		(1)		(3)		8		-		(4)		8	(12)		-		(20)		(32)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(2)		-		(2)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		24		24
Net income (loss) attributable to Unitholders			(21)		15		(4)		45		(1)		1		(9)		(73)	(47)		-		-		(47)

Page 116

The following table reconciles net loss attributable to Limited partners’ equity and loss per LP Unit, the most directly comparable IFRS measures, to Funds From Operations, Funds From Operations per Unit and Adjusted EBITDA, all non-IFRS financial metrics for the year ended December 31:

													Per unit
(MILLIONS, EXCEPT AS NOTED)				2017		2016		2015		2014		2013		2017		2016		2015		2014		2013
Net loss attributable to:
	Limited partners' equity		$	(32)	$	(36)	$	2	$	58	$	69	$	(0.18)	$	(0.23)	$	0.01	$	0.22	$	0.27
	General partnership interest in a holding
		subsidiary held by Brookfield	$	(1)	$	-	$	-	$	1	$	1		-		-		-	$	-	$	-
	Participating non-controlling interests - in a holding
		subsidiary - Redeemable/Exchangeable units
		held by Brookfield		(23)		(29)		1		55		67		-		-		-		0.20		0.25
Net loss attributable to Unitholders			$	(56)	$	(65)	$	3	$	114	$	137	$	(0.18)	$	(0.23)	$	0.01	$	0.42	$	0.52
Depreciation				539		540		462		456		481		1.76		1.87		1.68		1.68		1.81
Unrealized financial instruments loss				29		3		13		2		(30)		0.09		0.01		0.05		0.01		(0.11)
Deferred income tax expense (recovery)				26		(78)		(78)		(29)		(18)		0.09		(0.27)		(0.28)		(0.11)		(0.07)
Other				43		19		67		17		24		0.14		0.07		0.23		0.07		0.09
Funds From Operations			$	581	$	419	$	467	$	560	$	594	$	1.90	$	1.45	$	1.69	$	2.07	$	2.24
Adjusted sustaining capital expenditures				(68)		(67)		(60)		(58)		(56)
Adjusted Funds From Operations				513		352		407		502		538
Adjusted sustaining capital expenditures				68		67		60		58		56
Distributions attributable to:
	Preferred limited partners equity			28		15		1		-		-
	Preferred equity			26		25		30		38		37
Current income taxes				18		19		15		6		17
Interest expense - borrowings				407		402		346		353		366
Management service costs				82		62		48		51		41
Proportionate Adjusted EBITDA				1,142		942		907		1,008		1,055
Attributable to non-controlling interests				609		557		317		211		156
Consolidated Adjusted EBITDA				1,751		1,499		1,224		1,219		1,211
Weighted average Units outstanding(1)													305.77		288.69		275.64		271.08		265.25

⁽¹⁾Includes GP interest, Redeemable/Exchangeable partnership units, and LP Units.

Page 117

The following table reconciles net loss attributable to Limited partners’ equity and loss per LP Unit, the most directly comparable IFRS measures, to Funds From Operations, and Funds From Operations per Unit, both non-IFRS financial metrics for the three months ended December 31:

							Per unit
(MILLIONS, EXCEPT AS NOTED)				2017		2016		2017		2016
Net loss attributable to:
	Limited partners' equity		$	(38)	$	(26)	$	(0.22)	$	(0.16)
	General partnership interest in a holding
		subsidiary held by Brookfield		(1)		-		-		-
	Participating non-controlling interests - in a holding
		subsidiary - Redeemable/Exchangeable units
		held by Brookfield		(28)		(21)		-		-
Net loss attributable to Unitholders			$	(67)	$	(47)	$	(0.22)	$	(0.16)
Depreciation				143		144		0.46		0.48
Unrealized financial instruments gain				(3)		(4)		(0.01)		(0.01)
Deferred income tax expense (recovery)				32		(51)		0.10		(0.17)
Other				38		12		0.13		0.04
Funds From Operations			$	143	$	54	$	0.46	$	0.18
Weighted average Units outstanding(1)								312.63		299.06

⁽¹⁾Includes GP interest, Redeemable/Exchangeable partnership units, and LP Units.

Page 118

CONTRACT PROFILE

We operate the business on a largely contracted basis to provide a high degree of predictability in Funds From Operations. We maintain a long-term view that electricity prices and the demand for electricity from renewable sources will rise due to a growing level of acceptance around climate change, the legislated requirements in some areas to diversify away from fossil fuel based generation and because they are becoming increasingly cost competitive.

In Brazil and Colombia, we also expect power prices will continue to be supported by the need to build new supply over the medium to long term to serve growing demand. In these markets contracting for power is the only current mechanism to buy and sell power, and therefore we would expect to capture rising prices as we re-contract our power over the medium term.

The following table sets out our contracts over the next five years for generation output in North America, Europe and certain other countries, assuming long-term average on a proportionate basis. The table excludes Brazil and Colombia, where we would expect the energy associated with maturing contracts to be re-contracted in the normal course given the construct of the respective power markets. In these countries we currently have a contracted profile of approximately 90% and 70% respectively, of the long-term average and we would expect to maintain this going forward.

FOR THE YEAR ENDED DECEMBER 31				2018			2019		2020		2021		2022
Generation (GWh)
Contracted(1)
	Hydroelectric
		North America
			United States(2)		7,126		7,011		6,306		6,099		4,791
			Canada		5,051		5,051		3,584		3,091		3,045
					12,177		12,062		9,890		9,190		7,836
	Wind
		North America
			United States		1,316		1,302		1,261		1,226		1,214
			Canada		1,197		1,197		1,197		1,197		1,197
					2,513		2,499		2,458		2,423		2,411
		Europe			458		458		404		397		391
		Other(3)			127		127		127		127		127
					3,098		3,084		2,989		2,947		2,929
	Solar				456		456		456		456		456
Contracted on a proportionate basis					15,731		15,602		13,335		12,593		11,221
Uncontracted on a proportionate basis					1,438		1,567		3,834		4,576		5,948
Long-term average on a proportionate basis					17,169		17,169		17,169		17,169		17,169
Non-controlling interests					12,768		12,768		12,768		12,768		12,768
Total long-term average					29,937		29,937		29,937		29,937		29,937
Contracted generation - as at December 31, 2017
% of total generation on a proportionate basis					92	%	91	%	78	%	73	%	65	%
Price per MWh - total generation on a
	proportionate basis			$	75	$	76	$	81	$	82	$	88

⁽¹⁾Assets under construction are included when long-term average and pricing details are available and the commercial operation date is established in a definitive construction contract. In the years 2018 to 2022, on a proportionate basis, there is 38 GWh contributed from assets under construction that meet the aforementioned conditions.

⁽²⁾Includes generation of 820 GWh for 2018 and 705 GWh for 2019 GWh secured under financial contracts.

⁽³⁾Includes generation from China, India, Malaysia, Thailand, South Africa and Uruguay.

Page 119

Our North American portfolio has a weighted-average remaining contract duration of 20 years (on a proportionate basis). Over the next five years, five contracts at our hydroelectric facilities are expiring, including one in 2020, two in 2021 and two in 2022 with annual long-term average (on a proportionate basis) of 1,467 GWh, 850 GWh and 1,271 GWh, respectively. We expect on average to recontract expiring contracts at levels equal to or greater than the rates of the expiring contracts. The majority of the expiring contracts are in line with current merchant prices.

In our Brazilian and Colombian portfolios, we have a weighted-average remaining duration on our contracts of 8 years and 2 years (on a proportionate basis), respectively. We continue to focus on securing long-term contracts while maintaining a certain percentage of uncontracted generation so as to mitigate hydrology risk.

In our European wind portfolio, we have a weighted-average remaining duration of 9 years (on a proportionate basis).

In other countries we have a weighted-average remaining duration of 18 years (on a proportionate basis).

The majority of Brookfield Renewable’s long-term PPAs within our North American and European businesses are with investment-grade rated or creditworthy counterparties. The overall composition of our contracted generation on a proportionate basis under PPAs is comprised of Brookfield (42%), public power authorities (21%), distribution companies (18%) and industrial users (19%).

Page 120

PART 5 - liquidity and capital Resources

Capitalization

A key element of our financing strategy is to raise the majority of our debt in the form of asset-specific, non-recourse borrowings at our subsidiaries on an investment-grade basis.

The following table summarizes our capitalization as at December 31:

(MILLIONS, EXCEPT AS NOTED)		2017		2016
Credit facilities(1)	$	887	$	673
Corporate borrowings(2)		1,665		1,556
Subsidiary borrowings(3)(4)		8,774		7,953
Long-term indebtedness		11,326		10,182
Deferred income tax liabilities, net of deferred income tax assets		3,411		3,652
Equity		14,282		12,672
Total capitalization	$	29,019	$	26,506
Debt to total capitalization		39%		38%

⁽¹⁾Comprised of $685 million borrowed under unsecured corporate credit facilities guaranteed by Brookfield Renewable and $202 million borrowed under a subscription credit facility of a Brookfield sponsored private fund.

⁽²⁾Amounts are unsecured and guaranteed by Brookfield Renewable.

⁽³⁾Asset-specific, non-recourse borrowings secured against the assets of certain Brookfield Renewable subsidiaries.

⁽⁴⁾Net of cash and cash equivalents on TerraForm Global's balance sheet which, under the indenture, is not available for distribution.

Credit facility draws have increased by $214 million to $887 million since December 31, 2016. The increase is primarily attributable to draws related to the acquisition of TerraForm Global. The draw on the subscription facility, which matures in 2019, is expected to be repaid in 2018.

The strengthening of the Canadian dollar against the U.S. dollar during the year ended December 31, 2017 resulted in an increase in corporate borrowings of $109 million from December 31, 2016.

Page 121

Available liquidity

The following table summarizes the available liquidity as at December 31:

(MILLIONS)		2017		2016
Consolidated cash and cash equivalents(1)		$	359	$	223
Less: cash and cash equivalents attributable to
	participating non-controlling interests in operating subsidiaries		(191)		(135)
Brookfield Renewable's share of cash and cash equivalents			168		88
Available-for-sale securities			159		136
Credit facilities
	Authorized credit facilities		2,090		1,890
	Draws on credit facilities(2)		(685)		(673)
	Issued letters of credit		(193)		(250)
Available portion of credit facilities			1,212		967
Available liquidity		$	1,539	$	1,191

⁽¹⁾Net of cash and cash equivalents on TerraForm Global's balance sheet which, under the indenture, is not available for distribution.

⁽²⁾Draws were comprised of $685 million borrowed under unsecured corporate credit facilities guaranteed by Brookfield Renewable. Excludes the $202 million borrowed under a subscription credit facility of a Brookfield sponsored private fund.

We operate with sufficient liquidity to enable us to fund growth initiatives, capital expenditures, distributions, withstand sudden adverse changes in economic circumstances or short-term fluctuations in generation, and to finance the business on an investment-grade basis. Principal sources of liquidity are cash flows from operations, our credit facilities, up-financings on subsidiary borrowings and proceeds from the issuance of various securities through public markets.

Credit facilities and subsidiary borrowings

During the year ended December 31, 2017 we completed the following financing activities:

·Extended the maturity of our $1.6 billion corporate credit facility by one year to June 2022;

·Increased the unsecured revolving credit facility provided by Brookfield Asset Management from $200 million to $400 million; and

·Financed $3.1 billion of long-term debt at average rates of 4.5% reducing our proportionate floating rate exposure to 13% and extended our proportionate average term to maturity to 10 years.

Page !Unexpected End of Formula

LONG-TERM DEBT AND CREDIT FACILITIES

The composition of debt obligations, overall maturity profile, and average interest rates associated with our borrowings and credit facilities on a proportionate basis as at December 31 is presented in the following table:

		2017				2016
		Weighted-average				Weighted-average
		Interest	Term			Interest	Term
(MILLIONS EXCEPT AS NOTED)		rate (%)	(years)			rate (%)	(years)
Corporate borrowings		4.5	6.4	$	1,670	4.5	7.4	$	1,562
Credit facilities		2.6	4.5		887	1.9	4.5		673
Proportionate subsidiary borrowings
	Hydroelectric	6.1	10.5		3,741	6.5	8.6		3,640
	Wind	5.1	11.3		1,286	4.8	12.8		1,030
	Solar, storage and other	5.7	9.2		733	5.1	9.6		217
		5.8	10.5		5,760	6.1	9.5		4,887
Total proportionate debt				$	8,317			$	7,122
Proportionate unamortized financing
	fees, net of unamortized premiums				(47)				(45)
Brookfield Renewable's share					8,270				7,077
Subsequent financings(1)					(33)				-
Equity accounted borrowings					(834)				(233)
Non-controlling interests					4,363				3,338
As per IFRS Statements				$	11,766			$	10,182

⁽¹⁾Adjusted to reflect the financing initiatives, associated with a hydroelectric and a storage facility, finalized subsequent to year-end.

Page !Unexpected End of Formula

The following table summarizes our undiscounted principal repayments, schedule amortization and interest payable on a proportionate basis as at December 31, 2017:

(MILLIONS)				2018		2019		2020		2021		2022		Thereafter		Total
Principal repayments
	Corporate borrowings and
			credit facilities		159		202		377		-		984		835	$	2,557
	Subsidiary borrowings
		Hydro(1)			104		145		396		237		215		2,644		3,741
		Wind			77		75		79		84		122		849		1,286
		Solar, storage and other(1)			14		16		15		85		51		552		733
					195		236		490		406		388		4,045		5,760
Total					354		438		867		406		1,372		4,880	$	8,317
Interest payable(2)
	Corporate borrowings and
			credit facilities		95		85		85		66		58		192	$	581
	Subsidiary borrowings
		Hydro(1)			225		216		200		169		154		796		1,760
		Wind			61		54		51		47		43		178		434
		Solar, storage and other(1)			44		39		39		38		30		136		326
					330		309		290		254		227		1,110		2,520
Total					425		394		375		320		285		1,302	$	3,101

⁽¹⁾Adjusted to reflect the financing initiatives, associated with a hydroelectric and a storage facility, finalized subsequent to year-end.

⁽²⁾Represents aggregate interest payable expected to be paid over the entire term of the obligations, if held to maturity. Variable rate interest payments have been calculated based on estimated interest rates.

We remain focused on refinancing near-term facilities on acceptable terms and maintaining a manageable maturity ladder. We do not anticipate material issues in addressing our borrowings through 2022 on acceptable terms and will do so opportunistically based on the prevailing interest rate environment.

Our sole near term maturity is our C$200 million ($159 million) Series 3 medium-term notes which mature in November 2018.

As part of the TerraForm Global transaction, Brookfield Renewable acquired assets with project level financings that were in default prior to the acquisition, had outstanding principal amounts totaling $342 million, and mature in 2031.  As at December 31, 2017, the loans were not in compliance with certain covenants due to the SunEdison Bankruptcy, as well as issues with contractors under the engineering, procurement and construction contract. The loan balances have been classified as current as at December 31, 2017 on our IFRS financial statements. Brookfield Renewable is currently working with all the lenders to cure such defaults and release the restrictions place on the projects.  As we expect a successful outcome, we have presented these loans according to their original maturity date in the above maturity table.  Except for the aforementioned defaults, Brookfield Renewable complied with all material financial covenants as of December 31, 2017.

Page 124

The overall maturity profile and average interest rates associated with our borrowings and credit facilities on a proportionate basis as at December 31 are as follows:

	Average term (years)		Average interest rate (%)
	2017	2016		2017	2016
Corporate borrowings	6.4	7.4	4.5		4.5
Credit facilities	4.5	4.5	2.6		1.9
Subsidiary borrowings(1)	10.5	9.5	5.8		6.1

⁽¹⁾Adjusted to reflect the financing initiatives, associated with a hydroelectric and a storage facility, finalized subsequent to year-end.

CONSOLIDATED STATEMENTS OF CASH FLOWS

The following table summarizes the key items in the audited annual consolidated statements of cash flows, for the year ended December 31:

(MILLIONS)	2017		2016			2015
Cash flow provided by (used in):
Operating activities	$	928	$	632	$	588
Financing activities		(27)		2,709		(33)
Investing activities		(328)		(3,191)		(623)
Foreign exchange gain on cash		3		10		(19)
Increase (decrease) in cash and cash equivalents	$	576	$	160	$	(87)

Cash and cash equivalents as at December 31, 2017 totaled $799 million, representing an increase of $576 million since December 31, 2016.

Operating Activities

Cash flows provided by operating activities totaled $928 million in 2017, a $296 million or 47% increase from 2016. The increase is primarily due to a $162 million increase in Funds From Operations as a result of a return to normal hydrology, advancement of our organic initiatives and contributions from new acquisitions. The impact from the net change in working capital balances is supported by the table below.

Cash flows provided by operating activities totaling $632 million for the year ended December 31, 2016 represent a year-over-year increase of $44 million.

Net change in working capital

The net change in working capital balances shown in the consolidated statements of cash flows for the year ended December 31 is comprised of the following:

(MILLIONS)		2017		2016		2015
Trade receivables and other current assets	$	(40)	$	30	$	(72)
Accounts payable and accrued liabilities		32		(160)		2
Other assets and liabilities		(17)		(7)		8
	$	(25)	$	(137)	$	(62)

Page 125

Financing Activities

Cash flows used in financing activities totaled $27 million for the year ended December 31, 2017. Long-term debt – borrowings, net of repayments, totaling $267 million were related to the growth in our portfolio and our project-level financing initiatives. The capital provided by participating non-controlling interests – in operating subsidiaries relates to the growth in our portfolio with our institutional partners and amounted to $294 million. To fund growth in our portfolio, capital markets activities resulted in the issuance of LP Units and Preferred LP Units providing net proceeds of $598 million. Distributions of $539 million paid to Participating non-controlling interests – in operating subsidiaries was primarily due to higher dividends paid out of our Colombian business and the sale of our Irish wind portfolio.

For the year ended December 31, 2017, distributions paid to LP Unitholders and Redeemable/Exchangeable Partnership Unitholders were $591 million (2016: $522 million and 2015: $461 million). We increased our distributions to $1.87 per LP Unit, an increase of 9 cents per LP Unit which took effect in the first quarter of 2017. The distributions paid to preferred shareholders, preferred limited partners’ unitholders and participating non-controlling interests - in operating subsidiaries totaled $590 million (2016: $156 million and 2015: $239 million).

Cash flows provided by financing activities totaled $2,709 million for the year ended December 31, 2016. Long-term debt – borrowings totaling $3,477 million were related to the growth in our portfolio, our subsidiary financing initiatives and the issuance of corporate medium-term notes. Long-term debt – repayments totaling $1,975 million were related to the repayment of our Series 6, medium-term notes upon maturity and our subsidiary financing initiatives. The capital provided by participating non-controlling interests – in operating subsidiaries relates to the growth in our portfolio with our institutional partners and amounted to $2,621 million. An amount of $1,540 million was paid for the shares owned by public shareholders of Isagen, in regards to the mandatory tender offers (“MTOs”), which included $6 million in related acquisition costs. The issuance of LP units and Preferred LP units provided net proceeds of $657 million and $147 million, respectively.

For the year ended December 31, 2016, distributions paid to unitholders of Brookfield Renewable or BRELP were $522 million (2015: $461 million and 2014: $480 million). We increased our distributions to $1.78 per LP Unit, an increase of 12 cents per LP Unit which took effect in the first quarter of 2016. The distributions paid to preferred shareholders, preferred limited partners’ unitholders and participating non-controlling interests - in operating subsidiaries totaled $156 million (2015: $239 million and 2014: $188 million).

Investing Activities

Cash flows used in investing activities totaled $328 million for the year ended December 31, 2017. Our acquisitions of TerraForm Global and an Irish wind facility along with investments in TerraForm Power and a European storage portfolio, totaled $62 million, net of cash acquired. Our continued investment in the development of power generating assets and sustainable capital expenditures was $217 million and $138 million, respectively. Proceeds from the sale of the Irish wind facility were $150 million.

Cash flows used in investing activities for the year ended December 31, 2016 totaled $3,191 million. Our investment in Isagen, a hydroelectric portfolio in Brazil, a hydroelectric portfolio in Pennsylvania and a wind development project in Ireland totaled $2,769 million, net of cash acquired. Our investment in the development of power generating assets and sustainable capital expenditures was $251 million and $118 million, respectively. Our investment in available-for-sale securities amounted to $60 million.

Page 126

SHARES AND UNITS OUTSTANDING

Shares and units outstanding as at December 31 are as follows:

		2017	2016
Class A Preference Shares
	Balance, beginning of year	31,035,967	33,921,463
	Preference Shares exchanged for Preferred LP Units	-	(2,885,496)
Balance, end of  year		31,035,967	31,035,967
Class A Preferred LP Units
	Balance, beginning of year	17,885,496	7,000,000
	Issuance of Preferred LP Units(1)	10,000,000	8,000,000
	Preference Shares exchanged for Preferred LP Units	-	2,885,496
Balance, end of  year		27,885,496	17,885,496
GP interest		2,651,506	2,651,506
Redeemable/Exchangeable partnership units		129,658,623	129,658,623
LP Units
	Balance, beginning of year	166,839,324	143,188,170
	Issuance of LP Units	13,247,000	23,352,208
	Distribution reinvestment plan	302,037	298,946
Balance, end of  year		180,388,361	166,839,324
Total LP Units on a fully-exchanged basis(2)		310,046,984	296,497,947

⁽¹⁾Subsequent to the end of the year, Brookfield Renewable issued 10,000,000 Series 13 Preferred LP Units. See “PART 8 - Subsequent Events”.

⁽²⁾The fully-exchanged amounts assume the exchange of all Redeemable/ Exchangeable partnership units for LP Units.

Page !Unexpected End of Formula

DIVIDENDS AND DISTRIBUTIONS

Dividends and distributions declared and paid for the year ended December 31 are as follows:

			Declared						Paid
(MILLIONS)			2017		2016		2015		2017		2016		2015
Class A Preference Shares		$	26	$	25	$	30	$	25	$	25	$	31
Class A Preferred LP Units		$	28	$	15	$	1	$	26	$	12	$	-
Participating non-controlling
	interests - in operating subsidiaries	$	539	$	119	$	208	$	539	$	119	$	208
GP interest and Incentive distributions		$	35	$	24	$	12	$	34	$	23	$	12
Redeemable/Exchangeable partnership units		$	243	$	232	$	217	$	242	$	230	$	216
LP Units		$	328	$	281	$	239	$	315	$	269	$	233

LP Unitholder distributions on an annualized, per LP Unit basis, were increased as follows:

Date of	Amount of	Annual	Distribution
Increase	Increase	Distribution	Effective Date
February 2014	$0.10	$1.55	March 2014
February 2015	$0.11	$1.66	March 2015
February 2016	$0.12	$1.78	March 2016
February 2017	$0.09	$1.87	March 2017
February 2018	$0.09	$1.96	March 2018

Contractual obligations

Please see Note 26 – Commitments, contingencies and guarantees in the audited annual consolidated financial statements, for further details on the following:

·Commitments–Water, land, and dams usage agreements, and agreements and conditions on committed acquisitions of operating portfolios and development projects

·Contingencies–Legal proceedings, arbitrations and actions arising in the normal course of business, and providing for letters of credit

·Guarantees  – Nature of all the indemnification undertakings

Off-STATEMENT OF FINANCIAL POSITION Arrangements

Brookfield Renewable has no off-statement of financial position financing arrangements.

Page !Unexpected End of Formula

PART 6 - SELECTED QUARTERLY INFORMATION

SUMMARY OF HISTORICAL QUARTERLY RESULTS

The following is a summary of unaudited quarterly financial information for the last twelve consecutive quarters on a consolidated basis:

	2017								2016								2015
(MILLIONS, EXCEPT AS NOTED)		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Total Generation (GWh) - LTA	12,198		9,098		10,674		10,364		10,319		9,092		10,728		8,843		6,067		5,164		6,929		6,307
Total Generation (GWh) - actual	11,913		9,370		11,618		10,484		8,728		7,522		8,792		9,029		6,117		4,992		6,400		5,823
Proportionate Generation (GWh) - LTA	6,030		5,053		6,279		5,889		5,739		5,068		6,214		5,341		4,609		3,948		5,348		4,844
Proportionate Generation (GWh) - actual	5,890		5,198		6,719		6,161		4,734		4,395		5,197		5,896		4,553		3,715		4,834		4,560
Net income (loss) attributable to Unitholders	$	(67)	$	(43)	$	38	$	16	$	(47)	$	(33)	$	(28)	$	43	$	(26)	$	(17)	$	17	$	29
Basic (loss) earnings per LP Unit		(0.22)		(0.14)		0.13		0.05		(0.16)		(0.12)		(0.11)		0.16		(0.09)		(0.07)		0.07		0.10
Consolidated Adjusted EBITDA		453		381		460		457		326		335		380		458		261		243		381		339
Proportionate Adjusted EBITDA		295		233		311		303		189		213		237		303		192		189		261		265
Funds From Operations		143		91		181		166		54		73		105		187		88		80		146		153
Funds From Operations per Unit		0.46		0.29		0.61		0.55		0.18		0.24		0.37		0.68		0.32		0.28		0.53		0.56
Distribution per LP Unit	0.468		0.468		0.468		0.468		0.445		0.445		0.445		0.445		0.415		0.415		0.415		0.415

Page 129

PROPORTIONATE RESULTS FOR THE FOURTH QUARTER

The following chart reflects the generation and summary financial figures on a proportionate basis  for the three months ended December 31:

		(GWh)				(MILLIONS)
		Actual Generation		LTA Generation		Revenues				Adjusted EBITDA				Funds From Operations				Net Income (Loss)
		2017	2016	2017	2016		2017		2016		2017		2016		2017		2016		2017		2016
Hydroelectric
	North America	3,076	2,589	3,143	3,142	$	217	$	162	$	144	$	91	$	100	$	47	$	(28)	$	(21)
	Colombia	978	924	935	989		51		56		26		28		14		13		7		15
	Brazil	867	451	978	891		64		46		43		33		33		26		(6)		(4)
		4,921	3,964	5,056	5,022		332		264		213		152		147		86		(27)		(10)
Wind
	North America	648	404	693	454		53		38		37		29		22		19		22		45
	Europe	128	149	146	181		12		15		7		8		6		3		(9)		(1)
	Brazil	74	74	82	82		7		5		6		4		5		2		3		1
		850	627	921	717		72		58		50		41		33		24		16		45
Solar, Storage & Other		119	143	53	-		26		10		22		2		14		(1)		(6)		(9)
Corporate		-	-	-	-		-		1		10		(6)		(51)		(55)		(50)		(73)
Total		5,890	4,734	6,030	5,739	$	430	$	333	$	295	$	189	$	143	$	54	$	(67)	$	(47)

Page 130

Funds From Operations increased by $89 million to $143 million supported by the return to long-term average generation, advancement of our organic initiatives and contributions from new acquisitions. Generation increased by 24% primarily as a result of improved hydrology in North America, as well as the contribution from our recent acquisitions and commissioned development projects. In Q4 2016, we experienced an unplanned outage at one of our Brazilian hydroelectric facilities resulting in 377 GWh of lost generation. Average realized pricing of $73 per MWh increased by 4% due primarily to strong market pricing North America.

Contributions from our recent acquisitions and the commissioning of development projects contributed $10 million to Funds From Operations for the quarter. The sale of the 137 MW Irish wind facility in the first quarter of 2017 would have contributed $2 million of Funds From Operations in the quarter.

Net loss attributable to Unitholders decreased by $20 million over the prior year as the above noted increase in Funds From Operations was offset primarily by additional depreciation on our growing portfolios and deferred tax expenses attributable to the U.S. tax reforms.

Page 131

PART 7 - BUSINESS RISKS AND RISK MANAGEMENT

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Management’s objectives are to protect Brookfield Renewable against material economic exposures and variability of results from various financial risks that include electricity price risk, foreign currency risk, interest rate risk, credit risk, and liquidity risk. These risks are further discussed in Note 5 - Risk Management and Financial Instruments in the audited annual consolidated financial statements.

The following table outlines Brookfield Renewable’s financial risks and how they are managed:

Financial Risk	Description of Risk	Management of Risk
Electricity price	We have exposure to movements in the market price of electricity.	·Enter into long-term contracts that specify the price at which electricity is sold ·Maintain a portfolio of short, medium, and long-term contracts to mitigate our exposure to short-term fluctuations in electricity prices ·Ensure limits and controls are in place for trading activities ·As of December 31, 2017, we had approximately 92% (2016: 95%) of 2018 production, excluding Brazil and Colombia, on a proportionate basis under short-term and long-term power purchase agreements and financial contracts. See “Part 4 – Financial Performance Review on Proportionate Information”
Foreign currency	We are exposed to foreign currency risk – including Canadian dollar, Brazilian real, Euro, British pound sterling, Colombian peso, Indian rupee, South African rand, Malaysian ringgit, Thai baht and Chinese yuan – related to operations, anticipated transactions, and certain foreign currency debt.	·Enter into foreign currency contracts designed to minimize the exposure to foreign currency fluctuations ·40% of cash flow is generated in the United States while Canadian Dollar and Euro exposure, representing 30% of our portfolio, is proactively managed through foreign currency contracts ·No foreign currency contracts to hedge our South American and Asian exposures – representing 30% of our portfolio – due to the high associated costs.  However, these specific exposures are mitigated by the annual inflation-linked escalations in our power purchase agreements

Page 132

Financial Risk	Description of Risk	Management of Risk
Interest rate	We are exposed to risk on the interest rates of our debt, and on dividend and distribution rate resets on our Preferred Shares and Preferred LP Units, respectively.	·Assets largely consist of long duration physical assets, and financial liabilities consist primarily of long-term fixed rate debt or floating-rate debt that has been swapped to fixed rates with interest rate financial instruments to minimize the exposure to interest rate fluctuations ·Enter into interest rate contracts to lock-in fixed rates on certain anticipated future debt issuances ·Our proportionate floating rate exposure represents 13% of our total debt, after affecting for variable rate debt that has been hedged through the use of interest rate swaps.  Our floating rate exposure arises primarily from our South American operations, as we have no interest rate swaps to hedge our exposures due to the high associated costs.
Credit	We are exposed to credit risk from operating activities and certain financing activities, the maximum exposure of which is represented by the carrying amounts reported in the statements of financial position. We are exposed to credit risk if counterparties to our energy contracts, interest rate swaps, forward foreign exchange contracts and physical electricity and gas transactions as well as trade receivables are unable to meet their obligations.	·Diverse counterparty base with long standing credit histories ·Exposure to counterparties with investment-grade credit ratings ·Use of standard trading contracts and other standard credit risk mitigation techniques ·As at December 31, 2017, 99% (2016: 95%) of Brookfield Renewable’s trade receivables were current

Page 133

Financial Risk	Description of Risk	Management of Risk
Liquidity	We are exposed to liquidity risk for financial liabilities. We are also subject to internal liquidity risk because we conduct our business activities through separate legal entities (subsidiaries and affiliates) and are dependent on receipts of cash from those entities to defray corporate expenses and to make dividend and distribution payments to shareholders and Unitholders, respectively. Under the credit agreements for subsidiary debt, it is conventional for distributions of cash to Brookfield Renewable to be prohibited if the loan is in default (notably for non-payment of principal or interest) or if the entity fails to achieve a benchmark debt service coverage ratio.  For the year ended December 31, 2017, Brookfield Renewable and its subsidiaries were in compliance with majority of its debt covenants except covenants mentioned in Note 18 – Capital Management.	·As at December 31, 2017, available liquidity was $1.5 billion.  Liquidity is comprised of our share of cash and cash equivalents, available-for-sale securities and undrawn corporate line of credit available of $168 million, $159 million and $1.2 billion, respectively.  Details of the available portion of credit facilities and debt maturity ladder are included in “PART 5 - Liquidity and Capital Resources” ·Effective and regular monitoring of debt covenants ·Target investment grade debt or debt with investment grade characteristics with the ability to absorb volatility in cash flows ·Long-term duration of debt instruments and the diversification in maturity dates over an extended period of time ·Sufficient cash from operating activities, access to undrawn credit facilities, and possible capital markets financing to fund our operations and fulfill our obligations as they become due ·Ensure access to public capital markets and maintain a strong investment grade credit rating

Page 134

PART 8 - CRITICAL ESTIMATES, ACCOUNTING POLICIES AND INTERNAL CONTROLS

Critical ESTIMATES AND CRITICAL JUDGMENTS in applying accounting policies

The audited annual consolidated financial statements are prepared in accordance with IFRS, which require the use of estimates and judgments in reporting assets, liabilities, revenues, expenses and contingencies. In the judgment of management, none of the estimates outlined in Note 1 – Basis of preparation and significant accounting policies in our audited annual consolidated financial statements are considered critical accounting estimates as defined in Canadian National Instrument 51-102 – Continuous Disclosure Obligations with the exception of the estimates related to the valuation of property, plant and equipment and the related deferred income tax liabilities. These assumptions include estimates of future electricity prices, discount rates, expected long-term average generation, inflation rates, terminal year and operating and capital costs, the amount, the timing and the income tax rates of future income tax provisions. Estimates also include determination of accruals, purchase price allocations, useful lives, asset valuations, asset impairment testing, deferred tax liabilities, decommissioning retirement obligations and those relevant to the defined benefit pension and non-pension benefit plans. Estimates are based on historical experience, current trends and various other assumptions that are believed to be reasonable under the circumstances.

In making estimates, management relies on external information and observable conditions where possible, supplemented by internal analysis, as required. These estimates have been applied in a manner consistent with that in the prior year and there are no known trends, commitments, events or uncertainties that we believe will materially affect the methodology or assumptions utilized in this report. These estimates are impacted by, among other things, future power prices, movements in interest rates, foreign exchange volatility and other factors, some of which are highly uncertain, as described in the “Risk Factors” section. The interrelated nature of these factors prevents us from quantifying the overall impact of these movements on Brookfield Renewable’s financial statements in a meaningful way. These sources of estimation uncertainty relate in varying degrees to substantially all asset and liability account balances. Actual results could differ from those estimates.

Critical estimates

Brookfield Renewable makes estimates and assumptions that affect the carrying value of assets and liabilities, disclosure of contingent assets and liabilities and the reported amount of income and other comprehensive income (“OCI”) for the year. Actual results could differ from these estimates. The estimates and assumptions that are critical to the determination of the amounts reported in the consolidated financial statements relate to the following:

(i)         Property, plant and equipment

The fair value of Brookfield Renewable’s property, plant and equipment is calculated using estimates and assumptions about future electricity prices from renewable sources, anticipated long-term average generation, estimated operating and capital expenditures, future inflation rates and discount rates, as described in Note 12 - Property, plant and equipment, at fair value in our audited annual consolidated financial statements. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies – Property, plant and equipment in our audited annual consolidated financial statements for further details.

Estimates of useful lives and residual values are used in determining depreciation. To ensure the accuracy of useful lives and residual values, these estimates are reviewed on an annual basis.

(ii)         Financial instruments

Brookfield Renewable makes estimates and assumptions that affect the carrying value of its financial instruments, including estimates and assumptions about future electricity prices, long-term average generation, capacity prices, discount rates and the timing of energy delivery. Non-financial instruments are valued using estimates of future electricity prices which are estimated by considering

Page 135

broker quotes for the years in which there is a liquid market and for the subsequent years Brookfield Renewable’s best estimate of electricity prices that would allow new entrants into the market. The fair value of interest rate swaps is the estimated amount that another party would receive or pay to terminate the swap agreements at the reporting date, taking into account current market interest rates. This valuation technique approximates the net present value of future cash flows. See Note 5 - Risk Management and Financial Instruments in our audited annual consolidated financial statements for more details.

(iii)        Deferred income taxes

The consolidated financial statements include estimates and assumptions for determining the future tax rates applicable to subsidiaries and identifying the temporary differences that relate to each subsidiary. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply during the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the consolidated statements of financial position dates. Operating plans and forecasts are used to estimate when the temporary difference will reverse.

Critical judgments in applying accounting policies

The following are the critical judgments that have been made in applying the accounting policies used in the consolidated financial statements and that have the most significant effect on the amounts in the consolidated financial statements:

(i)Preparation of consolidated financial statements

These consolidated financial statements present the financial position, results of operations and cash flows of Brookfield Renewable. Judgment is required in determining what assets, liabilities and transactions are recognized in the consolidated financial statements as pertaining to Brookfield Renewable’s operations. 

(ii)Common control transactions

Common control business combinations specifically fall outside of scope of IFRS 3, Business Combinations (“IFRS 3”), and as such management has used its judgment to determine an appropriate policy to account for these transactions. Consideration was given to other relevant accounting guidance within the framework of principles in IFRS and that reflects the economic reality of the transactions, in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors (“IAS 8”). As a result, the consolidated financial statements account for assets and liabilities acquired at the previous carrying value on the predecessor’s financial statements. Differences between the consideration given and the assets and liabilities received are recorded directly to equity.

(iii)Property, plant and equipment

The accounting policy relating to Brookfield Renewable’s property, plant and equipment is described in Note 1(f) - Property plant and equipment and revaluation method in our audited annual consolidated financial statements. In applying this policy, judgment is used in determining whether certain costs are additions to the carrying amount of the property, plant and equipment as opposed to repairs and maintenance. If an asset has been developed, judgment is required to identify the point at which the asset is capable of being used as intended and to identify the directly attributable costs to be included in the carrying value of the development asset. The useful lives of property, plant and equipment are determined by independent engineers periodically with an annual review by management.

Annually, Brookfield Renewable determines the fair value of its property, plant and equipment using a methodology that it has judged to be reasonable. The methodology is generally a 20 year discounted cash flow model. Twenty years is the period considered reasonable as Brookfield Renewable has 20 year capital plans and it believes a reasonable third party would be indifferent between extending the cash flows further in the model versus using a discounted terminal value.

The valuation model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. With respect to estimated future generation that does not incorporate long-term power purchase agreement pricing, the cash flow model uses estimates of future electricity

Page 136

prices using broker quotes from independent sources for the years in which there is a liquid market. The valuation of power generating assets not linked to long-term power purchase agreements also requires the development of a long-term estimate of future electricity prices. In this regard the valuation model uses a discount to the all-in cost of construction with a reasonable return, to secure energy from new renewable on-shore wind development resources as the benchmark that will establish the market price for electricity for renewable resources.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth by the year 2025 in North America and Colombia, 2023 in Europe, and 2021 in Brazil.  Based on current supply and demand fundamentals, Brookfield Renewable revised the year of new entry in North America to 2025 from 2023.  The year of new entry is viewed as the point when generators must build additional capacity to maintain system reliability and provide an adequate level of reserve generation with the retirement of older coal fired plants and rising environmental compliance costs in North America and Europe, and overall increasing demand in Colombia and Brazil. For the North American and European businesses, Brookfield Renewable has estimated a discount to these new-build wind prices to determine renewable electricity prices for hydroelectric and wind facilities. In Brazil and Colombia, the estimate of future electricity prices is based on a similar approach as applied in North America using a forecast of the all-in cost of development.

Discount rates are determined each year by considering the current interest rates, average market cost of capital as well as the price risk and the geographical location of the operational facilities as judged by management. Inflation rates are also determined by considering the current inflation rates and the expectations of future rates by economists. Operating costs are based on long-term budgets escalated for inflation. Each operational facility has a 20 year capital plan that it follows to ensure the maximum life of its assets is achieved.  Foreign exchange rates are forecasted by using the spot rates and the available forward rates, extrapolated beyond the period available. The inputs described above to the discounted cash flow model require management to consider facts, trends and plans in making its judgments as to what derives a reasonable fair value of its property, plant and equipment.

(iv)Financial instruments

The accounting policy relating to Brookfield Renewable’s financial instruments is described in Note 1(i) — Financial instruments in our audited annual consolidated financial statements. In applying the policy, judgments are made in applying the criteria set out in IAS 39, Financial Instruments: Recognition and Measurement (“IAS 39”), to record financial instruments at fair value through profit and loss, and the assessments of the effectiveness of hedging relationships.

(v)        Deferred income taxes

The accounting policy relating to Brookfield Renewable’s income taxes is described in Note 1(k) — Income taxes in our audited annual consolidated financial statements. In applying this policy, judgments are made in determining the probability of whether deductions, tax credits and tax losses can be utilized.

Future changes in accounting policies

(i)      Financial Instruments

In July 2014, the IASB issued the final version of IFRS 9, Financial Instruments (“IFRS 9”) which reflects all phases of the financial instruments project and replaces IAS 39, Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. This standard establishes principles for the financial reporting of financial assets and financial liabilities that will present relevant and useful information to users of financial statements for their assessment of the amounts, timing and uncertainty of an entity’s future cash flows. The new standard makes several improvements to IAS 39; mostly notably adopting a principle based approach to hedge accounting. While this does not change the type of hedging relationships or the requirement to measure ineffectiveness, it simplifies the application of hedge accounting and should allow for better alignment of risk management strategies with accounting presentation. Other changes include replacing the multiple financial asset impairment models in IAS 39 with a single model based on expected credit losses on all financial assets, and replacing the existing

Page 137

complex classifications structure with a business model approach based on the intent and nature of the cash flows.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early application permitted. The adoption of IFRS 9 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard retrospectively with no restatement of comparative periods. The assessment of financial assets and liabilities under the new classification methodology has been completed. Hedging documentation has been updated for compliance with IFRS 9 and management has updated risk management policies and internal controls to align with the new standard. Management has also assessed the impact of the new impairment requirements for financial assets. There are no material adjustments from the adoption of the standard.

(ii)     Revenue recognition

IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) was issued by IASB on May 28, 2014. IFRS 15 outlines a single comprehensive model to account for revenue arising from contracts with customers and will replace the majority of existing IFRS requirements on revenue recognition including IAS 18, Revenue, IAS 11, Construction Contracts and related interpretations. The core principle of the standard is to recognize revenue to depict the transfer of goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard has prescribed a five-step model to apply the principles. The standard also specifies how to account for the incremental costs of obtaining a contract and the costs directly related to fulfilling a contract as well as requiring more informative and relevant disclosures. IFRS 15 applies to nearly all contracts with customers, unless covered by another standard, such as leases, financial instruments and insurance contracts. In April 2016, the IASB issued amendments to IFRS 15, which provided additional guidance on the identification of performance obligations, on assessing principal versus agent considerations and on licensing revenue. The amendments also provide additional transition relief upon initial adoption of IFRS 15 and have the same effective date as the IFRS 15 standard.

IFRS 15 is effective for annual periods beginning on or after January 1, 2018, with early adoption permitted. The adoption of IFRS 15 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard using the modified retrospective approach. This method results in a cumulative catch-up adjustment to equity as of January 1, 2018 as if the standard had always been in effect. Management has completed its review of material revenue streams. The majority of Brookfield Renewable’s revenue streams are within the scope of IFRS 15 and are include the sale of energy, capacity and renewable energy credits through power purchase agreements or through merchant mechanisms. Based on management’s analysis, substantially all of the contracts currently in place for the year beginning on January 1, 2018 do not contain a difference in the timing or measurement of revenue recognition under the new standard and the impact of both the cumulative catch up and ongoing revenue recognition is expected to not be material to the overall statements of Brookfield Renewable.

(iii)     Leases

IFRS 16, Leases  (“IFRS 16”) was issued by the IASB on January 13, 2016. IFRS 16 brings most leases onto the statement of financial position for lessees under a single model, eliminating the distinction between operating and finance leases. Lessor accounting remains largely unchanged and the distinction between operating and finance leases is retained. Under IFRS 16 a lessee recognizes a right-of-use asset and a lease liability. The right-of-use asset is treated similarly to other non-financial assets and depreciated accordingly, and the liability accrues interest. The lease liability is initially measured at the present value of the lease payments payable over the lease term, discounted at the rate implicit in the lease. Lessees are permitted to make an accounting policy election, by class of underlying asset, to apply a method like IAS 17’s operating lease accounting and not recognize lease assets and lease liabilities for leases with a lease term of 12 months or less, and on a lease-by-lease basis, to apply a method similar to current operating lease accounting to leases for which the underlying asset is of low value. IFRS 16 supersedes IAS 17, Leases and related interpretations. A lessee will apply IFRS 16 to its leases either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying IFRS 16 being recognized at the date of initial application. IFRS 16 is effective for annual periods beginning on or after January 1, 2019, with early adoption permitted. Management has formed its

Page 138

adoption working group and participated in planning sessions with Brookfield Asset Management. Management continues to evaluate the impact of IFRS 16 on the consolidated financial statements.

Subsequent eventS

On January 16, 2018, Brookfield Renewable issued 10,000,000 Series 13 Preferred LP Units at a price of C$25 per unit for gross proceeds of C$250 million ($201 million).

On January 19, 2018, Brookfield Renewable completed financing associated with its equity-accounted 2.1 GW pumped storage facility in the United Kingdom by securing £60 million ($83 million) of long-term debt and £90 million ($125 million) letter of credit facility. The long-term debt matures in 2021 and bears interest at LIBOR plus a margin of 2.75%.

On January 29, 2018, Brookfield Renewable completed R$130 million ($40 million) of financing with respect to a 19 MW hydroelectric facility currently under construction in Brazil. The loan bears interest at a rate of TJLP plus 2.15% and matures in 2038.

On February 15, 2018, Brookfield Renewable completed a refinancing associated with a 296 MW hydroelectric facility in the United States. The financing was a $350 million interest only green bond bearing interest at 4.5%, maturing in 2033.  Proceeds were used to repay the existing principal amount of $315 million and the excess was distributed to investors.

On February 22, 2018, TerraForm Global issued $400 million of senior notes at 6.13%, maturing in March 2026.  Along with cash on the balance sheet, proceeds were used to repay the existing $760 million of 9.75% senior notes due in 2022. Additionally, TerraForm Global secured a $45 million revolving credit facility, maturing in February 2021.

On February 27, 2018, Brookfield Renewable completed a COP 750 billion ($262 million) bond refinancing associated with the Colombian business.

Page 139

PART 9 - PRESENTATION TO STAKEHOLDERS AND PERFORMANCE Measurement

PRESENTATION TO PUBLIC STAKEHOLDERS

Equity

Brookfield Renewable’s consolidated equity interests include the non-voting LP Units held by public LP Unitholders and Brookfield, Redeemable/Exchangeable limited partnership units in BRELP, a holding subsidiary of Brookfield Renewable, held by Brookfield, and GP interest in BRELP held by Brookfield. The LP Units and the Redeemable/Exchangeable partnership units have the same economic attributes in all respects, except that the Redeemable/Exchangeable partnership units provide Brookfield the right to request that their units be redeemed for cash consideration. In the event that Brookfield exercises this right, Brookfield Renewable has the right, at its sole discretion, to satisfy the redemption request with LP Units, rather than cash, on a one-for-one basis. Brookfield, as holder of Redeemable/Exchangeable partnership units, participates in earnings and distributions on a per unit basis equivalent to the per unit participation of the LP Units. As Brookfield Renewable, at its sole discretion, has the right to settle the obligation with LP Units, the Redeemable/Exchangeable partnership units are classified under equity, and not as a liability. 

Given the exchange feature referenced above, we are presenting LP Units, Redeemable/Exchangeable partnership units, and the GP interest as separate components of consolidated equity. This presentation does not impact the total income (loss), per unit or share information, or total consolidated equity.

As at the date of this report, Brookfield owns an approximate 60% LP Unit interest, on a fully-exchanged basis, and all general partnership interests in Brookfield Renewable, representing a 0.01% interest, while the remaining approximately 40% is held by the public.

Voting Agreements with Affiliates

Brookfield Renewable has entered into voting agreements with Brookfield, whereby Brookfield Renewable gained control of the entities that own certain United States, Brazil and Europe renewable power generating operations as well as the entity that owns the renewable power generating operations acquired as part of the acquisition of TerraForm Global. Brookfield Renewable has also entered into a voting agreement with its consortium partners in respect of the Colombian operations. The voting agreements provide Brookfield Renewable the authority to direct the election of the Boards of Directors of the relevant entities, among other things, and therefore provide Brookfield Renewable with control. Accordingly, Brookfield Renewable consolidates the accounts of these entities.

Brookfield Renewable has also entered into a voting agreement with Brookfield, whereby Brookfield Renewable gained certain rights in respect of TerraForm Power and its subsidiaries. This voting agreement provides Brookfield Renewable the authority to direct the election of one member of the Board of Directors of the relevant entity, among other things, and therefore provide Brookfield Renewable with significant influence over TerraForm Power. Accordingly, Brookfield Renewable equity account the accounts of these entities.

For entities previously controlled by Brookfield Asset Management, the voting agreements entered into do not represent business combinations in accordance with IFRS 3, as all combining businesses are ultimately controlled by Brookfield Asset Management both before and after the transactions were completed. Brookfield Renewable accounts for these transactions involving entities under common control in a manner similar to a pooling of interest, which requires the presentation of pre-voting agreement financial information as if the transactions had always been in place. Refer to Note 1(o)(ii) –Critical judgments in applying accounting policies - Common control transactionsin our audited annual consolidated financial statements for our policy on accounting for transactions under common control.

Page 140

Performance Measurement

Net Income (Loss)

Net income (loss) is calculated in accordance with IFRS.

Net income (loss) is an important measure of profitability, in particular because it has a standardized meaning under IFRS. The presentation of net income (loss) on an IFRS basis for our business will often lead to the recognition of a loss or a year-over-year decrease in income even though the underlying cash flows generated by the assets are supported by strong margins and stable, long-term power purchase agreements. The primary reason for this is that accounting rules require us to recognize a significantly higher level of depreciation for our assets than we are required to reinvest in the business as sustaining capital expenditures.

Adjusted EBITDA

EBITDA is a non-IFRS measure used by investors to analyze the operating performance of companies.

Brookfield Renewable uses Adjusted EBITDA to assess the performance of its operations before the effects of interest expense, income taxes, depreciation, management service costs, non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments, distributions to preferred limited partners and other typical non-recurring items. Brookfield Renewable adjusts for these factors as they may be non-cash, unusual in nature and/or are not factors used by management for evaluating operating performance.

As compared to the preceding years, we revised our definition of Adjusted EBITDA to include our proportionate share of Adjusted EBITDA from equity-accounted investments. In preceding years, we included our proportionate share of Funds From Operations from equity-accounted investments. We revised our definition as we believe it provides a more meaningful measure for investors to evaluate our financial and operating performance on an allocable basis to Unitholders.

Funds From Operations and Funds From Operations per Unit

Funds From Operations is a non-IFRS measure used by investors to analyze net earnings from operations without the effects of certain volatile items that generally have no current financial impact or items not directly related to the performance of the business.

Brookfield Renewable uses Funds From Operations to assess the performance of the business before the effects of deferred income taxes, depreciation, non-cash portion of non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments and other typical non-recurring items as these are not reflective of the performance of the underlying business. In our audited annual consolidated financial statements we use the revaluation approach in accordance with IAS 16, Property, Plant and Equipment, whereby depreciation is determined based on a revalued amount, thereby reducing comparability with our peers who do not report under IFRS as issued by the IASB or who do not employ the revaluation approach to measuring property, plant and equipment. We add back deferred income taxes on the basis that we do not believe this item reflects the present value of the actual tax obligations that we expect to incur over our long-term investment horizon.

Brookfield Renewable believes that analysis and presentation of Funds From Operations on this basis will enhance an investor’s understanding of the performance of the business. Funds From Operations per Unit is not a substitute measure of performance for earnings per share and does not represent amounts available for distribution to LP Unitholders.

Adjusted Funds From Operations

Adjusted Funds From Operations is a non-IFRS measure used by investors to analyze net earnings from operations without the effects of certain volatile items that generally have no current financial impact or items not directly related to the performance of the business but also adjusted for sustaining capital expenditures.

Page 141

Adjusted sustaining capital expenditures are an estimate made by management of the amount of ongoing capital investment required to maintain the condition of all our facilities and current revenues.

Annually, Brookfield Renewable determines the fair value of its property, plant and equipment using a 20-year discounted cash flow model with each operational facility having a 20-year capital plan. In addition, the useful lives of property, plant and equipment are determined periodically by independent engineers and are reviewed annually by management.

Management considers several items in estimating adjusted sustaining capital expenditures. Such factors include, but are not limited to, review and analysis of historical capital spending, the annual budgeted capital expenditures, management’s 5-year business plan, and independent third-party engineering assessments.

Capital expenditures do not occur evenly over the life of our assets. Adjusted sustaining capital expenditures are intended to reflect an average annual spending level based on the 20-year capital plan.

Accounting rules require us to recognize a significantly higher level of depreciation for our assets than we are required to reinvest in the business as sustaining capital expenditures. This higher level of depreciation is primarily attributed to: 1) our election to annually fair value property, plant and equipment under IFRS; and 2) accounting useful life is not always reflective of the perpetual nature of a hydroelectric facility.

Brookfield Renewable uses Adjusted Funds From Operations to also assess performance of the business and defines it as Funds From Operations less Brookfield Renewable’s proportionate share of adjusted sustaining capital expenditures (based on long-term sustaining capital expenditure plans) which are recurring in nature and used to maintain the reliability and efficiency of our power generating assets over our long-term investment horizon.

Neither Funds From Operations nor Adjusted Funds From Operations are intended to be representative of cash provided by operating activities or results of operations determined in accordance with IFRS. Furthermore, these measures are not used by the CODM to assess Brookfield Renewable’s liquidity.

5.B              LIQUIDITY AND CAPITAL RESOURCES

See Item 5.A “Operating Results – Liquidity and Capital Resources”

5.C              RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC.

None.

5.D              TREND INFORMATION

See Item 4.B “Business Overview — Renewable Power Growth Opportunity” to understand our global renewable power drivers, core markets and growth opportunities.

See Item 5.A “Operating Results” for information on the following trend information: 

· “— Financial Performance Review on Proportionate Information” (variability of generation);

· “— Liquidity and Capital Resources” (funding of growth initiatives, capital expenditures, distributions and general business purposes); and

·“— Contract Profile” (Funds From Operations).

5.E              OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

5.F              TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See Item 5.A “Operating Results – Liquidity and Capital Resources”

Page 142

ITEM 6.       DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES           

6.A              DIRECTORS AND SENIOR MANAGEMENT

Board of Directors of the Managing General Partner

As required by Bermuda law, the Amended and Restated Limited Partnership Agreement of BEP provides for the management and control of BEP by a general partner rather than a board of directors and officers. The Managing General Partner, which is a wholly-owned subsidiary of Brookfield Asset Management, serves as BEP’s general partner and has a board of directors. The Managing General Partner has sole responsibility and authority for the central management and control of BEP, which is exercised through its board of directors. The directors of the Managing General Partner each serve as a director until a successor is appointed to replace them.

The board of directors of the Managing General Partner is comprised of seven directors, five of whom are independent pursuant to the NYSE Listed Company Manual and within the meaning of Canadian National Instrument 58-101 – Disclosure of Corporate Governance Practices. The following table presents certain information concerning the current board of directors of the Managing General Partner as of the date of this Form 20-F.

Name and Residence(1)	Age	Position	Principal Occupation
Jeffrey Blidner	69	Chair	Vice Chairman of Brookfield Asset Management
Ontario, Canada
Eleazar de Carvalho Filho(2)	60	Director	Founder of Virtus BR Partners and Corporate Director; Founder of Sinfonia Consultoria e Participações
Sao Paulo, Brazil
John Van Egmond(3)	68	Director	Financial Consultant, Ozona Corporation
Arizona, United States
Lars Josefsson	67	Director	Managing Director, Contributor AB
Stockholm, Sweden
David Mann(2)(3)(4)	78	Director	Corporate Director
Nova Scotia, Canada
Lou Maroun(3)	67	Director	Chairman of Sigma Real Estate Advisors/Sigma Capital Corporation
Warwick, Bermuda
Patricia Zuccotti(2)	70	Director	Corporate Director
Washington, United States

⁽¹⁾The business address for each of the directors is 73 Front Street, Hamilton, HM 12, Bermuda.

⁽²⁾Member of the Audit Committee.  Patricia Zuccotti is the Chair of the Audit Committee and is the “audit committee financial expert” as defined by the SEC.

⁽³⁾Member of the Nominating and Governance Committee.  David Mann is the Chair of the Nominating and Governance Committee.

Page 143

⁽⁴⁾Lead Independent Director.

Biographical information for each of the directors is included below.

Jeffrey Blidner. Mr. Blidner is the Chair of the board of directors of the Managing General Partner. Mr. Blidner is also a Vice Chairman of Brookfield Asset Management. In that capacity he is responsible for strategic planning as well as transaction execution. He is also the Chief Executive Officer of Brookfield Asset Management’s Private Funds Group.  He is the Chair and a director of Brookfield Business Partners L.P., and a director of Brookfield Asset Management, Brookfield Property Partners L.P. and Brookfield Infrastructure Partners L.P. Prior to joining Brookfield in 2000, Mr. Blidner was a senior partner at a Canadian law firm.  He received his law degree from York University’s Osgoode Hall Law School and was called to the Bar in Ontario as Gold Medalist.

Eleazar de Carvalho Filho. Mr. de Carvalho Filho is a director of the Managing General Partner. Mr. de Carvalho Filho is a founding partner of Virtus BR Partners, an independent advisory company. He was formerly the President and Managing Director of the Brazilian National Development Bank and has served as the Chief Executive Officer of Unibanco Investment Bank. Mr. de Carvalho Filho served as the non-executive Chairman of BHP Billiton Brazil (2006-2011) and served on the board of directors of Petrobras, Eletrobrás and Vale, among others. Mr. de Carvalho Filho is currently a director of Cnova N.V.  He is also a director and audit committee member of TechnipFMC plc (formerly FMC Technologies, Inc.) and Grupo Pão de Açúcar.  In January 2018, Mr. de Carvalho Filho was named to the transitional board of directors of Oi S.A., a large Brazilian company.  Mr. de Carvalho Filho is the President of the Board of Trustees of the Brazilian Symphony Orchestra. Mr. de Carvalho Filho holds a Master of Arts in International Relations from The Johns Hopkins University in Washington, D.C. and a Bachelor of Arts with a major in Economics from New York University.

John Van Egmond. Mr. Van Egmond is a director of the Managing General Partner. Mr. Van Egmond is presently a financial consultant with Ozona Corporation (a general consulting company) in Tucson, Arizona. He was formerly the acting President and Chief Executive Officer and director of Wilshire Technologies, Inc., where he was responsible for all financial, operational, sales and marketing and human resource functions. Mr. Van Egmond was also the President of Century Power Corporation, an independent power producer based in Tucson, Arizona. Mr. Van Egmond is a Certified Public Accountant and received a Bachelor of Science in accounting in 1972 from Montana State University.

Lars Josefsson. Mr. Josefsson is a director of the Managing General Partner. Mr. Josefsson was formerly President and Chief Executive Officer of Vattenfall AB (2000-2010), Celsius AB (1997-2000) and various positions with Ericsson over a 24-year period. Mr. Josefsson is also a member of the boards of directors of Robert Bosch GmbH and Holmen AB and is Chairman of the board of directors of Burntisland Fabrication Ltd. He is also Chairman and Managing Partner of BioElectric Solutions LGJ AB, the founder of the Biomass for Electricity Initiative and Foundation and a member of the board of trustees of Hand in Hand International. Mr. Josefsson graduated from Chalmers University of Technology in Applied Physics with a Master of Science in 1973 and in 1986 graduated from IMD, Lausanne, PED. Mr. Josefsson is an Honorary Professor in Physics, Brandenburg Technical University, Cottbus, Germany.

David Mann. Mr. Mann is the lead independent director of the Managing General Partner. Mr. Mann formerly served as President and Chief Executive Officer of Nova Scotia Power Inc. (1996-2004) and Vice Chairman (2004-2005) and President and Chief Executive Officer (1998-2004) of Emera Inc., a TSX-listed energy and services company that invests in electrical generation, transmission and distribution. Mr. Mann is a Corporate Director and prior to January 1, 2016, served as Counsel at the law firm Cox & Palmer. He has over 30 years of experience in the practice of corporate and commercial law, with a particular emphasis on corporate finance and public utility regulation. He retired as Chairman of Logistec Corporation in 2016 but remains a director and a member of the corporation’s Audit Committee.  He is also the Audit Committee Chairman of NewGrowth Corp., Acadian Timber Corp. and Allbanc Split Corp II.Mr. Mann holds a Bachelor of Commerce and a Bachelor of Laws from Dalhousie University and a Master of Laws from the University of London.

Lou Maroun. Mr. Maroun is a director of the Managing General Partner. Mr. Maroun was formerly the Executive Chairman of ING Real Estate Canada, and held executive positions in a number of real estate companies where he was responsible for overseeing operations, real estate transactions, asset

Page 144

and property management, as well as many other related functions. Mr. Maroun is a director of Brookfield Property Partners L.P. where he is a member of the Audit Committee and the Chair of the Governance and Nominating Committee. Mr. Maroun is also Chairman of Sigma Real Estate Advisors and Sigma Capital Corporation and is on the board of directors and is Chairman of Summit Industrial Income REIT. Mr. Maroun graduated from the University of New Brunswick in 1972 with a Bachelor’s degree, majoring in psychology, followed by a series of post graduate studies in finance and mortgage underwriting. In January of 2007, Mr. Maroun was elected a Fellow of the Royal Institute of Chartered Surveyors.

Patricia Zuccotti. Ms. Zuccotti is a director of the Managing General Partner. Ms. Zuccotti was formerly Senior Vice President, Chief Accounting Officer and Controller of Expedia, Inc. (2005-2011). Prior to joining Expedia, Ms. Zuccotti was the Director, Enterprise Risk Services of Deloitte & Touche LLP (2003-2005). Ms. Zuccotti is a director of Brookfield Business Partners L.P. where she is the Chair of the Audit Committee. Ms. Zuccotti is a Certified Public Accountant (inactive) and received her Masters of Business Administration, majoring in accounting and finance, from the University of Washington and a Bachelor of Arts, majoring in political science, from Trinity College.

Director LP Unit Ownership Requirements

The Managing General Partner believes that directors can better represent Brookfield Renewable’s Unitholders if they have economic exposure to Brookfield Renewable LP Units. Brookfield Renewable expects each external director to hold sufficient LP Units such that the acquisition cost of such units is equal to at least two times their annual retainer (the “Ownership Requirement”). Directors are required to purchase limited partnership units on an annual basis in an amount not less than 20% of the Ownership Requirement until they have met the Ownership Requirement. Directors are required to achieve the Ownership Requirement within five years of joining the Board. In the event of an increase in the annual retainer fee, the directors will have two years from the date of the change to comply with the revised Ownership Requirement. In the case of directors who have served on the board of directors less than five years at the date of the change, such Directors will be required to comply with the Ownership Requirement by the date that is the later of: (i) the fifth anniversary of their appointment to the board of directors and (ii) two years following the date of the change in retainer fee. During the year ended December 31, 2017, our General Partner paid an annual retainer of $100,000 per year to each director serving on its board, with additional amounts payable to directors who are also serving as chair of the board of directors or one of its committees, or as lead independent director. Subsequent to year end on February 6, 2018, the Board of directors approved a $25,000 increase to the annual retainer paid to each director bringing the total annual retainer payable to $125,000. There was no change to the amounts paid for service as chair of a committee or as lead independent director. All of Brookfield Renewable’s external directors are in compliance with the Ownership Requirement.

Additional Information About Directors and Officers

To our knowledge, within the past ten years, no director or executive officer of the Managing General Partner and no employee of the Service Provider who performs an executive function for BEP has (a) served as a director, chief executive officer or chief financial officer of any company that was subject to a “cease trade” or similar order, or an order denying the relevant company access to any exemption under securities legislation, which remained in effect for more than 30 consecutive days, and that was issued (i) while he or she was acting as director, chief executive officer or chief financial officer, or (ii) after he or she ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while he or she was a director, chief executive officer or chief financial officer, (b) served as a director or executive officer of any company that, while he or she was acting in that capacity, or within a year after he or she ceased to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the company’s assets, or (c) become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold his or her assets.  In January 2018, Mr. de Carvalho Filho was appointed to the transitional board of directors of Oi S.A., a bankrupt telecommunications company in Brazil. As of the date of this Form 20-F, Oi S.A. remains bankrupt.  Mr. de Carvalho Filho was not on the board of directors at the time that Oi S.A.

Page 145

was declared bankrupt and was appointed to the transitional board after serving as a strategic advisor to certain bondholders.

To our knowledge, no director or executive officer of the Managing General Partner and no employee of the Service Provider who performs an executive function for BEP, nor any personal holding company thereof owned or controlled by them, (i) has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or (ii) has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

To our knowledge, within the past ten years, no director or executive officer of our Managing General Partner and no employee of the Service Provider who performs an executive function for BEP, nor any personal holding company thereof owned or controlled by them, has become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, has become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold his or her assets or the assets of his or her holding company. 

Our Management

The Managing General Partner does not have any employees. Instead, members of Brookfield’s senior management and other individuals from Brookfield’s global affiliates are drawn upon to fulfill the Service Provider’s obligations to provide us with management services under our Master Services Agreement. The following table presents certain information concerning our core senior management team that is principally responsible for our operations as well as their positions with the Service Provider as of the date of this Form 20-F. In February 2018, the following changes were made to the senior management team of the Service Provider: (i) Mr. Nicholas Goodman resigned as Chief Financial Officer and began another role with Brookfield; and (ii) Mr. Wyatt Hartley, Senior Vice President, Finance, was named Chief Financial Officer. The further disclosure required under Canadian securities laws regarding the compensation of certain members of our core senior management team will be separately filed within 140 days of December 31, 2017.

Name	Years of experience in relevant industry or role	Years at Brookfield	Current Position with the Service Provider
Harry Goldgut	33	21	Group Chairman
Richard Legault	33	30	Group Chairman
Sachin Shah	19	16	Chief Executive Officer
Wyatt Hartley	12	8	Chief Financial Officer
Jennifer Mazin	19	4	General Counsel

Each of the members of our core senior management team has substantial operational and transaction origination and execution expertise. Certain members of this team have also been integral in building and developing Brookfield’s renewable power operations and, although certain members of the senior management team are also managing partners of Brookfield or have some responsibilities in other Brookfield businesses, these members devote substantially all of their time to the management and development of Brookfield Renewable. Biographical information for each of the members of this team is included below.

Harry Goldgut. Mr. Goldgut is the Group Chairman of the Service Provider. Mr. Goldgut is also an Executive Chairman of Brookfield Asset Management’s infrastructure and power groups. He has been involved in the electric power industry since 1985. Mr. Goldgut joined Brookfield in 1997 as Vice President, Power Generation and since then has held various senior positions in BRPI, becoming its Co-Chairman and Chief Executive Officer in 2000, adding Chairman in 2005. He has been actively involved

Page 146

in developing and expanding Brookfield’s power operations and has had primary responsibility for its acquisitions and its senior regulatory relationships. He played an active role in the restructuring of the electricity industry in Ontario as a member of several governmental and regulatory committees and task forces including the Market Design Committee, the Minister of Energy’s Advisory Committee, the Clean Energy Task Force and the Ontario Energy Board Chair’s Advisory Roundtable. Mr. Goldgut received his law degree from York University’s Osgoode Hall Law School in Ontario, and was called to the Ontario Bar in 1982.

Richard Legault. Mr. Legault is the Group Chairman of the Service Provider. Mr. Legault is also an Executive Chairman of Brookfield Asset Management’s renewable power group. Prior to 2015, Mr. Legault was Chief Executive Officer of BEP during which time he led the growth of Brookfield’s renewable power operations on a global basis, helping to make Brookfield Renewable one of the world’s largest pure play renewable power portfolios. Mr. Legault was Chief Financial Officer of Brookfield from 2000 to 2001, prior to which he held several senior positions in operations, finance, and corporate development with Brookfield’s forest products operations. Mr. Legault received a Bachelor of Accounting from the Université du Québec in Hull and is a member of the Chartered Professional Accountants of Canada (CPA, CA).

Sachin Shah. Mr. Shah is the Chief Executive Officer of the Service Provider and a Senior Managing Partner of Brookfield Asset Management. Mr. Shah has oversight of Brookfield Renewable’s growth and capitalization, on a global basis. Mr. Shah received a Bachelor of Commerce degree from the University of Toronto and is a member of the Chartered Professional Accountants of Canada (CPA, CA).

Wyatt Hartley.  Mr. Hartley is the Chief Financial Officer of the Service Provider and a Senior Vice President of Brookfield. He directs all capital markets activities, accounting, financial reporting, treasury, taxation and investor relations, on a global basis. Mr. Hartley holds a Bachelor of Science from Queen’s University and is a member of the Chartered Professional Accountants of Canada (CPA, CA).

Jennifer Mazin. Ms. Mazin is General Counsel of the Service Provider and a Managing Partner of Brookfield Asset Management. Ms. Mazin provides oversight of Brookfield Renewable’s legal matters on a global basis, including transactional matters, corporate governance and public disclosure. Ms. Mazin received her Bachelor of Arts from the University of Western Ontario and her law degree from the University of Toronto. She is called to the bars of the State of New York and the Province of Ontario.

See also information contained under Item 3.D “Risk Factors — Risks Related to Our Relationship with Brookfield” and Item 7.B “Related Party Transactions”.

Management Diversity

At Brookfield Renewable, hiring and promotion decisions are based on solely on merit, so that each officer and employee possesses the necessary skills, knowledge and experience to do his or her job.  Brookfield Renewable and the Service Provider are committed to workplace diversity, including but not limited to diversity of gender, culture, geography, and skills.  Brookfield Renewable appreciates the benefits of leveraging a range of diverse talents and perspectives and we actively support the development and advancement of a diverse group of employees capable of achieving management roles, including executive officer positions.  Neither Brookfield Renewable nor the Service Provider have targets for the representation of women in executive officer positions because such targets do not accurately reflect the full range of factors considered in hiring or promoting executive officers.  Currently, we have eight women in executive positions who constitute 31% of the executive team of the Service Provider and the senior management team of our business, in the aggregate.

Our Master Services Agreement

BEP, BRELP and the Holding Entities entered into our Master Services Agreement pursuant to which the Service Provider has agreed to provide oversight of our business and provide the services of senior management to BEP. In addition, the Service Provider has agreed to provide services relating to acquisitions or dispositions, financings, business planning and strategy and oversight and supervision of various day to day management and administrative activities. The Operating Entities are not a party to our Master Services Agreement. 

Page 147

Under our Master Services Agreement, the Service Recipients have appointed the Service Provider to provide or arrange for the provision by an appropriate service provider of the following services:

·causing or supervising the carrying out of all day to day management, secretarial, accounting, banking, treasury, administrative, liaison, representative, regulatory and reporting functions and obligations;

·providing overall strategic advice to the Holding Entities including advising with respect to the expansion of their business into new markets;

·establishing and maintaining or supervising the establishment and maintenance of books and records;

·identifying, evaluating and recommending to the Holding Entities acquisitions or dispositions from time to time and, where requested to do so, assisting in negotiating the terms of such acquisitions or dispositions;

·recommending and, where requested to do so, assisting in the raising of funds whether by way of debt, equity or otherwise, including the preparation, review or distribution of any prospectus or offering memorandum in respect thereof and assisting with communications support in connection therewith;

·causing or supervising the preparation and implementation of any operating plan, capital expenditure plan or marketing plan;

·recommending to the Holding Entities suitable candidates to serve on the Governing Bodies of the Operating Entities;

·making recommendations with respect to the exercise of any voting rights to which the Holding Entities are entitled in respect of the Operating Entities;

·making recommendations with respect to the payment of dividends by the Holding Entities or any other distributions by the Service Recipients, including distributions by us to our LP Unitholders;

·monitoring and/or oversight of the applicable Service Recipient’s accountants, legal counsel and other accounting, financial or legal advisers and technical, commercial, marketing and other independent experts and managing litigation in which a Service Recipient is sued or commencing litigation after consulting with, and subject to the approval of, the relevant Governing Body;

·attending to all matters necessary for any reorganization, bankruptcy proceedings, dissolution or winding up of a Service Recipient, subject to approval by the relevant Governing Body;

·supervising the timely calculation and payment of taxes payable, and the filing of all tax returns due, by each Service Recipient;

·causing or supervising the preparation of the Service Recipients’ annual consolidated financial statements, quarterly interim financial statements and other public disclosure;

·making recommendations in relation to and effecting the entry into insurance of each Service Recipient’s assets, together with other insurances against other risks including directors and officers insurance, as the relevant service provider and the relevant Governing Body may from time to time agree;

·arranging for individuals to carry out the functions of the principal executive, accounting and financial officers for BEP only for purposes of applicable securities laws;

·providing individuals to act as senior officers of Holding Entities as agreed from time to time, subject to the approval of the relevant Governing Body;

·advising the Service Recipients regarding the maintenance of compliance with applicable laws and other obligations; and

·providing all such other services as may from time to time be agreed with the Service Recipients that are reasonably related to the Service Recipient’s day to day operations.

Notwithstanding the forgoing, all Investment Advisor Services (as defined in the Master Services Agreement) must be provided solely to BRELP. The Service Provider’s activities are subject to the supervision of the board of directors of the Managing General Partner and the Governing Bodies of each of the other Service Recipients, as applicable. The Service Provider has agreed to exercise the power and discharge the duties conferred under our Master Services Agreement honestly and in good faith, and

Page 148

will exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances, subject to, and after taking into account, the terms and conditions of the Relationship Agreement.

Management Fee 

 Under our Master Services Agreement, we pay our Service Provider an annual base management fee (the “Base Management Fee”) of $20 million (adjusted annually for inflation at an inflation factor based on year-over-year United States consumer price index) plus 1.25% of the amount by which the Total Capitalization Value exceeds an initial reference value, determined based on market capitalization immediately following the combination of the assets of the Fund and the Brookfield Power Renewable Assets into BEP. In the event that the measured Total Capitalization Value in a given period is less than the initial reference value, the Service Provider will receive only the Base Management Fee of $20 million annually (subject to an annual escalation by the specified inflation factor described above). The Base Management Fee is calculated and paid on a quarterly basis.

To the extent that under any other arrangement we must pay a base management fee to the Service Provider or one of its affiliates on a portion of our capital that is comparable to the Base Management Fee, the Base Management Fee will be reduced on a dollar for dollar basis by our proportionate share of the comparable base management fee. The Base Management Fee will not be reduced by the amount of any incentive distribution payable by any Service Recipient or Operating Entity to the Service Provider (or any other affiliate) (for which there is a separate credit mechanism under the Amended and Restated Limited Partnership Agreement of BRELP), or any other fees that are payable by any Operating Entity to Brookfield for financial advisory, operations and maintenance, development, operations management and other services. See Item 7.B “Related Party Transactions — Incentive Distributions” and “—Other Services”.

The Base Management Fee payments for the years ended December 31, 2017, 2016 and 2015 are set out below:

	Year ended December 31
(MILLIONS)	2017		2016		2015
Base management fee	$	82	$	62	$	48

Reimbursement of Expenses and Certain Taxes

The relevant Service Recipient will reimburse the Service Provider for all out-of-pocket fees, costs and expenses incurred in connection with the provision of the services including those of any third party. Such out-of-pocket fees, costs and expenses include, among other things, (i) fees, costs and expenses relating to any debt or equity financing; (ii) fees, costs and expenses incurred in connection with the general administration of any Service Recipient; (iii) taxes, licenses and other statutory fees or penalties levied against or in respect of a Service Recipient; (iv) amounts owed under indemnification, contribution or similar arrangements; (v) fees, costs and expenses relating to our financial reporting, regulatory filings and investor relations and the fees, costs and expenses of agents, advisers and other persons who provide services to or on behalf of a Service Recipient; and (vi) any other fees, costs and expenses incurred by the Service Provider that are reasonably necessary for the performance by the Service Provider of its duties and functions under our Master Services Agreement. However, the Service Recipients will not be required to reimburse the Service Provider for the salaries and other remuneration of its management, personnel or support staff who carry out any services or functions for such Service Recipients or overhead for such persons.

In addition, the Service Recipients will be required to pay all fees, expenses and costs incurred in connection with the investigation, acquisition, holding or disposal of any acquisition that is made or that is proposed to be made by us. Where the acquisition or proposed acquisition involves a joint acquisition that is made alongside one or more other persons, the Service Provider will be required to allocate such fees, costs and expenses in proportion to the notional amount of the acquisition made (or that would have been made in the case of an unconsummated acquisition) among all joint investors. Such additional fees, expenses and costs represent out-of-pocket costs associated with investment activities that will be undertaken pursuant to our Master Services Agreement.

Page 149

The Service Recipients will also be required to pay or reimburse the Service Provider for all sales, use, value added, goods and services, harmonized sales, withholding or other taxes or customs duties or other governmental charges levied or imposed by reason of our Master Services Agreement or any agreement it contemplates, other than income taxes, corporation taxes, capital taxes or other similar taxes payable by the Service Provider, which are personal to the Service Provider.

Termination

Our Master Services Agreement has no fixed term. However, the Service Recipients may terminate our Master Services Agreement effective upon written notice of termination to the Service Provider if any of the following occurs:

·the Service Provider defaults in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm to the Service Recipients and the default continues unremedied for a period of 60 days after written notice of the breach is given to the Service Provider;

·the Service Provider engages in any act of fraud, misappropriation of funds or embezzlement against any Service Recipient that results in material harm to the Service Recipients;

·the Service Provider is grossly negligent in the performance of its duties under the agreement and such gross negligence results in material harm to the Service Recipients; or

·certain events relating to the bankruptcy or insolvency of the Service Provider.

The Service Recipients have no right to terminate for any other reason, including if the Service Provider or Brookfield experiences a change of control. The Managing General Partner may only terminate our Master Services Agreement on behalf of BEP with the prior unanimous approval of the Managing General Partner’s independent directors.

Our Master Services Agreement expressly provides that the agreement may not be terminated by the Service Recipients due solely to the poor performance or the underperformance of any of our operations.

            The Service Provider may terminate our Master Services Agreement effective upon written notice of termination to the Service Recipients if any Service Recipient defaults in the performance or observance of any material term, condition or covenant contained in the agreement in a manner that results in material harm to the Service Provider and the default continues unremedied for a period of 60 days after written notice of the breach is given to the Service Recipients. The Service Provider may also terminate our Master Services Agreement upon the occurrence of certain events relating to the bankruptcy or insolvency of any Service Recipient.

If our Master Services Agreement is terminated, the Licensing Agreement, the Relationship Agreement and any of Brookfield’s obligations under the Relationship Agreement would also terminate. See Item 7.B “Related Party Transactions — Relationship Agreement” and Item 3.D “Risk Factors — Risks Related to Our Relationship with Brookfield”.

Indemnification and Limitations on Liability

Under our Master Services Agreement, the Service Provider has not assumed and will not assume any responsibility other than to provide or arrange for the provision of the services called for under such agreement in good faith and will not be responsible for any action that the Service Recipients take in following or declining to follow the advice or recommendations of the Service Provider. The Service Provider has agreed to indemnify each of the Service Recipients and its affiliates, and its directors, officers, agents, members, partners, shareholders, employees and other representatives to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses (including legal fees) resulting from the Service Provider’s bad faith, fraud, willful misconduct, gross negligence and, in the case of a criminal matter, conduct undertaken with the knowledge that the conduct was unlawful. The maximum amount of the aggregate liability of the Service Provider and its affiliates, the directors, officers, employees, contractors, agents, advisers and other representatives of the Service Provider and its affiliates, will be equal to the amounts previously paid in respect of services pursuant to our Master Services Agreement or any other agreement or arrangement contemplated by our Master Services Agreement in the two most recent calendar years by the Service Recipients. The Service

Page 150

Recipients have also agreed to indemnify each of the Service Provider, Brookfield and their directors, officers, agents, subcontractors, delegates, members, partners, shareholders and employees to the fullest extent permitted by law from and against any claims, liabilities, losses, damages, costs or expenses (including legal fees) incurred by an indemnified person or threatened in connection with our respective businesses, investments and activities or in respect of or arising from our Master Services Agreement or the services provided by the Service Provider, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the indemnified person’s bad faith, fraud, willful misconduct, gross negligence or in the case of a criminal matter, action that the indemnified person knew to have been unlawful. In addition, under our Master Services Agreement, the indemnified persons will not be liable to the Service Recipients to the fullest extent permitted by law, except for conduct that involved bad faith, fraud, willful misconduct, gross negligence, or in the case of a criminal matter, conduct that the indemnified person knew to have been unlawful.

Outside Activities

Our Master Services Agreement does not prohibit the Service Provider or its affiliates from pursuing other business activities or providing services to third parties that compete directly or indirectly with us. For a description of related aspects of the relationship between Brookfield and the Service Recipients, see Item 7.B “Related Party Transactions — Relationship Agreement”.

See also information contained in this Form 20-F under Item 6.C “Board Practices,” Item 3.D “Risk Factors — Risks Related to our Relationship with Brookfield” and Item 6.A “Directors and Senior Management”.

6.B       COMPENSATION

Our Management

The Managing General Partner does not have any employees. We have entered into our Master Services Agreement with the Service Provider pursuant to which the Service Provider and certain other affiliates of Brookfield provide or arrange for other service providers to provide management services to BEP, BRELP and the Holding Entities. The fees payable under the Master Services Agreement are set forth under Item 6.A “Directors and Senior Management — Our Master Services Agreement — Management Fee”. In addition, Brookfield is entitled to receive incentive distributions from BRELP described under Item 7.B “Related Party Transactions — Incentive Distributions”.

Pursuant to our Master Services Agreement, members of Brookfield’s senior management and other individuals from Brookfield’s global affiliates are drawn upon to fulfill obligations under our Master Services Agreement. These individuals, including the Brookfield employees identified in the table above under Item 6.A “Directors and Senior Management — Our Management”, arenot compensated by BEP or our Managing General Partner; instead they are and will continue to be compensated by Brookfield.  Further disclosure required under Canadian securities laws regarding the compensation of certain members of our core senior management team for the year ended December 31, 2017 will be separately filed within 140 days of December 31, 2017.

Board of Directors of the Managing General Partner

For the year ended December 31, 2017, the Managing General Partner paid each of its directors $100,000 per year for serving on its board of directors and various board committees. The Managing General Partner pays the Chair of the board of directors an additional $35,000 per year, the Chair of the Audit Committee of the board of directors an additional $20,000, the Chair of the Nominating and Governance Committee of the board of directors an additional $10,000 and the lead independent director of the board of directors an additional $10,000. Subsequent to year end on February 6, 2018, the board of directors approved a $25,000 increase to the annual retainer paid to each director bringing the total annual retainer payable to $125,000.  There was no change to the amounts paid for service as Chair of the committee or as lead independent director.  Only those directors who are not employed by Brookfield or its affiliates are entitled to receive compensation for acting as a director of the Managing General Partner.

We believe that directors of the Managing General Partner can better represent Unitholders if they have economic exposure to Brookfield Renewable themselves. Accordingly, each director of the

Page 151

Managing General Partner must hold sufficient LP Units such that the acquisition cost of such units is equal to at least two times their annual retainer. We consider this minimum economic ownership requirement to be consistent with best practices. See Item 6.A “Directors and Senior Management — Director LP Unit Ownership Requirements”.

The Nominating and Governance Committee is responsible for reviewing and making recommendations to the board of directors of the Managing General Partner concerning the remuneration of directors and committee members. See Item 6.C “Board Practices — Committees of the Board of Directors — Nominating and Governance Committee”.

Indebtedness of Directors and Executive Officers

As at the date of this Form 20-F, and at all times since January 1, 2017, none of the directors, officers, employees and former directors, officers and employees of the Managing General Partner, the Service Provider or any of their respective subsidiaries, nor any of their associates, has or had any indebtedness owing to Brookfield Renewable.

6.C              BOARD PRACTICES

Board Structure, Practices and Committees

The structure, practices and committees of the Managing General Partner’s board of directors, including matters relating to the size, independence and composition of the board of directors, the election and removal of directors, requirements relating to board action and the powers delegated to board committees, are governed by the Managing General Partner’s bye-laws. The Managing General Partner’s board of directors is responsible for exercising the management, control, power and authority of the Managing General Partner except as required by applicable law or the bye-laws of the Managing General Partner. The following is a summary of certain provisions of those bye-laws that affect BEP’s governance.

Size, Independence and Composition of the Board of Directors

The Managing General Partner’s board of directors currently has seven directors. The board may consist of between three and 11 directors or such other number of directors as may be determined from time-to-time by a resolution of the Managing General Partner’s shareholders and subject to its bye-laws. At least three directors and at least a majority of the directors holding office must be independent of the Managing General Partner and Brookfield, as determined by the full board of directors using the standards for independence established under applicable securities laws. In addition, in February 2016 the board of directors of the Managing General Partner, on the recommendation of the Nominating and Governance Committee, appointed a lead independent director. The responsibilities of the lead independent director include presiding over sessions of the board of directors of the Managing General Partner when the Chair is not present as well as the in camera meetings that follow each scheduled board meeting.  Shareholders and other interested parties may communicate with any member of the board of directors, including its Chair, the lead independent director and the independent directors as a group, by contacting BEP’s Corporate Secretary at 73 Front Street, 5th Floor, Hamilton HM 12, Bermuda, +441-294-3304.

If the death, resignation or removal of an independent director results in the board of directors consisting of less than a majority of independent directors, the vacancy must be filled promptly. Pending the filling of such vacancy, the board of directors may temporarily consist of less than a majority of independent directors and those directors who do not meet the standards for independence may continue to hold office. In addition, the Managing General Partner’s bye-laws provide that not more than 50% of the directors (as a group) or the independent directors (as a group) may be residents of any one jurisdiction (other than Bermuda and any other jurisdiction designated by the board of directors from time to time).

Election and Removal of Directors

The Managing General Partner’s board of directors was appointed by its sole shareholder and each of its current directors will serve until the close of the next annual meeting of shareholders of the Managing General Partner or his or her death, resignation or removal from office, whichever occurs first.

Page 152

Vacancies on the board of directors may be filled and additional directors may be added by a resolution of the Managing General Partner’s shareholders or a vote of the directors then in office. A director may be removed from office by a resolution duly passed by the Managing General Partner’s shareholders or, if the director has been absent without leave from three consecutive meetings of the board of directors, by a written resolution requesting resignation signed by all other directors then holding office. A director will be automatically removed from the board of directors if he or she becomes bankrupt, insolvent or suspends payments to his or her creditors or becomes prohibited by law from acting as a director.

Term Limits and Board Renewal

The Nominating and Governance Committee reviews and assesses the qualifications of candidates proposed by the Managing General Partner to join the board of directors with the goal, among other things, of reflecting a balance between the experience that comes with longevity of service on the board of directors and the need for renewal and fresh perspectives.

The board of directors does not have a mandatory age for the retirement of directors and there are no term limits nor any other mechanisms in place that operate to compel board of directors turnover. While we believe that mandatory retirement ages, director term limits and other board of directors turnover mechanisms are overly prescriptive, periodically adding new voices to the board of directors can help Brookfield Renewable adapt to a changing business environment. 

As such, the Nominating and Governance Committee reviews the composition of the board of directors on a regular basis in relation to approved director criteria and skill requirements and recommends changes as appropriate. Given that the board of directors was formed in 2011, there have not yet been any significant changes to its composition, other than the appointment of one new director in 2012 and the appointment of a current independent director as lead independent director in 2016. 

Board Diversity Policy 

We have a board of directors diversity policy (the “Diversity Policy”).  The Diversity Policy is informed by Brookfield Renewable’s deep roots in many global jurisdictions and the belief that the board of directors should reflect a diversity of backgrounds relevant to its strategic priorities. This includes such factors as diversity of business expertise and international experience, in addition to geographic and gender diversity.

All board of director appointments will be based solely on merit, having due regard for the benefits of diversity, so that each nominee possesses the necessary skills, knowledge and experience to serve effectively as a director. Therefore, in the director identification and selection process, gender diversity influences succession planning and is one criterion in adding new members to the board of directors.  Brookfield Renewable appreciates the benefits of leveraging a range of diverse talents and perspectives and is committed to pursuing the spirit and letter of the Diversity Policy. The Nominating and Governance Committee is responsible for overseeing the implementation of the Diversity Policy and for monitoring progress towards achieving its objectives.  The board of directors currently has seven directors, five of whom are independent, and one of whom is female (who is an independent director). Accordingly, approximately 15% of the board of directors is made up of women and women represent 20% of the independent directors. The Diversity Policy does not set any formal targets on diversity for directors at this time, because of the current need for geographic diversity of directors and the emphasis on subject matter expertise.

Action by the Board of Directors

The Managing General Partner’s board of directors may take action in a duly convened meeting at which a quorum is present or by a written resolution signed by all directors then holding office. When action is to be taken at a meeting of the board of directors, the affirmative vote of a majority of the votes cast is required for any action to be taken.

Transactions Requiring Approval by Independent Directors

The Managing General Partner’s independent directors approved the Conflicts Policy which addresses the approval and other requirements for transactions in which there is potential for a conflict of interest to arise. These transactions include:

Page 153

·subject to certain exceptions, acquisitions by us from, and dispositions by us to, Brookfield;

·acquisitions whereby Brookfield Renewable and Brookfield are purchasing different assets as part of a single transaction;

·investing in a private Brookfield sponsored-fund, consortium or partnership;

·the dissolution of BEP or BRELP;

·any material amendment to our Master Services Agreement, the Relationship Agreement, the Amended and Restated Limited Partnership Agreement of BRELP or the Amended and Restated Limited Partnership Agreement of BEP;

·subject to certain exceptions, any material service agreement or other arrangement pursuant to which Brookfield will be paid a fee, or other consideration other than any agreement or arrangement contemplated by our Master Services Agreement;

·determinations regarding the payment of fees under the Master Services Agreement in LP Units of BEP or limited partnership units of BRELP or the deferral of the incentive distribution (see Item 7.B “Related Party Transactions — Incentive Distributions”);

·termination of, or any determinations regarding indemnification under, our Master Services Agreement or determinations regarding indemnification under the Amended and Restated Limited Partnership Agreement of BRELP or the Amended and Restated Limited Partnership Agreement of BEP; and

·subject to certain exceptions, other material transactions involving us and Brookfield.

The Conflicts Policy requires the transactions described above to be approved by a majority of the Managing General Partner’s independent directors. Pursuant to the Conflicts Policy, independent directors may grant approvals for any of the transactions described above in the form of general guidelines, policies or procedures in which case no further special approval will be required in connection with a particular transaction or matter permitted thereby. The Conflicts Policy can be amended at the discretion of the Managing General Partner. See Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Transactions in Which a Director Has an Interest

A director who directly or indirectly has an interest in a contract, transaction or arrangement with the Managing General Partner, BEP or certain of our affiliates is required to disclose the nature of his or her interest to the full board of directors. Such disclosure may take the form of a general notice given to the board of directors to the effect that the director has an interest in a specified company or firm and is to be regarded as interested in any contract, transaction or arrangement made with that company or firm or its affiliates after the date of the notice. A director may participate in any meeting called to discuss or any vote called to approve the transaction in which the director has an interest and any transaction approved by the board of directors will not be void or voidable solely because the director was present at or participated in the meeting in which the approval was given provided that the board of directors or a board committee authorizes the transaction in good faith after the director’s interest has been disclosed or the transaction is fair to the Managing General Partner and BEP at the time it is approved.

Transactions Requiring Unitholder Approval

Unitholders have consent rights with respect to certain fundamental matters and on any other matters that require their approval in accordance with applicable securities laws and stock exchanges rules. See Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”.

Service Contracts

There are no service contracts with directors that provide benefit upon termination of office or services.

Indemnification and Limitations on Liability

Page 154

The Amended and Restated Limited Partnership Agreement of BEP

The laws of Bermuda permit the partnership agreement of a limited partnership, such as BEP, to provide for the indemnification of a partner, the officers and directors of a partner and any other person against any and all claims and demands whatsoever, except to the extent that the indemnification may be held by the courts of Bermuda to be contrary to public policy or to the extent that the laws of Bermuda prohibit indemnification against personal liability that may be imposed under specific provisions of the laws of Bermuda. The laws of Bermuda also permit a partnership to pay or reimburse an indemnified person’s expenses in advance of a final disposition of a proceeding for which indemnification is sought. See Item 10.B “Memorandum and Articles of Association — Description of Our LP Units, Preferred Units and The Amended and Restated Limited Partnership Agreement of BEP — Indemnification; Limitations on Liability” for a description of the indemnification arrangements in place under the Amended and Restated Limited Partnership Agreement of BEP.

The Managing General Partner’s Bye-laws

The laws of Bermuda permit the bye-laws of an exempted company, such as our Managing General Partner, to provide for the indemnification of its officers, directors and shareholders and any other person designated by the company against any and all claims and demands whatsoever, except to the extent that the indemnification may be held by the courts of Bermuda to be contrary to public policy or to the extent that the laws of Bermuda prohibit indemnification against personal liability that may be imposed under specific provisions of the laws of Bermuda. Bermuda company law also permits an exempted company to pay or reimburse an indemnified person’s expenses in advance of a final disposition of a proceeding for which indemnification is sought.

Under the Managing General Partner’s bye-laws, the Managing General Partner is required to indemnify, to the fullest extent permitted by law, its affiliates, directors, officers, resident representative, shareholders and employees, any person who serves on a Governing Body of BRELP or any of its subsidiaries and certain others against any and all losses, claims, damages, liabilities, costs or expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, incurred by an indemnified person in connection with BEP’s investments and activities or in respect of or arising from their holding such positions, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the indemnified person’s bad faith, fraud or willful misconduct, or in the case of a criminal matter, action that the indemnified person knew or ought reasonably to have known was unlawful. In addition, under the Managing General Partner’s bye-laws: (i) the liability of such persons has been limited to the fullest extent permitted by law and except to the extent that their conduct involves bad faith, fraud or willful misconduct, or in the case of a criminal matter, action that the indemnified person knew or ought reasonably to have known was unlawful; and (ii) any matter that is approved by the independent directors will not constitute a breach of any duties stated or implied by law or equity, including fiduciary duties. The Managing General Partner’s bye-laws require it to advance funds to pay the expenses of an indemnified person in connection with a matter in which indemnification may be sought until it is determined that the indemnified person is not entitled to indemnification.

Insurance

BEP has obtained insurance coverage under which the directors of the Managing General Partner are insured, subject to the limits of the policy, against certain losses arising from claims made against such directors by reason of any acts or omissions covered under the policy in their respective capacities as directors of the Managing General Partner, including certain liabilities under securities laws.

Corporate Governance Disclosure

The Managing General Partner’s board of directors encourages sound corporate governance practices designed to promote the well-being and ongoing development of BEP, including advancing the best interests of BEP.

The Managing General Partner’s board of directors is of the view that its corporate governance policies and practices, outlined below, are comprehensive and consistent with the guidelines for corporate governance adopted by Canadian securities administrators. The board of directors is also of the view that

Page 155

these policies and practices are consistent with the requirements of the New York Stock Exchange and the applicable provisions under the Sarbanes-Oxley Act.

Board of Directors of the Managing General Partner

Mandate of the Board of Directors         

The Managing General Partner’s board of directors oversees the management of Brookfield Renewable’s affairs directly and through two existing standing committees. The responsibilities of the board of directors and each committee are set out in written charters, which are reviewed and approved annually. These charters are also posted on BEP’s website at https://bep.brookfield.com/en/corporate-governance/governance-documents.

In fulfilling its mandate, the board of directors is, among other things, responsible for the following:

·assessing the principal risks of Brookfield Renewable’s business and reviewing, approving and monitoring the systems in place to manage these risks;

·reviewing and approving the reports issued to LP Unitholders and Preferred Unitholders, including annual and interim financial statements; and

·promoting the effective operation of the board of directors.

Meetings of the Board of Directors

The Managing General Partner’s board of directors meets at least four times each year, with additional meetings held to consider specific items of business or as deemed necessary. Meeting frequency and agenda items may change depending on the opportunities or risks faced by Brookfield Renewable. The board of directors is responsible for its agenda. Prior to each board meeting, the Chair of the board discusses agenda items for the meeting with the Service Provider.

The board of directors of the Managing General Partner had four regular quarterly meetings as well as two special meetings in 2017.  Ms. Zuccotti was unable to attend one of the special meetings. Otherwise, all of the directors were present in person or by phone at all meetings. Four regular quarterly meetings are scheduled for 2018.

Size and Composition of the Board of Directors

The Managing General Partner’s board of directors is currently set at seven directors. See Item 6.C “Board Practices — Size, Independence and Composition of the Board of Directors”.

Independent Directors

At least three directors and at least a majority of the directors holding office must be independent of the Managing General Partner and Brookfield, as determined by the full board of directors using the standards for independence established under applicable securities laws. See Item 6.C “Board Practices — Size, Independence and Composition of the Board of Directors”.

The following table describes the independence status of the directors of the Managing General Partner.

Page 156

Director	Independence Status	Reason for Related Status
Jeffrey Blidner	Related	Mr. Blidner is a Vice Chairman
		of Brookfield Asset Management
Eleazar de Carvalho Filho	Independent
John Van Egmond	Independent
Lars Josefsson	Related	Mr. Josefsson is a consultant to
		Brookfield Asset Management
David Mann	Independent
Lou Maroun	Independent
Patricia Zuccotti	Independent

The Chair of the Managing General Partner’s board of directors is Jeffrey Blidner, who is not an independent director. However, each of the committees of the board of directors is fully comprised of independent directors and the Board has a lead independent director, David Mann. In addition, special committees of independent directors may be formed from time to time to review particular matters or transactions. The board of directors encourages regular open dialogue between the independent directors and the Chair to discuss matters raised by independent directors.

At all quarterly meetings, the independent directors held meetings without the presence of management and the directors that are not independent. The board of directors has also adopted the Conflicts Policy to govern its practices in circumstances in which conflicts of interest with Brookfield may arise. See Item 6.C “Board Practices — Transactions Requiring Approval by Independent Directors” and “— Transactions in Which a Director Has an Interest” and Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Other Directorships

The following directors of the Managing General Partner are also directors of other reporting issuers (or the equivalent in foreign jurisdictions).

·Blidner: Brookfield Asset Management; Brookfield Property Partners L.P.; Brookfield Infrastructure Partners L.P.; Brookfield Business Partners L.P.

·de Carvalho Filho: TechnipFMC plc; Grupo Pão de Açúcar; Cnova N.V.; Oi S.A.

·Josefsson: Robert Bosch GmbH; Holmen AB

·Mann: Acadian Timber Corp.; NewGrowth Corp.; Allbanc Split Corp. II; Logistec Corporation

·Maroun: Summit II REIT; Brookfield Property Partners L.P.

·Patricia Zuccotti:  Brookfield Business Partners L.P.

Director Orientation and Education

New directors of the Managing General Partner are provided with comprehensive information about BEP and its affiliates. Arrangements are made for specific briefing sessions from appropriate senior personnel to help new directors better understand Brookfield Renewable’s strategies and operations. They also participate in the continuing education measures discussed below.

The Managing General Partner’s board of directors receives annual operating plans for each of Brookfield Renewable’s strategic business units and more detailed presentations on particular strategies. Existing directors are invited to join the orientation sessions for new directors as a refresher. The directors are also invited to participate in guided tours of Brookfield Renewable’s various operational facilities. They have the opportunity to meet and participate in work sessions with management to obtain insight into the operations of Brookfield Renewable and its affiliates. Directors are regularly briefed to help better understand industry related issues such as accounting rule changes, transaction activity, capital markets initiatives, significant regulatory developments, as well as trends in corporate governance.

Director Expectations

Page 157

The Managing General Partner’s board of directors has adopted a Charter of Expectations for Directors, which sets out the expectations in regard to personal and professional competencies, LP Unit ownership, meeting attendance, conflicts of interest, changes of circumstance and resignation events. The Charter of Expectations for Directors can be found on our website at https://bep.brookfield.com/en/corporate-governance/governance-documents.  Directors are expected to identify in advance any potential conflict of interest regarding a matter coming before the board of directors or its committees, bring these to the attention of the board of directors or committee chair and refrain from voting on such matters. Directors are also expected to submit their resignations to the Chair of the board of directors if they become unable to attend at least 75% of the board of directors’ regularly scheduled meetings or if they become involved in a legal dispute, regulatory or similar proceedings, take on new responsibilities or experience other changes in personal or professional circumstances that could adversely impact Brookfield Renewable or their ability to serve as director. Further information on director LP Unit ownership requirements is set out in Item 6.B “Compensation — Board of Directors of the Managing General Partner”.

Committees of the Boardof Directors

The Managing General Partner’s board of directors believes that its committees assist in the effective functioning of the board of directors and help ensure that the views of independent directors are effectively represented.

The board of directors has two committees:

·the Audit Committee; and

·the Nominating and Governance Committee.

The responsibilities of these committees are set out in written charters, which are reviewed and approved annually by the board of directors. The charters of these committees can be found on our website at https://bep.brookfield.com/en/corporate-governance/governance-documents. All members of these committees must be independent directors, as described above. Special committees may be formed from time to time as required to review particular matters or transactions. While the board of directors retains overall responsibility for corporate governance matters, the Audit Committee and the Nominating and Governance Committee each have specific responsibilities for certain aspects of corporate governance, in addition to their other responsibilities as described below.

Audit Committee

The Managing General Partner’s board of directors has established an audit committee (the “Audit Committee”) that operates pursuant to a written charter. The Audit Committee consists solely of independent directors, each member is financially literate and there will be at least one member at all times designated as an “audit committee financial expert” as defined by the SEC. Collectively, the Audit Committee has the education and experience to fulfill the responsibilities outlined in the Audit Committee Charter. The education and past experience of each Audit Committee member that is relevant to the performance of his or her responsibilities as an Audit Committee member can be found in the biographical information about the applicable member under Item 6.A “Directors and Senior Management”. Audit Committee members may not serve on more than two other public company audit committees, except with the prior approval of the Managing General Partner’s board of directors. Such prior approval was granted with respect to David Mann’s service on the audit committees of more than two other public companies. Not more than 50% of the Audit Committee members may be directors who are residents of any one jurisdiction (other than Bermuda and any other jurisdiction designated by the board of directors from time to time).

The Audit Committee is responsible for assisting and advising the Managing General Partner’s board of directors with matters relating to:

·our accounting and financial reporting processes;

·the integrity and audits of our financial statements;

·our compliance with legal and regulatory requirements; and

·the qualifications, performance and independence of our independent accountants.

Page 158

The Audit Committee is also responsible for engaging our independent auditors, reviewing the plans and results of each audit engagement with our independent auditors, approving professional services provided by our independent auditors, considering the range of audit and non-audit fees charged by our independent auditors and reviewing the adequacy of our internal accounting controls.

As of the date of this Form 20-F, the Audit Committee was comprised of the following three directors: Patricia Zuccotti (Chair), David Mann and Eleazar de Carvalho Filho, all of whom are independent directors.

The Audit Committee had four regular quarterly meetings in 2017 as well as one special meeting. All of the committee members were present in person or by telephone. Four regular quarterly meetings are scheduled for 2018.

The board of directors of the Managing General Partner, upon the recommendation of the Audit Committee, have adopted a written policy on auditor independence (the “Pre-Approval Policy”). Under the Pre-Approval Policy, except in very limited circumstances, all audit and permitted non-audit services are required to be pre-approved by the Audit Committee. The Pre-Approval Policy prohibits the auditors from providing the following types of non-audit services:

·booking or other services related to Brookfield Renewable’s accounting records or financial statements;

·appraisal or valuation services or fairness opinions;

·actuarial services;

·management functions or human resources;

·legal services and expert services unrelated to the audit;

·internal audit outsourcing; and

·financial information systems design and implementation.

The Pre-Approval Policy permits the auditors to provide other types of non-audit services, including tax services, but only if approved in advance by the Audit Committee, subject to limited exceptions.

The Pre-Approval Policy also addresses issues relating to the disclosure of fees paid to the auditors. See Item 16.C – “Principal Accountant Fees and Services” for a summary of our external auditor service fees.

Nominating and Governance Committee

The Managing General Partner’s board of directors has established a nominating and governance committee (the “Nominating and Governance Committee”) that operates pursuant to a written charter. The Nominating and Governance Committee consists entirely of independent directors and not more than 50% of the Nominating and Governance Committee members may be directors who are residents of any one jurisdiction (other than Bermuda and any other jurisdiction designated by the board of directors from time to time).

The Nominating and Governance Committee is responsible for approving the appointment by the sitting directors of a person to the office of director and for recommending a slate of nominees for election as directors by the Managing General Partner’s shareholders. The Nominating and Governance Committee is also responsible for assisting and advising the Managing General Partner’s board of directors with respect to matters relating to the general operation of the board of directors, BEP’s governance, the governance of the Managing General Partner and the performance of its board of directors, individual directors and the Service Provider.The Nominating and Governance Committee must also assess the size and composition of the Managing General Partner’s board of directors and its committees, review the effectiveness of the board of directors’ relations with the Service Provider and review BEP’s corporate governance practices.  The Nominating and Governance Committee annually reviews the performance of the board of directors and its committees and the individual contribution of directors through a self-survey.

Page 159

The Nominating and Governance Committee had four regular quarterly meetings in 2017 and no special meetings. All of the committee members were present in person or by telephone. Four regular quarterly meetings are scheduled for 2018.

As Brookfield Asset Management is entitled to elect all of the directors of the Managing General Partner, the directors of the Managing General Partner consult with Brookfield to identify and assess the credentials of appropriate individuals with the skills, knowledge, experience and talents needed to act as an independent member of the board of directors of the Managing General Partner, including the need for the board of directors as a whole to have a diversity of perspectives. Brookfield maintains an “evergreen” list of potential independent board members to ensure that outstanding candidates with the needed skills can be quickly identified to fill planned or unplanned vacancies. Candidates from that list and any other candidates familiar to Brookfield or Brookfield Renewable are assessed to ensure the Managing General Partner’s board of directors has the appropriate mix of talent, quality, skills and other requirements necessary to promote sound governance and board effectiveness. Individuals who meet those requirements are recommended by Brookfield to the Nominating and Governance Committee for its review as potential candidates for nomination to the board of directors. The Nominating and Governance Committee also recommends to the Board the appointment of an independent director as the lead independent director where the Chair of the Board is not independent.

The Nominating and Governance Committee is also responsible for reviewing and making recommendations to the board of directors of the Managing General Partner concerning the remuneration of directors and committee members. On recommendation of the Nominating and Governance Committee, the Managing General Partner’s board of directors will set compensation of the directors by seeking to ensure that the compensation reflects the responsibilities and risks involved in being a director and aligns the interests of the directors with the best interests of Brookfield Renewable and our Unitholders. Compensation of the directors will be periodically assessed by the Nominating and Governance Committee and the board of directors to ensure that it is competitive in the marketplace and fair in relation to the scope of the duties and responsibilities of the directors.

The Managing General Partner does not have any executive officers. As the Service Provider manages BEP pursuant to our Master Services Agreement, the compensation of our core senior management team is determined by Brookfield. Our Nominating and Governance Committee is responsible for supervising any changes in the fees to be paid pursuant to our Master Services Agreement. See Item 6.A “Directors and Senior Management — Our Management” and Item 6.B “Compensation — Our Management”. As of the date of this Form 20-F, the Nominating and Governance Committee was comprised of the following three directors: David Mann (Chair), Lou Maroun and John Van Egmond, all of whom are independent directors.

Boardof Directors, Committees and Director Evaluation

The Managing General Partner’s board of directors believes that a regular and formal process of evaluation improves the performance of the board of directors as a whole, its committees and individual directors. Each year, a survey is sent to directors regarding the effectiveness of the board of directors and its committees, inviting comments and suggestions on areas for improvement. The results of this survey are reviewed by the Nominating and Governance Committee, which makes recommendations to the board of directors as required. Each director also receives a list of questions for completing a self-assessment. The Chair of the board of directors also holds private interviews with each director annually to discuss the operations of the board of directors and its committees and to provide any feedback on the individual director’s contributions.

Boardof Directors and Management Responsibilities

The Managing General Partner’s board of directors has not developed written position descriptions for the Chair of the board of directors, the role of lead independent director or the chair of any of the committees of the board of directors. However, each chair takes responsibility for ensuring the board of directors or committee, as applicable, addresses the matters within its written charter. The lead independent director similarly takes responsibility for promoting and safeguarding the independence of the independent directors.

Page 160

The Managing General Partner’s board of directors has not developed a written position description for any members of our core senior management team. The services of our core senior management team are provided by the Service Provider pursuant to our Master Services Agreement.

Code of Business Conduct and Ethics

Brookfield Renewable has adopted a Code of Business Conduct and Ethics (the “Code”), a copy of which can be found on BEP’s web site athttps://bep.brookfield.com/en/corporate-governance/governance-documents or on BEP’s SEDAR profile at www.sedar.com or EDGAR profile at www.sec.gov. The Code provides guidelines to ensure that all employees, including directors of the Managing General Partner, respect BEP’s commitment to conducting business relationships with respect, openness and integrity. Management provides regular instructions and updates to the Code to our employees, as appropriate, and has provided training and e-learning tools to support the understanding of the Code throughout the organization. Employees may report activities which they feel are not consistent with the spirit and intent of the Code through a hotline or through a designated ethics reporting website (in each case on an anonymous basis), or alternatively, to designated members of management. Monitoring of calls and of the ethics reporting website is managed by an independent third party called Navex. The Audit Committee is to be notified of any significant reports of activities that are not consistent with the Code by Brookfield’s internal auditor. If the Audit Committee considers it appropriate, it will notify the Nominating and Governance Committee and/or the board of directors of such reports. The board of directors has not granted any waivers of the Code to date.

The Managing General Partner’s board of directors promotes the highest ethical business conduct. The board of directors has taken measures to ensure directors exercise independent judgment in considering transactions and agreements in respect of which a director or our core senior management team has a material interest. Any director with a material interest in a transaction declares his/her interest and refrains from voting on such matter. Significant related party transactions, if any, are reviewed and approved by an independent committee made up of independent directors who may be advised by independent counsel and independent advisers. See Item 6.C “Board Practices — Transactions Requiring Approval by Independent Directors” and “— Transactions in Which a Director Has an Interest” and Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

6.D              EMPLOYEES

We do not employ the individuals who provide management services to us under our Master Services Agreement, including the individuals who serve as the Managing General Partner’s Chief Executive Officer and Chief Financial Officer. The personnel that carry out these activities are employees of Brookfield, and their services are provided to Brookfield Renewable for our benefit under our Master Services Agreement. For a discussion of the individuals from Brookfield’s management team that are involved in our renewable power business, see Item 6.A “Directors and Senior Management — Our Management”.

Brookfield Renewable has approximately 2,270 employees involved in the day-to-day operations of our facilities and the development of our business, of which approximately 380 are located in Canada, 545 are located in the United States, 435 are located in Brazil, 680 are located in Colombia and 125 are located in the Republic of Ireland, the United Kingdom and Portugal, and 105 are located in other markets. Approximately 1,340, or approximately 60% of these employees, are covered by collective agreements expiring between 2017 and 2020. Eleven of these collective agreements are due to be renewed in 2018. We maintain very good relations with represented and salaried employees across all facilities. Relationships with the various unions in Canada, the United States, Brazil and Colombia have also been positive, without the occurrence of any work disruptions that would have had a negative impact on the business. Our corporate group, including the Manager, also has approximately 125 employees with non-operational roles who are largely based in Canada.

6.E              SHARE OWNERSHIP

Except as described below under Item 7.A “Major Shareholders”, as of the date of this Form 20-F, the directors and officers of the Managing General Partner and the employees of the Service Provider

Page 161

who perform executive functions for Brookfield Renewable, and their respective associates, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, less than one percent of the outstanding LP Units.

ITEM 7.       MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS      

7.A              MAJOR SHAREHOLDERS

As of the date of this Form 20-F, there are 180,388,361 LP Units outstanding. To our knowledge, as at the date of this Form 20-F, no person or company, other than Brookfield, beneficially owns or controls or directs, directly or indirectly, more than 5% of our LP Units, on a fully-exchanged basis. Brookfield beneficially owns 56,068,944 LP Units and 129,658,623 Redeemable/Exchangeable partnership units, or an approximate 60% interest in BEP (on a fully-exchanged basis) including its indirect general partnership interest in the Managing General Partner and the BRELP GP LP. All LP Units, including those held by Brookfield, are non-voting. See also the information contained in this Form 20-F under Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”.

As of February 26, 2018, 11,390 of our outstanding LP Units were held by 5 holders of record in the United States, not including LP Units held of record by DTC. As of February 26, 2018, DTC was the holder of record of 17,913,443 LP Units.

The following table sets forth information, as of date of this Form 20-F, regarding the beneficial ownership of LP Units by each person that is a beneficial owner of more than 5% of our LP Units, on a fully-exchanged basis.

Name	LP Units (1)	Percentage of LP Units (2)
Brookfield Asset Management Inc. (3)	185,727,567	60%
Partners Limited (4)	185,727,567	60%

⁽¹⁾Includes 129,658,623 Redeemable/Exchangeable partnership units indirectly held by Brookfield Asset Management which are redeemable for cash or exchangeable for LP Units in accordance with the Redemption-Exchange Mechanism. All Redeemable/Exchangeable partnership units and all limited partnership units of BRELP held by BEP are non-voting. For additional information, see Item 10.B “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Units”.

⁽²⁾Assuming the exchange of all Redeemable/Exchangeable partnership units indirectly held by Brookfield Asset Management and including Brookfield Asset Management’s indirect general partnership interests.

⁽³⁾Consists of 56,068,944 LP Units and 129,658,623 Redeemable/Exchangeable partnership units.  In addition, Brookfield Asset Management has an indirect general partnership interest in BEP and BRELP through its indirect wholly-owned subsidiary Brookfield Renewable Power Inc.

⁽⁴⁾Partners Limited owns all of Brookfield Asset Management’s Class B Limited Voting Shares entitling it to appoint one-half of the board of directors of Brookfield Asset Management.  Partners Limited may be deemed the beneficial owner of 185,727,567 of our LP Units, constituting approximately 60% of the issued and outstanding units, assuming that all of the Redemption-Exchange Units are exchanged for our units pursuant to the Redemption-Exchange Mechanism described in Item 10.B “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Redemption-Exchange Mechanism”

See also the information contained in this Form 20-F under Item 3.D “Risk Factors—Risks Related to our Relationship with Brookfield”, Item 6.A “Directors and Senior Management”, Item 6.C “Board Practices” and Item 7.B “Related Party Transactions”.

7.B              RELATED PARTY TRANSACTIONS

We are an affiliate of Brookfield. We have entered into a number of agreements and arrangements with Brookfield in order to enable us to be established as a separate entity and to pursue our vision of being a leading owner and operator of high-quality renewable power assets. While we believe that this ongoing relationship with Brookfield provides us with a strong competitive advantage as well as access to opportunities that would otherwise not be available to us, we operate as an independent, stand-alone entity. We describe below these relationships as well as potential conflicts of interest (and the methods for resolving them) and other material considerations arising from our relationship with Brookfield.

See also the information contained in this Form 20-F under Item 3.D “Risk Factors — Risks Related to Our Relationship with Brookfield”, Item 5.A “Operating Results — Related Party Transactions”,

Page 162

Item 6.A “Directors and Senior Management”, Item 6.C “Board Practices” and Item 7.A “Major Shareholders” and Note 27 to our audited consolidated financial statements for the year ended December 31, 2017, 2016 and  2015, respectively.

Relationship Agreement

Brookfield Asset Management and certain of its subsidiaries entered into an agreement with BEP, referred to as the Relationship Agreement that governs aspects of the relationship among them. Pursuant to the Relationship Agreement, Brookfield Asset Management has agreed that BEP will serve as its primary vehicle through which it will acquire renewable power assets on a global basis. See Item 4.B “Business Overview — The Service Provider” for further details on Brookfield Asset Management.

Each of BEP, BRELP and the Holding Entities acknowledge and agree that Brookfield Asset Management is not required under the Relationship Agreement to allocate any minimum level of dedicated resources for the pursuit of acquisitions of power generation operations or developments and that Brookfield has established or advised, and may continue to establish or advise, other entities that rely on the diligence, skill and business contacts of Brookfield’s professionals and the information and acquisition opportunities they generate during the normal course of their activities (including in the power generation sector). Brookfield Asset Management also agrees that it will not sponsor transactions that are suitable for us in the renewable power sector unless we are given an opportunity to participate. Further, Brookfield may, but is not required to, offer Brookfield Renewable the opportunity to acquire: (i) an integrated utility even if a significant component of such utility’s operations consist of a non-renewable power generation operation or development, such as a power generation operation that uses coal or natural gas, (ii) a portfolio of power operations, even if a significant component of such portfolio’s operations consist of non-renewable power generation, or (iii) renewable power generation operations or developments that comprise part of a broader enterprise, unless the primary purpose of such acquisition, as determined by Brookfield, acting in good faith, is to acquire the underlying operation or development.

Brookfield Renewable also acknowledges and agrees that members of Brookfield carry on a diverse range of businesses worldwide, including the development, ownership and/or management of power, transmission and other infrastructure assets, and investing and advising on investing in any of the foregoing or loans, debt instruments and other securities with underlying infrastructure collateral or exposure including renewable power generation operations or developments, both as principal and through other public companies that are affiliates of Brookfield or through private investment vehicles and accounts established or managed by affiliates of Brookfield and that except as explicitly provided in the Relationship Agreement, the Relationship Agreement will not in any way limit or restrict members of Brookfield from carrying on their respective business.

If we intend to pursue an acquisition opportunity presented by Brookfield, one or more members of Brookfield may participate in the acquisition opportunity if we do not have the financial capacity (as determined by Brookfield) to acquire all of the opportunity or if Brookfield allocates participation in the opportunity between BEP and one or more members of Brookfield, after taking into consideration the purpose of the investment opportunity, the risk/return profile, the source of the investment opportunity and other factors that Brookfield considers relevant. In the event that we decline an acquisition opportunity presented by Brookfield, Brookfield may pursue such acquisition opportunity for its own account, without restriction. Due to the foregoing, we expect to compete from time-to-time with Brookfield or other third parties for access to the benefits that we expect to realize from Brookfield Asset Management’s involvement in our business. See Item 3.D “Risk Factors — Risks Related to Our Relationship with Brookfield — Brookfield is not necessarily required to act in the best interests of the Service Recipients, BEP or our Unitholders”.

An integral part of our strategy is to participate with institutional investors in Brookfield sponsored or co-sponsored consortiums or funds for acquisitions that fit our strategy. Brookfield has a strong track record of leading such consortiums and funds and actively manages underlying assets to improve performance. Currently, Brookfield manages the Brookfield Americas Infrastructure Fund, a $2.7 billion infrastructure fund focused on the Americas, Brookfield Infrastructure Fund II, a $7 billion global infrastructure fund, Brookfield Infrastructure Fund III, a $14 billion global infrastructure fund and Brookfield Infrastructure Debt Fund, an infrastructure fund focused on credit investments. Brookfield is the fund manager and typically invests approximately 25% to 50% of the capital required for a transaction

Page 163

alongside its institutional investors. It is currently intended that future renewable power acquisitions identified by Brookfield may be funded with commitments pursuant to Brookfield sponsored funds and we would fund Brookfield’s participation where renewable power investments are made by such funds. See Item 3.D “Risk Factors – We do not have control over all our operations”.

In the event of the termination of our Master Services Agreement, the Relationship Agreement would also terminate, including Brookfield’s commitments to provide us with acquisition opportunities, as described above.

Master Services Agreement

BEP, BRELP and the Holding Entities entered into our Master Services Agreement pursuant to which the Service Provider has agreed to provide oversight of the business and provide the services of senior officers to Brookfield Renewable. In addition, the Service Provider has agreed to provide services relating to acquisitions or dispositions, financings, business planning and strategy and oversight and supervision of various day to day management and administration activities. In exchange for providing these services, the Service Provider is entitled to a Base Management Fee, which for the year ended 2017 was approximately $82 million. For a detailed description of our Master Services Agreement, see Item 6.A “Directors and Senior Management – Our Master Services Agreement”. For components of the management fee, see Item 6.A— “Directors and Senior Management — Our Master Services Agreement — Management Fee”.

Incentive Distributions

BRELP GP LP is entitled to receive incentive distributions from BRELP as a result of its ownership of the general partnership interest in BRELP. The incentive distributions are to be calculated in increments based on the amount by which quarterly distributions on the limited partnership units of BRELP exceed specified target levels as set forth in the Amended and Restated Limited Partnership Agreement of BRELP. See Item 10.B “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Distributions”.

BRELP GP LP may, at its sole discretion, elect to reinvest incentive distributions in exchange for Redeemable/Exchangeable partnership units.

To the extent that any of the Holding Entities or any operating entity pays to Brookfield any comparable performance or incentive distribution, the amount of any future incentive distributions will be reduced in an equitable manner to avoid duplication of distributions.

General Partner Distributions

Pursuant to the Amended and Restated Limited Partnership Agreement of BEP, the Managing General Partner is entitled to receive a general partner distribution equal to 0.01% of the total distributions of BEP. See Item 10.B “Memorandum and Articles of Association — Description of Our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP —Distributions”.

Pursuant to the Amended and Restated Limited Partnership Agreement of BRELP, BRELP GP LP is entitled to receive a general partner distribution from BRELP equal to a share of the total distributions of BRELP in proportion to BRELP GP LP’s percentage interest in BRELP which is equal to 1% of the total distributions of BRELP. In addition, it is entitled to receive the incentive distributions described above under “— Incentive Distributions”. See Item 10.B “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Distributions”.

Energy Revenue Agreement

On November 23, 2011, BEM LP, a subsidiary of Brookfield, and BPUSHA, a subsidiary of BRELP that indirectly owns most of our U.S. facilities, entered into an energy revenue agreement (“Energy Revenue Agreement”) pursuant to which BEM LP agreed to support the price that BPUSHA receives for the energy generated from certain of those facilities. BEM LP has agreed to pay BPUSHA each month an amount equal to the difference between the Fixed Amount and the total revenues received by BPUSHA from certain of those facilities. The “Fixed Amount” is calculated as the energy generated by those facilities multiplied by a price of $75/MWh (subject to an annual adjustment, equal to

Page 164

40% of the increase in the U.S. Consumer Price Index during the previous year, but capped at a 3% increase in the fixed price per year). Should the total revenues received by these facilities from sales of electricity and all ancillary services, capacity and green credits for any month be more than the calculated Fixed Amount at the end of any month, BEM LP will receive from BPUSHA an amount equal to such excess.

In the Energy Revenue Agreement, BEM LP has agreed that at all times that it does not have a minimum net worth of $500 million, it will provide a guarantee or other acceptable security of a person with a minimum net worth of $500 million. This guarantee is currently being provided by Brookfield.

The Energy Revenue Agreement has an initial term of 20 years, with automatic renewals for successive 20-year periods unless 180 days before the end of the applicable term (i) both parties agree in writing not to renew the agreement or (ii) BEM LP provides written notice that the agreement shall terminate with respect to one or more facilities five years after the end of the applicable term. The Energy Revenue Agreement is subject to customary termination provisions in the event of a failure to pay or an insolvency event of BPUSHA or BEM LP.

Other Power Agreements

In addition to the Energy Revenue Agreement, BEP is a party to a number of commercial agreements with Brookfield, including PPAs for the sale of power generated from certain of Brookfield Renewable’s North American facilities to subsidiaries of Brookfield and revenue support agreements under which Brookfield supports Brookfield Renewable’s revenue from the sale of power generated by certain of Brookfield Renewable’s North American facilities. Including the Energy Revenue Agreement, Brookfield purchases or provides revenue support for approximately 25% of Brookfield Renewable’s portfolio as of December 31, 2017.

Details of the related party power purchase and revenue support agreements are as follows:

In December 2009, Brookfield entered into a 20-year power sales agreement with the Province of Ontario pursuant to a hydroelectric contracting initiative issued by the provincial government earlier that year. The power sales agreement, which matures in 2029, applies to all power produced by hydro assets in Ontario owned by Great Lakes Power Limited (“GLPL”) and Mississagi Power Trust (“MPT”). As of November 28, 2011, PPAs between Brookfield subsidiaries and GLPL and MPT were amended to increase the price paid by Brookfield to GLPL and MPT and to extend the term of such contracts. These amendments were designed to pass through substantially all of the economics of the new power sales agreement. When the assets of the Fund and the Brookfield Renewable Power Assets were combined into BEP, Brookfield received aggregate consideration in respect of such amendments valued at C$292 million, which was recorded in equity by BEP as part of the adjustments arising from this combination, since the transactions were between entities under the common control of Brookfield. The GLPL and MPT contract amendments were taken into account in the determination of the valuation of BEP and, ultimately, in the number of LP Units that were issued to the public and the number of Redeemable/Exchangeable partnership units of BRELP that were issued to Brookfield. The material terms of the GLPL and MPT contract amendments are described below.

Under a PPA with GLPL, a subsidiary of Brookfield Asset Management supports the price that GLPL receives for energy generated by all of GLPL’s facilities in Ontario at a price of C$82 per MWh (increased from C$68 per MWh by an amendment to the PPA effective as of November 28, 2011) subject to an annual adjustment equal to 40% of the increase in CPI) in the previous year. The GLPL PPA has an initial term ending on December 1, 2029 and automatically renews for successive 20-year periods, subject to certain termination provisions. After December 1, 2029, the price under the GLPL PPA will revert back to the original C$68/MWh price (as escalated in accordance with the original inflation linked price escalation provisions in such agreement).

Under a PPA with MPT, a subsidiary of Brookfield Asset Management purchases the energy generated by MPT’s facilities in Ontario at a price of C$103 per MWh (increased from C$68 per MWh by an amendment to the PPA effective as of November 28, 2011) subject to an annual adjustment equal to 20% of the increase in the CPI in the previous year. The MPT PPA terminates on December 1, 2029, subject to MPT’s option to terminate the agreement, on 120 days written notice, at certain times between 2017 and 2024.

Page 165

Pursuant to PPAs with Great Lakes Hydro America, LLC (“GLHA”), a subsidiary of Brookfield Asset Management purchases the energy generated by several of GLHA’s power facilities in Maine and New Hampshire at an initial price of $35.75 per MWh, subject to an annual adjustment equal to 20% of the increase in the United States consumer price index during the previous year. The GLHA PPAs have 20-year terms ending in 2022 and 2023.

Pursuant to a PPA with Lievre Power, a subsidiary of Brookfield Asset Management purchases the energy generated by Lievre Power’s facilities in Québec (excluding the Rapides des Cedres facility) at a price of C$68 per MWh, subject to an annual adjustment equal to the lesser of 40% of the increase in the CPI during the previous calendar year or 3%. The Lievre Power PPA has a 20-year term ending in 2019.

Pursuant to a PPA with Hydro Pontiac Inc. (“HPI”), a subsidiary of Brookfield Asset Management has agreed to purchase the energy generated by HPI’s two facilities in Québec at a price of C$68 per MWh, subject to an annual adjustment beginning in 2010 equal to 40% of the increase in the CPI during the previous calendar year. This power guarantee agreement is scheduled to commence in 2019 for one facility and in 2020 for the other, upon the expiration of existing PPAs. The HPI PPAs with Brookfield will have an initial term ending in 2029, and automatically renew for successive 20-year periods.

Pursuant to a 10-year wind levelization agreement expiring in 2019, a subsidiary of Brookfield Asset Management mitigates any potential wind variation from the expected annual generation of 506 GWh for our Prince Wind assets in Ontario. Any excess generation compared to the expected generation results in a payment from BEP to the subsidiary of Brookfield Asset Management, while a shortfall would result in a payment from a subsidiary of Brookfield Asset Management to BEP.

Pursuant to a PPA guarantee, expiring in 2021, Brookfield guarantees to Powell River the payment obligations of an industrial power purchaser for an annual fee of $0.5 million.

Pursuant to a PPA guarantee, expiring in 2023, Brookfield guarantees to Pontook Operating Limited Partnership the payment by BEM LP of a power purchase price of $36/MWh.

Energy Marketing Agreement

BEM LP, NA Holdco and Brookfield BRP Canada Corp. (a subsidiary of NA Holdco that holds our North American operating assets) are party to an energy marketing agreement pursuant to which BEM LP has agreed to provide energy marketing services to NA Holdco and Brookfield BRP Canada Corp. (the “Energy Marketing Agreement”). Under the Energy Marketing Agreement, BEM LP provides the following energy marketing services for certain of our North American power generating facilities:

·preparing and assisting with compliance with an annual marketing plan which seeks to maximize annual generation, taking into account (among other things) (i) the hydrologic or wind resource available to each power generating facility in a prudent manner having regard to obligations under applicable regulatory authorizations, and (ii) the obligation of the Operating Entities to operate and maintain the power generating facilities in accordance with prudent industry practice and to protect against harm to human life or property of any person;

·preparing and assisting with compliance with a risk management policy; and

·assisting with compliance with the terms of any energy marketing agreement between BEM LP and any subsidiary of NA Holdco holding the power generating facilities.

Pursuant to the Energy Marketing Agreement, Brookfield BRP Canada Corp. pays an annual marketing fee, referred to as the “Base Marketing Fee”, to BEM LP equal to $18 million (subject to increase by a specified inflation factor, with the first such increase having been made on January 1, 2013), paid in equal monthly installments. To the extent that any amounts are paid to BEM LP (or one of its affiliates) under certain other existing energy marketing agreements or PPAs between certain of the Operating Entities and BEM LP (or one of its affiliates) that BEM LP determines are comparable to the Base Marketing Fee, the Base Marketing Fee will be reduced on a dollar for dollar basis by the comparable amounts.

The Energy Marketing Agreement has a term of 20 years. Provided that no event of default relating to BEM LP has occurred and is continuing, the Energy Marketing Agreement will be automatically

Page 166

renewed for successive periods of 20 years unless BEM LP provides NA Holdco with written notice to the contrary at least 180 days prior to the expiry of the applicable term.

The Energy Marketing Agreement is subject to customary termination provisions in the event of a failure to pay or an insolvency event of the applicable Operating Entity or BEM LP.

The maximum amount of the aggregate liability of BEM LP pursuant to the Energy Marketing Agreement is equal to the fees previously paid by NA Holdco pursuant to the Energy Marketing Agreement in the two most recent calendar years.

The Energy Marketing Agreement does not prohibit BEM LP or its affiliates from pursuing other business activities that compete directly or indirectly with us. For a description of related aspects of the relationship between Brookfield and NA Holdco, see Item 7.B “Related Party Transactions— Relationship Agreement”.

Power Agency Agreements

BEM LP and the owners of many of our North American facilities have entered into power agency agreements (the “Power Agency Agreements”). Under each Power Agency Agreement, BEM LP is appointed as the exclusive agent of the owner in respect of the sales of electricity, the procurement of transmission and other additional services. BEM LP also schedules, dispatches and arranges for transmission of the power produced and the power supplied to third parties in accordance with prudent industry practice. Pursuant to each Power Agency Agreement, BEM LP is entitled to be reimbursed for any third party costs incurred, and in certain cases, a fee for its services. To the extent that any fee is payable to BEM LP (or one of its affiliates) under Power Agency Agreements that existed prior to November 28, 2011, the Base Marketing Fee under the Energy Marketing Agreement will be reduced on a dollar for dollar basis.

The Power Agency Agreements that relate to the Energy Revenue Agreement have initial terms of 20 years, with automatic renewals for successive 20-year periods unless 180 days before the end of the applicable term (i) both parties agree in writing not to renew the agreement or (ii) BEM LP has provided the owner with the written notice to terminate the Energy Revenue Agreement as it relates to the particular facility five years after the end of the applicable term. Other Power Agency Agreements have varying terms, renewal and termination rights but are generally long-term arrangements. The Power Agency Agreements are subject to customary termination provisions in the event of a failure to pay or an insolvency event of the applicable Operating Entity or BEM LP.

Development Projects

We indirectly acquired a number of early stage development projects in Brazil, Canada and the United States from Brookfield on November 28, 2011. To further align interests and incentivize continued development success with respect to these specific projects, Brookfield received no upfront proceeds for the transfer of these projects, but is entitled to receive on commercial operation or sale of the projects, in each case if developed or sold in the 25 years following the acquisition, up to 100% of the development costs that it contributed to each project and 50% of the fair market value of the projects in excess of a priority return on each party’s invested capital. These amounts will only be payable on projects upon substantial completion or sale of the project. Fair market value means our pro rata percentage of the fair market value of a development project, as determined by the Service Provider and the independent directors of NA Holdco, on the date on which substantial completion of the development project has been achieved, or, if earlier, the date that the project is sold. With respect to the projects located in Canada and the United States, we entered into the Development Projects Agreement which provides for the reimbursement of expenses to Brookfield for such projects and each project entity and Brookfield have entered into a separate royalty agreement providing for royalties on each project. With respect to our projects located in Brazil, Brookfield subscribed for special shares which contain a redemption feature that provides for the reimbursement of expenses as well as the sharing of the fair market value of a given project. These financial arrangements with Brookfield will not apply to any future projects. Projects that were in late stages of development or construction were transferred by Brookfield for consideration in November 2011 and are not part of this mechanism.

Voting Agreement

Page 167

Brookfield and BEP determined that it is advisable for BEP to have control over the BRELP General Partner, BRELP GP LP and BRELP. Accordingly, BEP and Brookfield entered into the Voting Agreement that provides BEP, through the Managing General Partner, a number of rights.

Pursuant to the Voting Agreement, Brookfield has agreed that any voting rights with respect to the BRELP General Partner, the BRELP GP LP and BRELP will be voted in favor of the election of directors approved by BEP. For these purposes, BEP may maintain, from time-to-time, an approved slate of nominees or provide direction with respect to the approval or rejection of any matter in the form of general guidelines, policies or procedures in which case no further approval or direction will be required. Any such general guidelines, policies or procedures may be modified by BEP in its discretion.

In addition, pursuant to the Voting Agreement, Brookfield has also agreed that any voting rights with respect to the BRELP General Partner, the BRELP GP LP and BRELP will be voted in accordance with the direction of BEP with respect to the approval or rejection of the following matters relating to any such entity, as applicable: (i) any sale of all or substantially all of its assets; (ii) any merger, amalgamation, consolidation, business combination or other material corporate transaction, except in connection with any internal reorganization that does not result in a change of control; (iii) any plan or proposal for a complete or partial liquidation or dissolution, or any reorganization or any case, proceeding or action seeking relief under any existing laws or future laws relating to bankruptcy or insolvency; (iv) any amendment to the limited partnership agreement of BRELP GP LP or to the Amended and Restated Limited Partnership Agreement of BRELP; or (v) any commitment or agreement to do any of the foregoing.

In addition, pursuant to the Voting Agreement, Brookfield has agreed that it will not exercise its right under the limited partnership agreement of BRELP GP LP to remove the BRELP General Partner as the general partner of BRELP GP LP except with the prior consent of BEP.

The Voting Agreement terminates: (i) at such time that Brookfield ceases to own any interest in BRELP; (ii) at such time that the Managing General Partner (or its successors or permitted assigns) involuntarily ceases to be the general partner of BEP; (iii) at such time that the BRELP GP LP (or its successors or permitted assigns) involuntarily ceases to be the general partner of BRELP; or (iv) at such time that the BRELP General Partner (or its successors or permitted assigns) involuntarily ceases to be the general partner of BRELP GP LP. In addition, we are permitted to terminate the Voting Agreement upon 30 days’ notice.

The Voting Agreement also contains restrictions on transfers of the shares of the BRELP General Partner, except that Brookfield may transfer shares of the BRELP General Partner to any of its affiliates.

Other Voting Agreements

From time to time, Brookfield Renewable enters into voting agreements with subsidiaries of Brookfield Asset Management whereby these subsidiaries, as managing members of entities in which Brookfield Renewable holds investments with its institutional investors, agree to exercise certain voting rights as directed by Brookfield Renewable.

Registration Rights Agreement

On November 28, 2011, Brookfield and BEP entered into a registration rights agreement (the “Registration Rights Agreement”) pursuant to which BEP has agreed that, upon the request of Brookfield, BEP will file one or more registration statements to register for sale under the Securities Act, or one or more prospectuses to qualify the distribution in Canada of, any LP Units held by Brookfield (including LP Units acquired pursuant to the Redemption-Exchange Mechanism). Under the Registration Rights Agreement, BEP is not required to file a registration statement or a prospectus unless Brookfield requests that LP Units having a value of at least $50,000,000 be registered or qualified. In the Registration Rights Agreement, BEP has agreed to pay expenses in connection with such registration and sales, except for any underwriting discounts or commissions which will be borne by Brookfield, and will indemnify Brookfield for material misstatements or omissions in the registration statement and/or prospectus.

Licensing Agreement

Page 168

Pursuant to a licensing agreement, Brookfield has granted to us a non-exclusive, royalty-free license to use the name “Brookfield” and the Brookfield logo (the “Licensing Agreement”). Other than under this limited license, we do not have a legal right to the “Brookfield” name and the Brookfield logo on a global basis.

We will be permitted to terminate the Licensing Agreement upon 30 days’ prior written notice if Brookfield defaults in the performance of any material term, condition or agreement contained in the Licensing Agreement and the default continues for a period of 30 days after written notice of termination of the breach is given to Brookfield. Brookfield may terminate the Licensing Agreement effective immediately upon termination of our Master Services Agreement or with respect to any licensee upon 30 days’ prior written notice of termination if any of the following occurs:

·the licensee defaults in the performance of any material term, condition or agreement contained in the Licensing Agreement and the default continues for a period of 30 days after written notice of termination of the breach is given to the licensee;

·the licensee assigns, sublicenses, pledges, mortgages or otherwise encumbers the intellectual property rights granted to it pursuant to the Licensing Agreement;

·certain events relating to a bankruptcy or insolvency of the licensee; or

·the licensee ceases to be an affiliate of Brookfield.

Termination of the Licensing Agreement with respect to one or more licensees will not affect the validity or enforceability of the Licensing Agreement with respect to any other licensees.

Preferred Shares

Brookfield has provided an aggregate of $5 million of working capital to LATAM Holdco through a subscription for preferred shares of LATAM Holdco. The preferred shares are entitled to receive a cumulative preferential dividend equal to 6% of their redemption value as and when declared by the board of directors of LATAM Holdco and are redeemable at the option of LATAM Holdco, subject to certain limitations, at any time after the tenth anniversary of their issuance. The preferred shares are not entitled to vote, except as required by law.

Redemption-Exchange Mechanism

One or more wholly-owned subsidiaries of Brookfield that hold Redeemable/Exchangeable partnership units have the right to require BRELP to redeem all or a portion of the Redeemable/Exchangeable partnership units, subject to BEP’s right of first refusal, for cash in an amount equal to the market value of one of our LP Units multiplied by the number of LP Units to be redeemed (subject to certain adjustments). See Item 10.B “Memorandum and Articles of Association – Description of the Amended and Restated Limited Partnership Agreement of BRELP — Redemption-Exchange Mechanism”. Taken together, the effect of the redemption right and the right of first refusal is that one or more wholly-owned subsidiaries of Brookfield will receive our LP Units, or the value of such LP Units, at the election of BEP. Should BEP determine not to exercise its right of first refusal, cash required to fund a redemption of limited partnership interests of BRELP held by wholly-owned subsidiaries of Brookfield will likely be financed by a public offering of our LP Units.

Indemnification Arrangements

Subject to certain limitations, Brookfield and its directors, officers, agents, members, partners, shareholders and employees generally benefit from indemnification provisions and limitations on liability that are included in the Amended and Restated Limited Partnership Agreement of BEP, Managing General Partner’s bye-laws, the Amended and Restated Limited Partnership Agreement of BRELP, our Master Services Agreement and other arrangements with Brookfield. See Item 6.A “Directors and Senior Management — Our Master Services Agreement”, Item 10.B “Memorandum and Articles of Association — Description of Our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP — Indemnification; Limitations on Liability” and “Memorandum and Articles of Association — Description of the Amended and Restated Limited Partnership Agreement of BRELP — Indemnification; Limitations on Liability”.

Other Services

Page 169

Brookfield may provide the Operating Entities with services which are outside the scope of our Master Services Agreement under arrangements that are on market terms and conditions and pursuant to which Brookfield will receive fees. The services provided under these arrangements will include financial advisory, operations management and other services. Pursuant to our conflict of interest guidelines, those arrangements may require prior approval by a majority of the independent directors, which may be granted in the form of general guidelines, policies or procedures. See Item 7.B “Related Party Transactions— Conflicts of Interest and Fiduciary Duties”.

Conflicts of Interest and Fiduciary Duties

Fiduciary Duties

Each of the Managing General Partner and the BRELP General Partner are required to exercise its powers and carry out its functions as general partner of BEP and BRELP, respectively, honestly and in good faith, and exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances, in each case, subject to and after taking into account, the terms and conditions of the Relationship Agreement, our Master Services Agreement and the Conflicts Policy. However, the Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP contain various provisions that modify the fiduciary duties that might otherwise be owed to us and our LP Unitholders and Preferred Unitholders, including when conflicts of interest arise. These duties include the duties of care and loyalty. The duty of loyalty, in the absence of provisions in the Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP to the contrary, would generally prohibit the Managing General Partner and BRELP General Partner from taking any action or engaging in any transaction as to which it has a conflict of interest. However, the Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP provide that the Managing General Partner, BRELP General Partner and their affiliates will not have any obligation under the Amended and Restated Limited Partnership Agreement of BEP and the Amended and Restated Limited Partnership Agreement of BRELP, or as a result of any duties stated or implied by law or equity, including fiduciary duties, to present business or investment opportunities to Brookfield Renewable, BRELP, any Holding Entity or any other holding vehicle established by Brookfield Renewable. They also allow affiliates of the Managing General Partner and BRELP General Partner to engage in activities that may compete with us or our activities, and state that, subject to applicable law, no breach of the Amended and Restated Limited Partnership Agreement of BEP or the Amended and Restated Limited Partnership Agreement of BRELP, or a breach of any duty, including fiduciary duties, may be found for any matter that has been approved by a majority of the independent directors of the Managing General Partner. Further, when resolving conflicts of interest, neither the Amended and Restated Limited Partnership Agreement of BEP nor the Amended and Restated Limited Partnership Agreement of BRELP impose limitations on the discretion of the independent directors or the factors which they may consider in resolving any such conflicts. The independent directors of our Managing General Partner can therefore take into account the interests of third parties, including Brookfield, when resolving conflicts of interest.

These modifications to the fiduciary duties may be detrimental to our LP Unitholders and Preferred Unitholders because they restrict the remedies available for actions that might otherwise constitute a breach of fiduciary duty and permit conflicts of interest to be resolved in a manner that is not always in the best interests of Brookfield Renewable or the best interests of our LP Unitholders and Preferred Unitholders. We believe that it was necessary to modify the fiduciary duties that might otherwise be owed to us and our LP Unitholders and Preferred Unitholders, as described above, due to our organizational and ownership structure and the potential conflicts of interest created thereby. Without modifying those duties, the ability of the Managing General Partner and BRELP General Partner to attract and retain experienced and capable directors and to take actions that we believe will be necessary for the carrying out of our business would be unduly limited due to their concern about potential liability.

Conflicts of Interest

We maintain a conflicts protocol and guidelines (the “Conflicts Policy”) for addressing conflicts and potential conflicts and for providing guidelines for the completion of certain transactions. The Conflicts Policy states that conflicts be resolved based on the principles of transparency and that

Page 170

transactions that are carried out, be carried out at an arm’s length basis, with validation of terms as arm’s length being based upon actual participation of arm’s length third party participants such as co-investors whenever possible, or otherwise through objective, independent professional advice or other satisfactory evidence of market terms.

The Conflicts Policy recognizes the benefit to us of our relationship with Brookfield and our intent to pursue a strategy that seeks to maximize the benefits from this relationship. The Conflicts Policy also recognizes that the principal areas of potential application of the Conflicts Policy on an ongoing basis will be in connection with our acquisitions and our participation in Brookfield sponsored funds, consortia and partnership arrangements, together with any management or service arrangements entered into in connection therewith or the ongoing operations of the underlying Operating Entities. The Conflicts Policy may be amended from time to time at the discretion of the Managing General Partner.

In general, the Conflicts Policy provides that acquisitions that are carried out jointly by us and Brookfield, or in the context of a Brookfield led or co-led sponsored fund, consortium or partnership, be carried out on the basis that the consideration paid by us be no more, on a per share or proportionate basis, than the consideration paid by Brookfield or other participants, as applicable. The Conflicts Policy also provides that any fees or carried interest payable in respect of our proportionate investment, or in respect of an acquisition made solely by us, must be credited in the manner contemplated by our Master Services Agreement and the Amended and Restated Limited Partnership Agreement of BRELP, where applicable, or that such fees or carried interest must either have been negotiated with another arm’s-length participant or otherwise demonstrated to be on market terms. The Conflicts Policy further provides that if the acquisition involves the purchase by us of an asset from Brookfield, or the participation in a transaction involving the purchase by us and Brookfield of different assets, that a fairness opinion or, in some circumstances, a valuation or appraisal by a qualified expert be obtained, confirming that the consideration paid by us is fair from a financial point of view. These requirements provided for in the Conflicts Policy are in addition to any disclosure, approval and valuation requirements that may arise under applicable law.

With respect to transactions in which there is greater potential for a conflict of interest to arise, the Managing General Partner may be required to seek the prior approval of the independent directors pursuant to the Conflicts Policy that has been approved by the independent directors from time to time. These transactions include:

·subject to certain exceptions, acquisitions by us from, and dispositions by us to, Brookfield;

·acquisitions whereby Brookfield Renewable and Brookfield are purchasing different assets as part of a single transaction;

·investing in a private Brookfield sponsored-fund, consortium or partnership;

·the dissolution of BEP or BRELP;

·any material amendment to our Master Services Agreement, the Relationship Agreement, the Amended and Restated Limited Partnership Agreement of BRELP or the Amended and Restated Limited Partnership Agreement of BEP;

·subject to certain exceptions, any material service agreement or other arrangement pursuant to which Brookfield will be paid a fee, or other consideration other than any agreement or arrangement contemplated by our Master Services Agreement;

·determinations regarding the payment of fees in the LP Units of BEP or limited partnership units of BRELP or the deferral of the incentive distribution (see Item 7.B “Related Party Transactions — Incentive Distributions”);

·termination of, or any determinations regarding indemnification under, our Master Services Agreement or determinations regarding indemnification under the Amended and Restated Limited Partnership Agreement of BRELP or the Amended and Restated Limited Partnership Agreement of BEP; and

·subject to certain exceptions, other material transactions involving us and Brookfield.

Page 171

Pursuant to the Conflicts Policy, independent directors may grant prior approvals for any of these transactions in the form of general guidelines, policies or procedures in which case no further special approval will be required in connection with a particular transaction or matter permitted thereby.

In certain circumstances, these transactions may be related party transactions for the purposes of, and subject to certain requirements of, Canadian Multilateral Instrument 61-101— Protection of Minority Securityholders in Special Transactions (“MI 61-101”). MI 61-101 provides a number of circumstances in which a transaction between an issuer and a related party may be subject to valuation and minority approval requirements. An exemption from such requirements is available when the fair market value of the transaction is not more than 25% of the market capitalization of the issuer. BEP has been granted exemptive relief from the requirements of MI 61-101 that, subject to certain conditions, permits it to be exempt from the minority approval and valuation requirements for transactions that would have a value of less than 25% of BEP’s market capitalization, if the indirect equity interest in BEP, which is held in the form of Redeemable/Exchangeable partnership units, is included in the calculation of BEP’s market capitalization. As a result, the 25% threshold, above which the minority approval and valuation requirements apply, is increased to include the approximately 43.7% indirect interest in BEP held by Brookfield in the form of Redeemable/Exchangeable partnership units.

Our organizational and ownership structure and strategy involve a number of relationships that may give rise to conflicts of interest between BEP and our Unitholders, on the one hand, and Brookfield, on the other hand. In particular, conflicts of interest could arise, among other reasons, because:

·in originating and recommending acquisition opportunities, Brookfield has significant discretion to determine the suitability of opportunities for us and to allocate such opportunities to us or to itself or third parties;

·because of the scale of typical renewable power acquisitions and because our strategy includes completing acquisitions through fund, consortium or partnership arrangements with pension funds and other financial sponsors, we will likely make co-investments with Brookfield and Brookfield sponsored funds or Brookfield sponsored or co-sponsored funds, consortiums and partnerships, which typically will require that Brookfield owe fiduciary duties to the other partners, investors or consortium members that it does not owe to us;

·there may be circumstances where Brookfield determines that an acquisition opportunity is not suitable for us because: (i) it does not fit with our acquisition strategy; (ii) limits arising due to regulatory or tax considerations; and/or (iii) limits on our financial capacity, and Brookfield is entitled to pursue the acquisition on its own behalf rather than offering us the opportunity to make the acquisition;

·where Brookfield has made an acquisition, it may transfer it to us at a later date after the assets have been developed or we have obtained sufficient financing;

·our relationship with Brookfield involves a number of arrangements pursuant to which Brookfield provides various services, access to financing arrangements and originates acquisition opportunities, and circumstances may arise in which these arrangements will need to be amended or new arrangements will need to be entered into;

·under the Amended and Restated Limited Partnership Agreement of BRELP and the agreements governing the Operating Entities, Brookfield is generally entitled to share in the returns generated by our operations, which could create an incentive for it to assume greater risks when making decisions than it otherwise would in the absence of such arrangements;

·Brookfield is permitted to pursue other business activities and provide services to third parties that compete directly with our business and activities without providing us with an opportunity to participate, which could result in the allocation of Brookfield’s resources, personnel and acquisition opportunities to others who compete with us;

·Brookfield does not owe Brookfield Renewable or our LP Unitholders and Preferred Unitholders any fiduciary duties, which may limit our recourse against it;

·the liability of Brookfield is limited under our arrangements with them, and we have agreed to indemnify Brookfield against claims, liabilities, losses, damages, costs or expenses which they may face in connection with those arrangements, which may lead them to assume greater risks when making decisions than they otherwise would if such decisions were being

Page 172

made solely for their own account, or may give rise to legal claims for indemnification that are adverse to the interests of our LP Unitholders and Preferred Unitholders;

·Brookfield or a Brookfield sponsored fund or consortium may want to acquire or dispose of the same asset as us;

·we may be, directly or indirectly, purchasing an asset from, or selling an asset to, Brookfield; and

·there may be circumstances where we are acquiring different assets as part of the same transaction with Brookfield.

Other Related Party Transactions

The $400 million committed unsecured revolving credit facility provided by Brookfield, at LIBOR plus 2%, has been extended for one year to December 2018 on the same terms.

Brookfield had placed funds on deposit with Brookfield Renewable during the first quarter of 2017 in the amount of $140 million. Interest earned on the deposits was at market terms and all funds on deposit were returned to Brookfield before the end of the first quarter of 2017.

7.C              INTEREST OF EXPERTS AND COUNSEL

Not applicable.

ITEM 8.       FINANCIAL INFORMATION         

8.A              CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

Financial Statements

See Item 18. “Financial Statements”, which contains our audited consolidated financial statements prepared in accordance with IFRS.

Dividend Policy

            See Item 4.B “Business Operations — Our LP Unit Distribution Policy”, which contains information regarding our dividend policy. Also see Item 4.B “Business Operations — Distributions to Preferred Unitholders”.

Legal Proceedings

See Item 18. “Financial Statements”.

8.B              SIGNIFICANT CHANGES

A discussion of the significant changes in our business can be found under Item 4. “Information on the Company”, Item 4.A “History and Development of the Company” and Item 5.A “Operating Results”.

ITEM 9.       THE OFFER AND LISTING           

9.A              OFFER AND LISTING DETAILS

Our LP Units are listed on the NYSE under the symbol “BEP”. Our LP Units do not have a par value.Our LP Units began trading on the NYSE on June 11, 2013.  The following table sets forth the reported high and low prices of our LP Units on the NYSE for the periods indicated since issued:

	High	Low
Year ended December 31, 2017	$35.82	$28.21
Year ended December 31, 2016	$31.64	$21.69
Year ended December 31, 2015	$33.42	$22.88
Year ended December 31, 2014	$32.72	$25.08
Year ended December 31, 2013	$30.00	$24.69

The following table sets forth the reported high and low prices of our LP Units on the NYSE for the periods indicated:

Page 173

	High	Low
2017
October 1, 2017 to December 31, 2017	$35.21	$32.28
July 1, 2017 to September 30, 2017	$35.82	$32.01
April 1, 2017 to June 30, 2017	$33.96	$29.33
January 1, 2017 to March 31, 2017	$30.45	$28.21
2016
October 1, 2016 to December 31, 2016	$31.15	$26.80
July 1, 2016 to September 30, 2016	$31.64	$29.04
April 1, 2016 to June 30, 2016	$30.22	$28.49
January 1, 2016 to March 31, 2016	$29.95	$21.69

The following table sets forth the monthly high and low prices for our LP Units on the NYSE for the most recent six months:

	High	Low
2018
February (February 1 through to February 26)	$33.25	$31.67
January	$34.92	$32.89
2017
December	$34.94	$32.28
November	$34.08	$32.84
October	$35.21	$32.95
September	$35.82	$33.04

Our LP Units are listed on the TSX under the symbol “BEP.UN”. Our LP Units do not have a par value. Trading on the TSX commenced on November 30, 2011. On March 21, 2014, our LP Units were added to the S&P/TSX Composite Index. The following table sets forth the reported high and low prices of our LP Units on the TSX for the periods indicated since issued:

	High	Low
Year ended December 31, 2017	C$44.96	C$38.00
Year ended December 31, 2016	C$41.50	C$31.43
Year ended December 31, 2015	C$41.78	C$31.45
Year ended December 31, 2014	C$36.84	C$27.67
Year ended December 31, 2013	C$32.02	C$25.69

The following table sets forth the quarterly high and low prices for our LP Units on the TSX for the two most recent full financial years:

	High	Low
2017
October 1, 2017 to December 31, 2017	C$44.96	C$41.20
July 1, 2017 to September 30, 2017	C$44.38	C$40.58
April 1, 2017 to June 30, 2017	C$44.40	C$39.17
January 1, 2017 to March 31, 2017	C$39.89	C$38.00
2016
October 1, 2016 to December 31, 2016	C$41.13	C$36.31
July 1, 2016 to September 30, 2016	C$41.50	C$38.15
April 1, 2016 to June 30, 2016	C$39.29	C$36.33
January 1, 2016 to March 31, 2016	C$39.26	C$31.43

Page 174

The following table sets forth the monthly high and low prices for our LP Units on the TSX for the most recent six months:

	High	Low
2018
February (February 1 through to February 26)	C$40.95	C$39.74
January	C$43.64	C$40.59
2017
December	C$44.96	C$41.20
November	C$43.81	C$42.25
October	C$44.01	C$41.25
September	C$43.47	C$40.58

Prior to November 2011, the Fund’s trust units, which were exchanged for our LP Units on a one-for-one basis in November 2011, were listed on the TSX under the symbol “BRC.UN”. The following table sets forth the reported high and low prices of the Fund’s trust units on the TSX for the periods indicated:

	High	Low
Year ended December 31, 2011	C$28.10	C$20.58
Year ended December 31, 2010	C$22.41	C$18.76
Year ended December 31, 2009	C$20.00	C$14.70

See Item 5.A “Operating Results”, Item 7.B “Related Party Transactions” and Item 10. “Additional Information”.

9.B              PLAN OF DISTRIBUTION

Not applicable.

9.C              MARKETS

See Item 9.A. “Offer and Listing Details”.

9.D              SELLING SHAREHOLDERS

Not applicable.

9.E              DILUTION

Not applicable.

9.F              EXPENSES OF THE ISSUE

Not applicable.

ITEM 10.     ADDITIONAL INFORMATION       

10.A            SHARE CAPITAL

Not applicable.

Page 175

10.B            MEMORANDUM AND ARTICLES OF ASSOCIATION

Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP

The following is a description of the material terms of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP. Because this description is only a summary of the terms of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP, it does not contain all of the information that you may find useful and is qualified in its entirety by reference to all of the provisions of the Amended and Restated Limited Partnership Agreement of BEP. For more complete information, you should read the Amended and Restated Limited Partnership Agreement of BEP which is available electronically on our EDGAR profile at www.sec.gov and on our SEDAR profile at www.sedar.com and will be made available to LP Unitholders and Preferred Unitholders as described under Item 10.C “Material Contracts” and Item 10.H “Documents on Display”.

See also the information contained in this Form 20-F under Item 3.D “Risk Factors—Risks Related to Our Relationship with Brookfield”, Item 6.A “Directors and Senior Management”, Item 6.C “Board Practices” and Item 7.B “Related Party Transactions”.

Formation and Duration

BEP is a Bermuda exempted limited partnership registered under the Limited Partnership Act 1883 and the Exempted Partnerships Act1992. BEP has a perpetual existence and will continue as a limited liability partnership unless it is terminated or dissolved in accordance with the Amended and Restated Limited Partnership Agreement of BEP. BEP’s interests consist of our LP Units and Preferred Units, which represent limited partnership interests in BEP, and any additional partnership interests representing limited partnership interests that we may issue in the future as described below under “— Issuance of Additional Partnership Interests”.

Nature and Purpose

Under section 2.2 of the Amended and Restated Limited Partnership Agreement of BEP, the purpose of BEP is to: acquire and hold interests in BRELP and, subject to the approval of the Managing General Partner, any other subsidiary of BEP; engage in any activity related to the capitalization and financing of Brookfield Renewable’s interests in such entities; and engage in any other activity that is incidental to or in furtherance of the foregoing and that is approved by the Managing General Partner and that lawfully may be conducted by a limited partnership organized under the Limited Partnership Act1883, the Exempted Partnerships Act 1992 and the Amended and Restated Limited Partnership Agreement of BEP.

Management

As required by law, the Amended and Restated Limited Partnership Agreement of BEP provides for the management and control of BEP by a general partner, being the Managing General Partner. The Managing General Partner will exercise its powers and carry out its functions honestly and in good faith and the Managing General Partner will exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances, in each case, subject to, and after taking into account, the terms and conditions of the Relationship Agreement, our Master Services Agreement and the Conflicts Policy. Except as set out in the Amended and Restated Limited Partnership Agreement of BEP, the Managing General Partner has no additional duty to propose or approve any conduct of BEP, and may decline to propose or approve such conduct free of any additional duty (including fiduciary duty). The Managing General Partner shall not be in breach of any duty to BEP if it takes actions permitted by the Amended and Restated Limited Partnership Agreement of BEP, the Relationship Agreement, our Master Services Agreement or the Conflicts Policy.

Our Holders of LP Units or Preferred Units

Our LP Units and Preferred Units are limited partnership interests in BEP. Holders of our LP Units or Preferred Units are not entitled to the withdrawal or return of capital contributions in respect of our LP Units or Preferred Units, except to the extent, if any, that distributions are made to such holders pursuant

Page 176

to the Amended and Restated Limited Partnership Agreement of BEP or upon the liquidation of BEP as described below under “— Liquidation and Distribution of Proceeds” or as otherwise required by applicable law.

Except to the extent expressly provided in the Amended and Restated Limited Partnership Agreement of BEP, a holder of our LP Units or Preferred Units does not have priority over any other LP Unitholder or Preferred Unitholder, respectively, either as to the return of capital contributions or as to profits, losses or distributions. Unless otherwise determined by the Managing General Partner, in its sole discretion, LP Unitholders and Preferred Unitholders will not be granted any pre-emptive or other similar right to acquire additional interests in BEP. In addition, LP Unitholders and Preferred Unitholders do not have any right to have their LP Units or Preferred Units redeemed by BEP.

Our Preferred Units

The Class A Preferred Units rank senior to the LP Units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BEP, whether voluntary or involuntary. Each series of Class A Preferred Units ranks on a parity with every other series of the Class A Preferred Units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BEP, whether voluntary or involuntary. Each series of Class A Preferred Units ranks on a parity with every other series of the Class A Preferred Units with respect to priority in the return of capital contributions or as to profits, losses and distributions.

The Series 13 Preferred Units will not be redeemable by BEP prior to April 30, 2023.  On April 30, 2023 and on April 30 every five years thereafter, BEP may redeem for cash the Series 13 Preferred Units at C$25 per Series 13 Preferred Unit, together with all accrued and unpaid distributions up to but excluding the date of payment or distribution.  Holders of the Series 13 Preferred Units will have the right, at their option, to reclassify their Series 13 Preferred Units into Series 14 Preferred Units, subject to certain conditions, on April 30, 2023 and on April 30 every five years thereafter. The Series 13 Preferred Units do not have a fixed maturity date and are not redeemable at the option of the Series 13 Preferred Unitholders.

The Series 11 Preferred Units will not be redeemable by BEP prior to April 30, 2022.  On April 30, 2022 and on April 30 every five years thereafter, BEP may redeem for cash the Series 11 Preferred Units at C$25 per Series 11 Preferred Unit, together with all accrued and unpaid distributions up to but excluding the date of payment or distribution.  Holders of the Series 11 Preferred Units will have the right, at their option, to reclassify their Series 11 Preferred Units into Series 12 Preferred Units, subject to certain conditions, on April 30, 2022 and on April 30 every five years thereafter. The Series 11 Preferred Units do not have a fixed maturity date and are not redeemable at the option of the Series 11 Preferred Unitholders.

The Series 9 Preferred Units will not be redeemable by BEP prior to July 31, 2021.  On July 31, 2021 and on July 31 every five years thereafter, BEP may redeem for cash the Series 9 Preferred Units at C$25 per Series 9 Preferred Unit, together with all accrued and unpaid distributions up to but excluding the date of payment or distribution.  Holders of the Series 9 Preferred Units will have the right, at their option, to reclassify their Series 9 Preferred Units into Series 10 Preferred Units, subject to certain conditions, on July 31, 2021 and on July 31 every five years thereafter. The Series 9 Preferred Units do not have a fixed maturity date and are not redeemable at the option of the Series 9 Preferred Unitholders.

The Series 7 Preferred Units will not be redeemable by BEP prior to January 31, 2021.  On January 31, 2021 and on January 31 every five years thereafter, BEP may redeem for cash the Series 7 Preferred Units at C$25 per Series 7 Preferred Unit, together with all accrued and unpaid distributions up to but excluding the date of payment or distribution.  Holders of the Series 7 Preferred Units will have the right, at their option, to reclassify their Series 7 Preferred Units into Series 8 Preferred Units, subject to certain conditions, on January 31, 2021 and on January 31 every five years thereafter. The Series 7 Preferred Units do not have a fixed maturity date and are not redeemable at the option of the Series 7 Preferred Unitholders.

The Series 5 Preferred Units will not be redeemable by BEP prior to April 30, 2018. On and after April 30, 2018, BEP may redeem for cash the Series 5 Preferred Units at C$26 per Series 5 Preferred

Page 177

Unit if redeemed before April 30, 2019, C$25.75 per Series 5 Preferred Unit if redeemed on or after April 30, 2019, C$25.50 per Series 5 Preferred Unit if redeemed on or after April 30, 2020, C$25.25 per Series 5 Preferred Unit if redeemed on or after April 30, 2021, and C$25 per Series 5 Preferred Unit if redeemed on or after April 30, 2022, in each case together with all accrued and unpaid dividends up to but excluding the date fixed for redemption (less any tax required to be deducted and withheld by BEP). The Series 5 Preferred Units do not have a fixed maturity date and are not redeemable at the option of the Series 5 Preferred Unitholders.

Issuance of Additional Partnership Interests

Subject to the rights of the holders of Class A Preferred Units to approve issuances of additional partnership interests ranking senior to the Class A Preferred Units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BEP, whether voluntary or involuntary, and to any approval required by applicable law and the approval of any applicable securities exchange, the Managing General Partner has broad rights to cause BEP to issue additional partnership interests and may cause BEP to issue additional partnership interests (including new classes of partnership interests and options, rights, warrants and appreciation rights relating to such interests) for any partnership purpose, at any time and on such terms and conditions as it may determine without the approval of any limited partners. Any additional partnership interests may be issued in one or more classes, or one or more series of classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership interests) as may be determined by the Managing General Partner in its sole discretion, all without approval of our limited partners.

Transfers of Units

We are not required to recognize any transfer of our LP Units or Preferred Units until certificates, if any, evidencing such LP Units are surrendered for registration of transfer. Each person to whom an LP Unit or Preferred Unit is transferred or issued (including any nominee holder or an agent or representative acquiring such LP Unit Or Preferred Unit for the account of another person) shall be admitted to BEP as a partner with respect to the unit so transferred or issued when any such transfer or issuance is reflected in the books and records of BEP subject to and in accordance with the terms of the Amended and Restated Limited Partnership Agreement of BEP. Any transfer of an LP Unit or Preferred Unit shall not entitle the transferee to share in the profits and losses of BEP, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a partner and a party to the Amended and Restated Limited Partnership Agreement of BEP.

By accepting an LP Unit or Preferred Unit for transfer in accordance with the Amended and Restated Limited Partnership Agreement of BEP, each transferee will be deemed to have:

·executed the Amended and Restated Limited Partnership Agreement of BEP and become bound by the terms thereof;

·granted an irrevocable power of attorney to the Managing General Partner or the liquidator of BEP and any officer thereof to act as such partner’s agent and attorney-in-fact to execute, swear to, acknowledge, deliver, file and record in the appropriate public offices (i) all agreements, certificates, documents and other instruments relating to the existence or qualification of BEP as an exempted limited partnership (or a partnership in which the limited partners have limited liability) in Bermuda and in all jurisdictions in which BEP may conduct activities and affairs or own property; any amendment, change, modification or restatement of the Amended and Restated Limited Partnership Agreement of BEP, subject to the requirements of the Amended and Restated Limited Partnership Agreement of BEP; the dissolution and liquidation of BEP; the admission, withdrawal of any partner of BEP or any capital contribution of any partner of BEP; the determination of the rights, preferences and privileges of any class or series of Units of BEP; and any tax election with any limited partner or general partner on our behalf or on behalf of any limited partner or the general partner, and (ii) subject to the requirements of the Amended and Restated Limited Partnership Agreement of BEP, all ballots, consents, approvals, waivers, certificates, documents and other instruments necessary or appropriate, in the sole discretion of the Managing General Partner

Page 178

or the liquidator of BEP, to make, evidence, give, confirm or ratify any voting consent, approval, agreement or other action that is made or given by BEP’s partners or is consistent with the terms of the Amended and Restated Limited Partnership Agreement of BEP or to effectuate the terms or intent of the Amended and Restated Limited Partnership Agreement of BEP;

·made the consents and waivers contained in the Amended and Restated Limited Partnership Agreement of BEP; and

·ratified and confirmed all contracts, agreements, assignments and instruments entered into on behalf of BEP in accordance with the Amended and Restated Limited Partnership Agreement of BEP, including the granting of any charge or security interest over the assets of BEP and the assumption of any indebtedness in connection with the affairs of BEP.

The transfer of any Unit and/or the admission of any new partner to BEP will not constitute an amendment to the Amended and Restated Limited Partnership Agreement of BEP.

Book-Based System

LP Units and Preferred Units may be represented in the form of one or more fully registered unit certificates held by, or on behalf of, CDS or DTC, as applicable, as custodian of such certificates for the participants of CDS or DTC, registered in the name of CDS or DTC or their respective nominee, and registration of ownership and transfers of LP Units and Preferred Units may be effected through the book-based system administered by CDS or DTC, as applicable.

Investments in BRELP

If and to the extent that BEP raises funds by way of the issuance of equity or debt securities, or otherwise, pursuant to a public offering, private placement or otherwise, an amount equal to the proceeds will be invested in BRELP.

Capital Contributions

Brookfield contributed $1 and the Managing General Partner contributed $100 to the capital of BEP in order to form BEP. Thereafter, Brookfield contributed to BEP its interest in various renewable power businesses in exchange for Redeemable/Exchangeable partnership units and our LP Units. No partner has the right to withdraw any or all of its capital contribution.

Distributions

Subject to the rights of holders of Class A Preferred Units to receive cumulative preferential cash distributions in accordance with the terms of a series of Class A Preferred Units, distributions to partners of BEP will be made only as determined by the Managing General Partner in its sole discretion. However, the Managing General Partner will not be permitted to cause BEP to make a distribution (i) if it does not have sufficient cash on hand to make the distribution, (ii) if the distribution would render it insolvent or (iii) if, in the opinion of the Managing General Partner, the distribution would leave it with insufficient funds to meet any future or contingent obligations or if the distribution would contravene the Limited Partnership Act1883. In addition, BEP will not be permitted to make a distribution on our LP Units unless all accrued distributions have been paid in respect of the Class A Preferred Units, and all other units of BEP ranking prior to or on a parity with the Class A Preferred Units with respect to the payment of distributions.

The amount of taxes withheld or paid by BEP or by any member of Brookfield Renewable in respect of LP Units and Preferred Units held by LP Unitholders, Preferred Unitholders or the Managing General Partner shall be treated either as a distribution to such partner or as a general expense of BEP as determined by the Managing General Partner in its sole discretion.

Holders of the Series 13 Preferred Units will be entitled to receive a cumulative quarterly fixed distribution at a rate of 5.00% annually for the initial period ending April 30, 2023.  Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5 year Government of Canada bond yield plus 3.00%, and (ii) 5.00%.  Holders of Series 13 Preferred Units will have the right to reclassify their Series 13 Preferred Units, subject to certain conditions, into Series 14 Preferred Units. Holders of Series 14 Preferred Units will be entitled to receive a cumulative quarterly floating distribution at a rate equal to the 90 day Canadian Treasury Bill yield plus 3.00%.

Page 179

Holders of the Series 11 Preferred Units will be entitled to receive a cumulative quarterly fixed distribution at a rate of 5.00% annually for the initial period ending April 30, 2022.  Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5 year Government of Canada bond yield plus 3.82%, and (ii) 5.00%.  Holders of Series 11 Preferred Units will have the right to reclassify their Series 11 Preferred Units, subject to certain conditions, into Series 12 Preferred Units. Holders of Series 12 Preferred Units will be entitled to receive a cumulative quarterly floating distribution at a rate equal to the 90 day Canadian Treasury Bill yield plus 3.82%.

Holders of the Series 9 Preferred Units will be entitled to receive a cumulative quarterly fixed distribution at a rate of 5.75% annually for the initial period ending July 31, 2021.  Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5 year Government of Canada bond yield plus 5.01%, and (ii) 5.75%.  Holders of Series 9 Preferred Units will have the right to reclassify their Series 9 Preferred Units, subject to certain conditions, into Series 10 Preferred Units. Holders of Series 10 Preferred Units will be entitled to receive a cumulative quarterly floating distribution at a rate equal to the 90 day Canadian Treasury Bill yield plus 5.01%. 

Holders of the Series 7 Preferred Units will be entitled to receive a cumulative quarterly fixed distribution at a rate of 5.50% annually for the initial period ending January 31, 2021. Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5 year Government of Canada bond yield plus 4.47%, and (ii) 5.50%. Holders of Series 7 Preferred Units will have the right to reclassify their Series 7 Preferred Units, subject to certain conditions, into Series 8 Preferred Units. Holders of the Series 8 Preferred Units will be entitled to receive a cumulative quarterly floating distribution at a rate equal to the 90 day Canadian Treasury Bill yield plus 4.47%.

Holders of the Series 5 Preferred Units will be entitled to receive fixed cumulative preferential cash distributions, as and when declared by the Managing General Partner, payable quarterly on the last day of January, April, July and October in each year at an annual rate equal to 5.59%, less any tax required to be deducted and withheld.

Subject to the terms of any Preferred Units outstanding at the time, any distributions from BEP will be made to the limited partners holding LP Units as to 99.99% and to the Managing General Partner as to 0.01%.Distributions to holders of Class A Preferred Units in accordance with their terms rank higher in priority than distributions to holders of our LP Units. Each holder of LP Units or Preferred Units will receive a pro rata share of distributions made to all holders of LP Units or Preferred Units, as applicable, in accordance with the proportion of all outstanding LP Units or Preferred Units held by that unitholder. Except for receiving 0.01% of distributions from BEP, the Managing General Partner shall not be compensated for its services as Managing General Partner but it shall be reimbursed for certain expenses.

Allocations of Income and Losses

Limited partners (other than partners holding Preferred Units) will share in the net profits and net losses of BEP generally in accordance with their respective percentage interest in BEP.

Net income and net losses for U.S. federal income tax purposes will be allocated for each taxable year or other relevant period among our partners (other than our partners holding Preferred Units) using a monthly, quarterly or other permissible convention pro rata on a per unit basis, except to the extent otherwise required by law or pursuant to tax elections made by BEP. Each item of income, gain, loss and deduction so allocated to a partner of BEP (other than a partner holding Preferred Units) generally will have the same source and character as though such partner had realized the item directly.

The income for Canadian federal income tax purposes of BEP for a given fiscal year of BEP will be allocated to each partner in an amount calculated by multiplying such income by a fraction, the numerator of which is the sum of the distributions received by such partner with respect to such fiscal year,provided that the numerator and denominator will not include any distributions on the Preferred Units that are in satisfaction of accrued distributions on the Preferred Units that were not paid in a previous fiscal year of BEP where the Managing General Partner determines that the inclusion of such distributions would result in a Preferred Unitholder being allocated more income than it would have been if the distributions were paid in the fiscal year of BEP in which they were accrued. Generally, the source

Page 180

and character of items of income so allocated to a partner with respect to a fiscal year of BEP will be the same source and character as the distributions received by such partner with respect to such fiscal year.

If, with respect to a given fiscal year, no distribution is made by BEP, or Brookfield Renewable has a loss for Canadian federal income tax purposes, one quarter of the income, or loss, as the case may be, for Canadian federal income tax purposes for such fiscal year, will be allocated to the partners of record at the end of each quarter ending in such fiscal year as follows: (i) to the Preferred Unitholders in respect of Preferred Units held by them on each such date, such amount of the income or the loss, as the case may be, for Canadian federal income tax purposes as the Managing General Partner determines is reasonable in the circumstances having regard to such factors as the Managing General Partner considers to be relevant, including, without limitation, the relative amount of capital contributed to our partnership on the issuance of Preferred Units as compared to all other LP Units and the relative fair market value of the Preferred Units as compared to all other LP Units, and (ii) to the partners, other than in respect of Preferred Units, the remaining amount of the income or the loss, as the case may be, for Canadian federal income tax purposes pro rata to their respective percentage interests on each such date.

However, any gain for Canadian tax purposes allocated by BRELP to BEP in respect of the disposition of the common shares of NA Holdco by BRELP, will be allocated for Canadian tax purposes firstly, in respect of any LP Units held by Brookfield that were acquired on the exchange of Redeemable/Exchangeable partnership units, such portion of the gain, if any, that would otherwise have been allocated for Canadian tax purposes to Brookfield in respect of the Redeemable/Exchangeable partnership units on the assumption that such units had not been exchanged for LP Units and remained Redeemable/Exchangeable partnership units, shall be allocated pro rata to Brookfield in respect of our LP Units acquired on the exchange of Redeemable/Exchangeable partnership units, and secondly, the remaining portion of the gain, if any, shall be allocated to LP Unitholders on a per LP Unit basis excluding: (i) LP Units owned by Brookfield immediately after November 28, 2011; and (ii) LP Units acquired by Brookfield pursuant to the Redemption-Exchange Mechanism. The foregoing summary, to the extent it states matters of Canadian or U.S. tax law or legal conclusions, is qualified in its entirety by the sections in this Form 20-F under Item 10.E entitled “Certain Material Canadian Federal Income Tax Considerations” and “Material U.S. Federal Income Tax Considerations”.

Limited Liability

Assuming that a limited partner does not participate in the control or management of BEP or conduct the affairs of, sign or execute documents for or otherwise bind BEP within the meaning of the Limited Partnership Act 1883 and otherwise acts in conformity with the provisions of the Amended and Restated Limited Partnership Agreement of BEP, such partner’s liability under the Limited Partnership Act 1883 and the Amended and Restated Limited Partnership Agreement of BEP will be limited to the amount of capital such partner is obligated to contribute to BEP for its limited partner interest plus its share of any undistributed profits and assets, except as described below.

If it were determined, however, that a limited partner was participating in the control or management of BEP or conducting the affairs of, signing or executing documents for or otherwise binding BEP (or purporting to do any of the foregoing) within the meaning of the Limited Partnership Act 1883 or the Exempted Partnerships Act1992  , such limited partner would be liable as if it were a general partner of BEP in respect of all debts of BEP incurred while that limited partner was so acting or purporting to act. Neither the Amended and Restated Limited Partnership Agreement of BEP nor the Limited Partnership Act 1883 specifically provides for legal recourse against the Managing General Partner if a limited partner were to lose limited liability through any fault of the Managing General Partner. While this does not mean that a limited partner could not seek legal recourse, we are not aware of any precedent for such a claim in Bermuda case law.

No Management or Control

BEP’s limited partners, in their capacities as such, may not take part in the management or control of the activities and affairs of BEP and do not have any right or authority to act for or to bind BEP or to take part or interfere in the conduct or management of BEP. Limited partners are not entitled to vote on matters relating to BEP, although LP Unitholders are entitled to consent to certain matters as

Page 181

described under “— Amendments to the Amended and Restated Limited Partnership Agreement of BEP”, “— Opinion of Counsel and Limited Partner Approval”, “— Sale or Other Disposition of Assets”, and “— Withdrawal of the Managing General Partner” which may be effected only with the consent of the holders of the percentages of our outstanding LP Units specified below. In addition, limited partners have consent rights with respect to certain fundamental matters and on any other matters that require their approval in accordance with applicable securities laws and stock exchange rules. Each LP Unit shall entitle the LP Unitholder to one vote for the purposes of any approvals of LP Unitholders. Except as otherwise provided by law or as set out in the provisions attached to any series of Class A Preferred Units and except for meetings of the holders of Class A Preferred Units as a class or meetings of the holders of a series thereof, the holders of Class A Preferred Units are not entitled to receive notice of, attend, or vote at any meeting of holders of LP Units, unless and until BEP shall have failed to pay eight quarterly distributions in respect of such series of Class A Preferred Units, whether or not consecutive and whether or not such distributions have been declared and whether or not there are any monies of our partnership properly applicable to the payment of distributions. In the event of such non-payment, and for only so long as any such distributions remain in arrears, such holders will be entitled to receive notice of and to attend each meeting of holders of LP Units (other than any meetings at which only holders of another specified class or series are entitled to vote) and such holders shall have the right, at any such meeting, to one vote for each Preferred Unit held. Upon payment of the entire amount of all such distributions in arrears, the voting rights of such holders of Class A Preferred Units shall forthwith cease (unless and until the same default shall again arise as described herein).

Meetings

The Managing General Partner may call special meetings of partners at a time and place outside of Canada determined by the Managing General Partner on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. The limited partners do not have the ability to call a special meeting. Only holders of record on the date set by the Managing General Partner (which may not be less than 10 days nor more than 60 days, before the meeting) are entitled to notice of any meeting.

Written consents may be solicited only by or on behalf of the Managing General Partner. Any such consent solicitation may specify that any written consents must be returned to BEP within the time period, which may not be less than 20 days, specified by the Managing General Partner.

            For purposes of determining holders of partnership interests entitled to provide consents to any action described above, the Managing General Partner may set a record date, which may be not less than 10 nor more than 60 days before the date by which record holders are requested in writing by the Managing General Partner to provide such consents. Only those holders of partnership interests on the record date established by the Managing General Partner will be entitled to provide consents with respect to matters as to which a consent right applies.

Amendments to the Amended and Restated Limited Partnership Agreement of BEP

Amendments to the Amended and Restated Limited Partnership Agreement of BEP may only be proposed by or with the consent of the Managing General Partner. To adopt a proposed amendment, other than the amendments that do not require limited partner approval discussed below, the Managing General Partner must seek approval of at least 66^2/3% of the voting power of our outstanding LP Units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment.

Notwithstanding the above, in addition to any other approvals required by law, the approval of all amendments to the rights, privileges, restrictions and conditions attaching to the Class A Preferred Units as a class and any other approval to be given by the holders of the Class A Preferred Units may be given (i) by a resolution signed by the holders of Class A Preferred Units owning not less than the percentage of the Class A Preferred Units that would be necessary to authorize such action at a meeting of the holders of the Class A Preferred Units at which all holders of the Class A Preferred Units were present and voted or were represented by proxy, or (ii) passed by an affirmative vote of at least 66^2/3% of the votes cast at a meeting of holders of the Class A Preferred Units duly called for that purpose and at which the holders of at least 25% of the outstanding Class A Preferred Units are present or represented by proxy or, if no quorum is present at such meeting, at an adjourned meeting at which the holders of Class A Preferred

Page 182

Units then present would form the necessary quorum. At any meeting of holders of Class A Preferred Units as a class, each such holder shall be entitled to one vote in respect of each Class A Preferred Unit held.

Further, in addition to any other approvals required by law, the approval of all amendments to the rights, privileges, restrictions and conditions attaching to each series of Class A Preferred Units, as a series, and any other approval to be given by the holders of each series of Class A Preferred Units, as a series, may be given (i) by a resolution signed by the holders of the applicable series of Class A Preferred Units owning not less than the percentage of such series of Class A Preferred Units that would be necessary to authorize such action at a meeting of the holders of the applicable series of Class A Preferred Units at which all holders of the applicable series of Class A Preferred Units were present and voted or were represented by proxy, or (ii) passed by an affirmative vote of at least 66^2/3% of the votes cast at a meeting of holders of the applicable series of Class A Preferred Units duly called for that purpose and at which the holders of at least 25% of the outstanding applicable series of Class A Preferred Units are present or represented by proxy or, if no quorum is present at such meeting, at an adjourned meeting at which the holders of the applicable series of Class A Preferred Units then present would form the necessary quorum. At any meeting of holders of a series of Class A Preferred Units, as a series, each such holder shall be entitled to one vote in respect of each applicable Class A Preferred Unit held.

Prohibited Amendments

No amendment may be made to the Amended and Restated Limited Partnership Agreement of BEP that would: 

(i)enlarge the obligations of any limited partner without its consent, except that any amendment that would have a material adverse effect on the rights or preferences of any class of partnership interests in relation to other classes of partnership interests may be approved by at least a majority of the type or class of partnership interests so affected; or

(ii)enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by BEP to the Managing General Partner or any of its affiliates without the consent of the Managing General Partner, which may be given or withheld in its sole discretion.

The provision of the Amended and Restated Limited Partnership Agreement of BEP preventing the amendments having the effects described directly above can be amended upon the approval of the holders of at least 90% of the outstanding LP Units, and in the case of (ii) above, with the consent of the Managing General Partner, which may be given or withheld in its sole discretion.

No Limited Partner Approval

Subject to applicable law, the Managing General Partner may generally make amendments to the Amended and Restated Limited Partnership Agreement of BEP without the approval of any limited partner to reflect:

·a change in the name of BEP, the location of BEP’s registered office, or BEP’s registered agent;

·the admission, substitution or withdrawal of partners in accordance with the Amended and Restated Limited Partnership Agreement of BEP;

·a change that the Managing General Partner determines is reasonable and necessary or appropriate for BEP to qualify or to continue BEP’s qualification as an exempted limited partnership under the laws of Bermuda or a partnership in which the limited partners have limited liability under the laws of any jurisdiction or is necessary or advisable in the opinion of the Managing General Partner to ensure that BEP will not be treated as an association taxable as a corporation or otherwise taxed as an entity for tax purposes;

·an amendment that the Managing General Partner determines to be necessary or appropriate to address certain changes in tax regulations, legislation or interpretation;

Page 183

·an amendment that is necessary, in the opinion of our counsel, to prevent BEP or the Managing General Partner or its directors or officers from in any manner being subjected to the provisions of the Investment Company Act or similar legislation in other jurisdictions;

·an amendment that the Managing General Partner determines in its sole discretion to be necessary or appropriate for the creation, authorization or issuance of any class or series of partnership interests or options, rights, warrants or appreciation rights relating to partnership securities;

·any amendment expressly permitted in the Amended and Restated Limited Partnership Agreement of BEP to be made by the Managing General Partner acting alone;

·any amendment that, in the sole discretion of the Managing General Partner, is necessary or appropriate to reflect and account for the formation by BEP of, or its investment in, any partnership, association, body corporate or other entity, as otherwise permitted by the Amended and Restated Limited Partnership Agreement of BEP;

·a change in BEP’s fiscal year and related changes; or

·any other amendments substantially similar to any of the matters described directly above.

In addition, the Managing General Partner may make amendments to the Amended and Restated Limited Partnership Agreement of BEP without the approval of any limited partner if those amendments, in the discretion of the Managing General Partner:

·do not adversely affect BEP’s limited partners considered as a whole (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;

·are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion or binding directive, order, ruling or regulation of any governmental agency or judicial authority;

·are necessary or appropriate to facilitate the trading of our LP Units or Preferred Units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which our LP Units or Preferred Units are or will be listed for trading;

·are necessary or appropriate for any action taken by the Managing General Partner relating to splits or combinations of LP Units or Preferred Units made in accordance with the provisions of the Amended and Restated Limited Partnership Agreement of BEP; or

·are required to effect the intent of the provisions of the Amended and Restated Limited Partnership Agreement of BEP or are otherwise contemplated by the Amended and Restated Limited Partnership Agreement of BEP.

Opinion of Counsel and Limited Partner Approval

The Managing General Partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners if one of the amendments described above under “— No Limited Partner Approval” should occur. No other amendments to the Amended and Restated Limited Partnership Agreement of BEP will become effective without the approval of holders of at least 90% of our LP Units, unless BEP obtains an opinion of counsel to the effect that the amendment will not cause BEP to be treated as an association taxable as a corporation or otherwise taxable as an entity for tax purposes (provided that for U.S. tax purposes the Managing General Partner has not made the election described below under “— Election to be Treated as a Corporation”) or affect the limited liability under the Limited Partnership Act 1883 of any of BEP’s limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will also require the approval of the holders of at least a majority of the outstanding partnership interests of the class so affected.

In addition, any amendment that reduces the voting percentage required to take any action must be approved by the written consent or affirmative vote of limited partners whose aggregate outstanding voting units constitute not less than the voting requirement sought to be reduced.

Sale or Other Disposition of Assets

Page 184

The Amended and Restated Limited Partnership Agreement of BEP generally prohibits the Managing General Partner, without the prior approval of the holders of at least 66^2/3% of the voting power of our LP Units, from causing BEP to, among other things, sell, exchange or otherwise dispose of all or substantially all of BEP’s assets in a single transaction or a series of related transactions, including by approving on BEP’s behalf the sale, exchange or other disposition of all or substantially all of the assets of BEP’s subsidiaries. However, the Managing General Partner, in its sole discretion, may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of BEP’s assets (including for the benefit of persons who are not BEP or BEP’s subsidiaries) without that approval. The Managing General Partner may also sell all or substantially all of BEP’s assets under any forced sale of any or all of BEP’s assets pursuant to the foreclosure or other realization upon those encumbrances without that approval.

Take-Over Bids

If, within 120 days after the date of a take-over bid, as defined in the Securities Act (Ontario), the take-over bid is accepted by holders of not less than 90% of our outstanding LP Units, other than our LP Units held at the date of the take-over bid by the offeror or any affiliate or associate of the offeror, and the offeror acquires all of such LP Units deposited or tendered under the take-over bid, the offeror will be entitled to acquire our LP Units not deposited under the take-over bid on the same terms as our LP Units acquired under the take-over bid.

Election to be Treated as a Corporation

If the Managing General Partner determines in its sole discretion that it is no longer in BEP’s best interests to continue as a partnership for U.S. federal income tax purposes, the Managing General Partner may elect to treat BEP as an association or as a publicly traded partnership taxable as a corporation for U.S. federal (and applicable state) income tax purposes.

Termination and Dissolution

BEP will terminate upon the earlier to occur of (i) the date on which all of BEP’s assets have been disposed of or otherwise realized by BEP and the proceeds of such disposals or realizations have been distributed to partners, (ii) the service of notice by the Managing General Partner, with the special approval of a majority of its independent directors, that in its opinion the coming into force of any law, regulation or binding authority has or will render illegal or impracticable the continuation of BEP, or (iii) at the election of the Managing General Partner, with the special approval of its independent directors, if BEP, as determined by the Managing General Partner, based on an opinion of counsel, is required to register as an “investment company” under the Investment Company Act or similar legislation in other jurisdictions.

BEP will be dissolved upon the withdrawal of the Managing General Partner as the general partner of BEP (unless a successor entity becomes the general partner as described in the following sentence or the withdrawal is effected in compliance with the provisions of the Amended and Restated Limited Partnership Agreement of BEP that are described below under “— Withdrawal of the Managing General Partner”) or the entry by a court of competent jurisdiction of a decree of judicial dissolution of BEP or an order to wind-up or liquidate the Managing General Partner without the appointment of a successor in compliance with the provisions of the Amended and Restated Limited Partnership Agreement of BEP that are described below under “— Withdrawal of the Managing General Partner”. BEP will be reconstituted and continue without dissolution if within 30 days of the date of dissolution (and so long as a notice of dissolution has not been filed with the Bermuda Monetary Authority), a successor general partner executes a transfer deed pursuant to which it becomes the general partner and assumes the rights and undertakes the obligations of the general partner and BEP receives an opinion of counsel that the admission of the new general partner will not result in the loss of the limited liability of any limited partner.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless BEP is continued as a new limited partnership, the liquidator authorized to wind-up BEP’s affairs will, acting with all of the powers of the Managing General Partner that the liquidator deems necessary or appropriate in its judgment, liquidate BEP’s assets and apply the proceeds of the liquidation first, to discharge BEP’s liabilities as provided in the Amended and Restated

Page 185

Limited Partnership Agreement of BEP and by law, second to the holders of any Class A Preferred Units in accordance with the terms of such Class A Preferred Units and thereafter to the partners holding LP Units pro rata according to the percentages of their respective partnership interests as of a record date selected by the liquidator. The liquidator may defer liquidation of BEP’s assets for a reasonable period of time or distribute assets to partners in kind if it determines that an immediate sale or distribution of all or some of BEP’s assets would be impractical or would cause undue loss to the partners.

Withdrawal of the Managing General Partner

The Managing General Partner may withdraw as Managing General Partner without first obtaining approval of our LP Unitholders and Preferred Unitholders by giving 180 days’ advance written notice to the other partners, and that withdrawal will not constitute a violation of the Amended and Restated Limited Partnership Agreement of BEP.

Upon the withdrawal of the Managing General Partner, the holders of at least 66^2/3% of the voting power of our outstanding LP Units may select a successor to the withdrawing Managing General Partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability, tax matters and the Investment Company Act (and similar legislation in other jurisdictions) cannot be obtained, BEP will be dissolved, wound up and liquidated. See “— Termination and Dissolution” above.

            In the event of withdrawal of a general partner where that withdrawal violates the Amended and Restated Limited Partnership Agreement of BEP, a successor general partner will have the option to purchase the general partnership interest of the departing general partner for a cash payment equal to its fair market value. Under all other circumstances where a general partner withdraws, the departing general partner will have the option to require the successor general partner to purchase the general partnership interest of the departing general partner for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached within 30 days of the general partner’s departure, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing general partner and the successor general partner cannot agree upon an expert within 45 days of the general partner’s departure, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partnership interests will automatically convert into LP Units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

Transfer of the General Partnership Interest

The Managing General Partner may transfer all or any part of its general partnership interest without first obtaining approval of any LP Unitholder or Preferred Unitholder. As a condition of this transfer, the transferee must (i) be an affiliate of the general partner of BRELP (or the transfer must be made concurrently with a transfer of the general partnership units of BRELP to an affiliate of the transferee), (ii) agree to assume the rights and duties of the Managing General Partner to whose interest that transferee has succeeded, (iii) agree to be bound by the provisions of the Amended and Restated Limited Partnership Agreement of BEP and (iv) furnish an opinion of counsel regarding limited liability and tax matters. Any transfer of the general partnership interest is subject to prior notice to and approval of the relevant Bermuda regulatory authorities. At any time, the shareholder of the Managing General Partner may sell or transfer all or part of its shares in the Managing General Partner without the approval of the LP Unitholders or Preferred Unitholders.

Partnership Name

If the Managing General Partner ceases to be the general partner of BEP and our new general partner is not an affiliate of Brookfield, BEP will be required by the Amended and Restated Limited Partnership Agreement of BEP to change the name of BEP to a name that does not include “Brookfield” and which could not be capable of confusion in any way with such name. The Amended and Restated Limited Partnership Agreement of BEP explicitly provides that this obligation shall be enforceable and

Page 186

may be waived by the Managing General Partner notwithstanding that it may have ceased to be the general partner of BEP.

Transactions with Interested Parties

The Managing General Partner, the Service Provider and their respective partners, members, shareholders, directors, officers, employees and shareholders, which we refer to in the BEP Amended and Restated Limited Partnership Agreement as “interested parties”, may become limited partners or beneficially interested in limited partners and may hold, dispose of or otherwise deal with our LP Units or Preferred Units with the same rights they would have if the Managing General Partner was not a party to the Amended and Restated Limited Partnership Agreement of BEP. An interested party will not be liable to account either to other interested parties or to BEP, BEP’s partners or any other persons for any profits or benefits made or derived by or in connection with any such transaction.

The Amended and Restated Limited Partnership Agreement of BEP permits an interested party to sell investments to, purchase assets from, vest assets in and enter into any contract, arrangement or transaction with BEP, BRELP, any of the Holding Entities, any operating entity or any other holding vehicle established by BEP and may be interested in any such contract, transaction or arrangement and shall not be liable to account either to BEP, BRELP, any of the Holding Entities, any operating entity or any other holding vehicle established by BEP or any other person in respect of any such contract, transaction or arrangement, or any benefits or profits made or derived therefrom, by virtue only of the relationship between the parties concerned, subject to any approval requirements that are contained in the Conflicts Policy. See Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Outside Activities of the Managing General Partner; Conflicts of Interest

Under the Amended and Restated Limited Partnership Agreement of BEP, the Managing General Partner is required to maintain as its sole activity the role of general partner of BEP. The Managing General Partner is not permitted to engage in any business or activity or incur or guarantee any debts or liabilities except in connection with or incidental to its performance as general partner or incurring, guaranteeing, acquiring, owning or disposing of debt or equity securities of BRELP, a Holding Entity or any other holding vehicle established by BEP.

            The Amended and Restated Limited Partnership Agreement of BEP provides that each person who is entitled to be indemnified by BEP (other than the Managing General Partner), as described below under “— Indemnification; Limitations on Liability”, shall have the right to engage in businesses of every type and description and other activities for profit, and to engage in and possess interests in business ventures of any and every type or description, irrespective of whether (i) such activities are similar to our affairs or activities or (ii) such affairs and activities directly compete with, or disfavor or exclude, the Managing General Partner, BEP, BRELP, any Holding Entity, any operating entity or any other holding vehicle established by BEP. Such business interests, activities and engagements will be deemed not to constitute a breach of the Amended and Restated Limited Partnership Agreement of BEP or any duties stated or implied by law or equity, including fiduciary duties, owed to any of the Managing General Partner, BEP, BRELP, any Holding Entity, any operating entity and any other holding vehicle established by BEP (or any of their respective investors), and shall be deemed not to be a breach of the Managing General Partner’s fiduciary duties or any other obligation of any type whatsoever of the Managing General Partner. None of the Managing General Partner, BEP, BRELP, any Holding Entity, any operating entity, any other holding vehicle established by BEP or any other person shall have any rights by virtue of the Amended and Restated Limited Partnership Agreement of BEP or the partnership relationship established thereby or otherwise in any business ventures of any person who is entitled to be indemnified by BEP as described below under “— Indemnification; Limitations on Liability”.

The Managing General Partner and the other indemnified persons described in the preceding paragraph do not have any obligation under the Amended and Restated Limited Partnership Agreement of BEP to present business or investment opportunities to Brookfield Renewable. These provisions will not, however, affect any obligation of an indemnified person to present business or investment opportunities to Brookfield Renewable pursuant to the Relationship Agreement or any other separate written agreement between such persons.

Page 187

Any conflicts of interest and potential conflicts of interest that are approved by a majority of the Managing General Partner’s independent directors from time-to-time will be deemed approved by all partners. Pursuant to the Conflicts Policy, independent directors may grant approvals for any matters that may give rise to a conflict of interest or potential conflict of interest in the form of general guidelines, policies or procedures that are adopted by the Managing General Partner’s independent directors, and amended from time-to-time with the approval of a majority of the independent directors of the Managing General Partner, in which case no further special approval will be required in connection with a particular transaction or matter permitted thereby other than any approvals required by law. See Item 7.B “Related Party Transactions — Conflicts of Interest and Fiduciary Duties”.

Indemnification; Limitations on Liability

Under the Amended and Restated Limited Partnership Agreement of BEP, BEP is required to indemnify on an after-tax basis out of the assets of BEP to the fullest extent permitted by law the Managing General Partner, the Service Provider and any of their respective affiliates (and their respective officers, directors, agents, shareholders, partners, members and employees), any person who serves on a Governing Body of BEP, BRELP, a Holding Entity, Operating Entity or any other holding vehicle established by BEP and any other person designated by the Managing General Partner as an indemnified person, in each case, against all losses, claims, damages, liabilities, costs or expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, incurred by an indemnified person in connection with our investments and activities or by reason of their holding such positions, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the indemnified person’s gross negligence, bad faith, fraud or willful misconduct, or in the case of a criminal matter, action that the indemnified person knew to have been unlawful. In addition, under the Amended and Restated Limited Partnership Agreement of BEP, (i) no such person shall be liable to BEP, the Managing General Partner or any LP Unitholder or Preferred Unitholder for any liabilities sustained or incurred as a result of any act or omission of such person, except to the extent there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such liabilities resulted from such person’s gross negligence, bad faith, fraud, willful misconduct, or in the case of a criminal matter, actions with knowledge that the conduct was unlawful and (ii) subject to applicable law, any matter that is approved by the independent directors of the Managing General Partner will not constitute a breach of the Amended and Restated Limited Partnership Agreement of BEP or any duties stated or implied by law or equity, including fiduciary duties. The Amended and Restated Limited Partnership Agreement of BEP requires us to advance funds to pay the expenses of an indemnified person in connection with a matter in which indemnification may be sought until it is determined that the indemnified person is not entitled to indemnification.

Accounts, Reports and Other Information

Under the Amended and Restated Limited Partnership Agreement of BEP, the Managing General Partner is required to prepare financial statements in accordance with IFRS as determined by the IASB. BEP’s financial statements must be made publicly available together with a statement of the accounting policies used in their preparation, such information as may be required by applicable laws and regulations and such information as the Managing General Partner deems appropriate. BEP’s annual financial statements must be audited by an independent accounting firm of international standing and made publicly available within such period of time as is required to comply with applicable laws and regulations, including any rules of any applicable securities exchange. BEP’s quarterly financial statements may be unaudited and are made available publicly as and within the time period required by applicable laws and regulations, including any rules of any applicable securities exchange. The Managing General Partner is also required to prepare all other press releases, proxy circulars and other disclosure documentation as by be required by applicable laws, including any rules of any applicable securities exchange.

The Managing General Partner is also required to use commercially reasonable efforts to prepare and send to the limited partners of BEP on an annual basis, additional information regarding BEP, including Schedule K-1 (or equivalent) and information related to the passive foreign investment company status of certain non-U.S. corporations that we control. The Managing General Partner will, where reasonably possible, prepare and send information required by the non-U.S. limited partners of BEP for

Page 188

U.S. federal income tax reporting purposes. The Managing General Partner will also, where reasonably possible and applicable, prepare and send information required by limited partners of BEP for Canadian federal income tax purposes.

Governing Law; Submission to Jurisdiction

The Amended and Restated Limited Partnership Agreement of BEP is governed by and will be construed in accordance with the laws of Bermuda. Under the Amended and Restated Limited Partnership Agreement of BEP, each of BEP’s partners (other than governmental entities prohibited from submitting to the jurisdiction of a particular jurisdiction) will submit to the non-exclusive jurisdiction of any court in Bermuda in any dispute, suit, action or proceeding arising out of or relating to the Amended and Restated Limited Partnership Agreement of BEP. Each partner waives, to the fullest extent permitted by law, any immunity from jurisdiction of any such court or from any legal process of any such court and further waives, to the fullest extent permitted by law, any claim of inconvenient forum, improper venue or that any such court does not have jurisdiction over the partner. Any final judgment against a partner in any proceedings brought in a court in Bermuda will be conclusive and binding upon the partner and may be enforced in the courts of any other jurisdiction of which the partner is or may be subject, by suit upon such judgment. The foregoing submission to jurisdiction and waivers will survive the dissolution, liquidation, winding up and termination of BEP.

Preferred Unit Guarantees

The Preferred Unit Guarantees provide that each series of Class A Preferred Units will be fully and unconditionally guaranteed by the Preferred Unit Guarantors as to (i) payment of dividends, as and when declared, (ii) payment of amounts due on redemption of the applicable series of Class A Preferred Units, and (iii) payment of amounts due on the liquidation, dissolution or winding up of BEP. For so long as the Preferred Unit Guarantees are in place, they will be subordinated to all of the senior and subordinated debt of the Preferred Unit Guarantors that is not expressly stated to be pari passu or subordinate to the Preferred Unit Guarantees, and will rank senior to the common equity of the Preferred Unit Guarantors. The Preferred Unit Guarantees will rank on a pro rata and pari passu basis with each other. The rights, obligations and liabilities of a Preferred Unit Guarantor pursuant to the Preferred Unit Guarantees will terminate upon the conveyance, distribution, transfer or lease of all or substantially all of its properties, securities and assets to another Preferred Unit Guarantor. A Preferred Unit Guarantor may not otherwise convey, distribute, transfer or lease all or substantially all of its properties, securities and assets to another person, unless the person which acquires the properties, securities and assets of such Preferred Unit Guarantor assumes such Preferred Unit Guarantor’s obligations under the Preferred Unit Guarantees. The Preferred Unit Guarantees were granted by the Preferred Unit Guarantors so that the Preferred Units rank pari passu at the Preferred Unit Guarantor level with the outstanding Preference Shares issued by BRP Equity, which are also guaranteed by the Preferred Unit Guarantors. Provided no default then exists in respect of the applicable Preferred Unit Guarantee, at any time following the termination of its guarantee of the Preferred Shares, each Preferred Unit Guarantor shall be entitled to a full, unconditional and final release of its obligations under its applicable Preferred Unit Guarantee. Should this occur in respect of all the Preferred Unit Guarantors, the Class A Preferred Units will then constitute obligations of BEP alone.

Description of the Amended and Restated Limited Partnership Agreement of BRELP

The following is a description of the material terms of the Amended and Restated Limited Partnership Agreement of BRELP. Holders of LP Units in BEP are not limited partners of BRELP and do not have any rights under the Amended and Restated Limited Partnership Agreement of BRELP. Pursuant to the Voting Agreement, however, BEP, through the Managing General Partner, has the right to direct all eligible votes in the election of the directors of the BRELP General Partner, through which BEP participates in the management and activities of BRELP and the Holding Entities. See Item 7.B “Related Party Transactions—Voting Agreements”.

Because this description is only a summary of the terms of the agreement, it does not necessarily contain all of the information that you may find useful. For more complete information, you should read the Amended and Restated Limited Partnership Agreement of BRELP which is available electronically on our EDGAR profile at www.sec.gov and on our SEDAR profile at www.sedar.com and will be made

Page 189

available to LP Unitholders and Preferred Unitholders as described under Item 10.C “Material Contracts” and Item 10.H “Documents on Display”.

Formation and Duration

BRELP is a Bermuda exempted limited partnership registered under the Limited Partnership Act 1883 and the Exempted Partnerships Act1992  . BRELP has a perpetual existence and will continue as a limited liability partnership unless BEP is terminated or dissolved in accordance with the Amended and Restated Limited Partnership Agreement of BRELP.

Nature and Purpose

Under the Amended and Restated Limited Partnership Agreement of BRELP, the purpose of BRELP is to: acquire and hold interests in the Holding Entities and, subject to the approval of the BRELP GP LP, any other subsidiary of BRELP; engage in any activity related to the capitalization and financing of BRELP’s interests in such entities; and engage in any other activity that is incidental to or in furtherance of the foregoing and that is approved by the BRELP GP LP and that lawfully may be conducted by a limited partnership organized under the Limited Partnership Act1883, the Exempted Partnerships Act 1992 and the Amended and Restated Limited Partnership Agreement of BRELP.

Management

As required by law, the Amended and Restated Limited Partnership Agreement of BRELP provides for the management and control of BRELP by a general partner, the BRELP GP LP. The BRELP GP LP will exercise its powers and carry out its functions honestly and in good faith and the BRELP GP LP will exercise the degree of care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances, in each case, subject to, and after taking into account, the terms and conditions of the Relationship Agreement, our Master Services Agreement and the Conflicts Policy. Except as set out in the Amended and Restated Limited Partnership Agreement of BRELP, the BRELP GP LP has no additional duty to propose or approve any conduct of BRELP, and may decline to propose or approve such conduct free of any additional duty (including fiduciary duty). The BRELP GP LP shall not be in breach of any duty to BRELP if it takes actions permitted by the Amended and Restated Limited Partnership Agreement of BRELP, the Relationship Agreement, our Master Services Agreement or the Conflicts Policy.

Units

BRELP’s units are limited partnership interests. Holders of units of BRELP are not entitled to the withdrawal or return of capital contributions in respect of their units, except to the extent, if any, that distributions are made to such holders pursuant to the Amended and Restated Limited Partnership Agreement of BRELP or upon the dissolution of BRELP or as otherwise required by applicable law. Except to the extent expressly provided in the Amended and Restated Limited Partnership Agreement of BRELP, as amended from time to time, and except pursuant to the terms of any BRELP Class A Preferred Units outstanding, a holder of units of BRELP does not have priority over any other holder of units, either as to the return of capital contributions or as to profits, losses or distributions. The BRELP Class A Preferred Units rank senior to the other BRELP units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BRELP, whether voluntary or involuntary. Each series of BRELP Class A Preferred Units ranks on a parity with every other series of BRELP Class A Preferred Units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BRELP, whether voluntary or involuntary.

Upon its formation, BRELP issued two classes of units. The first class of units was issued to Brookfield and subsequently transferred to BEP and the second class of units, referred to as the Redeemable/Exchangeable partnership units, were issued to wholly-owned subsidiaries of Brookfield. Redeemable/Exchangeable partnership units are identical to the limited partnership units held by BEP, except as described below under “— Distributions” and “— Withdrawal of the General Partner” and except that they have the right of redemption described below under the heading “— Redemption-Exchange Mechanism”.

Page 190

On November 25, 2015 the Amended and Restated Limited Partnership Agreement of BEP was amended to permit the authorization and issuance of Preferred Units and authorize and create the Class A Preferred Units, the Series 7 Preferred Units and the Series 8 Preferred Units. On the same date, BEP issued 7 million Series 7 Preferred Units and acquired 7 million BRELP Series 7 Preferred Units.

On February 11, 2016 the Amended and Restated Limited Partnership Agreement of BEP was amended to authorize and create the Series 5 Preferred Units. On the same date, BEP issued 2,885,496 million Series 5 Preferred Units and acquired 2,885,496 million BRELP Series 5 Preferred Units.

On May 25, 2016, the Amended and Restated Limited Partnership Agreement of BEP was amended to authorize and create the Series 9 Preferred Units and the Series 10 Preferred Units. On the same date, BEP issued 8 million Series 9 Preferred Units and acquired 8 million BRELP Series 9 Preferred Units.

On February 14, 2017, the Amended and Restated Limited Partnership Agreement of BEP was amended to authorize and create the Series 11 Preferred Units and the Series 12 Preferred Units. On the same date, BEP issued 10 million Series 11 Preferred Units and acquired 10 million BRELP Series 11 Preferred Units. 

On January 16, 2018, the Amended and Restated Limited Partnership Agreement of BEP was amended to authorize and create the Series 13 Preferred Units and the Series 14 Preferred Units. On the same date, BEP issued 10 million Series 13 Preferred Units and acquired 10 million BRELP Series 13 Preferred Units.

Issuance of Additional Partnership Interests

Subject to the rights of the holders of BRELP Class A Preferred Units to approve issuances of additional partnership interests ranking senior to the BRELP Class A Preferred Units with respect to priority in the payment of distributions and in the distribution of the assets in the event of the liquidation, dissolution or winding-up of BRELP, whether voluntary or involuntary, and subject to any approval required by applicable law, BRELP may issue additional partnership interests (including new classes of partnership interests and options, rights, warrants and appreciation rights relating to such interests) for any partnership purpose, at any time and from time to time and on such terms and conditions as its general partner may determine. Any additional partnership interests authorized to be issued by Amended and Restated Limited Partnership Agreement of BRELP may be issued in one or more classes, or one or more series of classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership interests) as its general partner may determine in its sole discretion.

Redemption-Exchange Mechanism

At any time, one or more wholly-owned subsidiaries of Brookfield that hold Redeemable/Exchangeable partnership units will have the right to require BRELP to redeem for cash all or a portion of the Redeemable/Exchangeable partnership units held by such subsidiary, subject to BEP’s right to acquire such Redeemable/Exchangeable partnership units, as described below, provided that exercise of the right of redemption or the payment of the redemption amount would not otherwise cause BRELP to be in breach or violation of any agreement material to BRELP or Brookfield Renewable or applicable law. Any such redeeming subsidiary may exercise its right of redemption by delivering a notice of redemption to BRELP and BEP. After presentation for redemption, such redeeming subsidiary will receive, subject to BEP’s right to acquire Redeemable/Exchangeable partnership units, as described below, for each such unit that is presented, cash in an amount equal to the market value of one of our LP Units multiplied by the number of Redeemable/Exchangeable partnership units to be redeemed (as determined by reference to the five day volume weighted average of the trading price of our LP Units and subject to certain customary adjustments). Upon its receipt of the redemption notice, BEP will have a right to acquire Redeemable/Exchangeable partnership units entitling it, at its sole discretion, to elect to acquire all (but not less than all) such units described in such notice and presented to BRELP for redemption in exchange for LP Units on a one for one basis (subject to certain customary adjustments). Upon a redemption for cash, the holder’s right to receive distributions with respect to BRELP’s Redeemable/Exchangeable partnership units so redeemed will cease.

Page 191

Brookfield’s aggregate interest in BEP, including its interest in the Managing General Partner and the BRELP GP LP, would be approximately 60% if it exercised its redemption right in full and BEP exercised its right of first refusal on BRELP’s Redeemable/Exchangeable partnership units redeemed. Brookfield’s total percentage interest in BEP would be increased if it participates in BRELP’s distribution reinvestment plan.

Distributions

Subject to the rights of holders of BRELP Class A Preferred Units to receive cumulative preferential cash distributions in accordance with the terms of a series of BRELP Class A Preferred Units, distributions by BRELP will be made in the sole discretion of its general partner, the BRELP GP LP. The holders of a series of BRELP Class A Preferred Units will be entitled to receive the same distribution as the holders of the corresponding series of BEP’s Class A Preferred Units, respectively. However, the BRELP GP LP will not be permitted to cause BRELP to make a distribution (i) if BRELP does not have sufficient cash on hand to make the distribution, (ii) if the distribution would render BRELP insolvent or (iii) if, in the opinion of the BRELP GP LP, the distribution would or might leave BRELP with insufficient funds to meet any future or contingent obligations or the distribution would contravene the Limited Partnership Act1883. 

Except as set forth below, prior to the dissolution of BRELP, distributions of available cash (if any) in any given quarter will be made by BRELP as follows, referred to as the “Regular Distribution Waterfall”: 

·first, 100% of any available cash to BEP until BRELP has distributed an amount equal to BEP’s expenses and outlays for the quarter properly incurred;

·second, 100% to the owners of the BRELP Preferred Units, in proportion to their respective relative percentage of BRELP Preferred Units held (determined by reference to the aggregate value of the issue price of the BRELP Preferred Units held by each holder relative to the aggregate value of the issue price of all BRELP Preferred Units then outstanding) until there has been distributed in respect of each BRELP Preferred Unit outstanding as of the last day of such quarter an amount equal to all preferential distributions to which the holders of BRELP Preferred Units are entitled under the terms of the BRELP Preferred Units then outstanding and any outstanding accrued and unpaid preferential distributions from prior periods;

·third, 100% of any available cash then remaining to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, until an amount equal to $0.375 has been distributed in respect of each limited partnership unit of BRELP, other than BRELP Preferred Units, during such quarter, referred to as the “First Distribution Threshold”; 

·fourth, 85% of any available cash then remaining to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, and 15% to its general partner, until an amount equal to $0.4225 has been distributed in respect of each limited partnership unit of BRELP, other than BRELP Preferred Units, during such quarter, referred to as the “Second Distribution Threshold”; and

·thereafter, 75% of any available cash then remaining to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, and 25% to its general partner.

Notwithstanding the foregoing, for any quarter in which the general partner of BRELP determines, in its sole discretion, that all or a portion of any distribution to holders of BRELP Preferred Units should not be paid until such later time as determined in accordance with the terms of such BRELP Preferred Units, the amount of such distribution (or portion thereof) to be paid at such later time shall be deducted from the available cash for the purposes of the Regular Waterfall Distribution and shall be distributed to such holders of BRELP Preferred Units at such later time.

Set forth below is an example of how the incentive distributions described above are calculated on a quarterly and annualized basis. The figures used below are for illustrative purposes only and are not indicative of BEP’s expectations.

Page 192

			Quarterly				Annually
(MILLIONS, EXCEPT PER UNIT AMOUNTS)		Units	Per Unit		Total		Per Unit		Total
Illustrative distribution			$	0.5000			$	2.00
First Distribution Threshold			$	0.3750			$	1.50
	Total units of BRELP (1)	265
	Total first distribution				$	99.4			$	397.6
Distribution in excess of First Distribution Threshold			$	0.0475			$	0.19
	Total units of BRELP (1)	265
	Second distribution to partners				$	12.6			$	50.4
	15% incentive distribution to general partner					2.2				8.8
	Total second distribution				$	14.8			$	59.2
Distribution in excess of Second Distribution Threshold			$	0.0775			$	0.31
	Total units of BRELP (1)	265
	Third distribution to partners				$	20.5			$	82
	25% incentive distribution to general partner					6.8				27.2
	Total third distribution				$	27.3			$	109.2
Total distributions to partners (including incentive distributions)					$	141.5			$	566
Total incentive distributions to general partner					$	9			$	36

⁽¹⁾Includes (a) class A non-voting limited partnership interests in BRELP held by Brookfield Renewable, (b) Redeemable/Exchangeable partnership units of BRELP that are held by Brookfield and that are redeemable for cash or exchangeable for LP Units in accordance with the Redemption-Exchange Mechanism and (c) general partnership interests in BRELP.

The table below sets forth all management fees and incentive distributions that have been earned for the year ended December 31:

(MILLIONS)	2015		2016		2017
Base management fee (1)	$	48.8	$	65.7	$	82.1
Incentive distribution		8.2		19.1		29.5
Total	$	57.0	$	84.8	$	111.6

(1)        Pursuant to our Master Services Agreement, we pay the Service Provider a fixed base management fee equal to $20 million, which amount is annually adjusted for inflation, with the first adjustment having been made on January 1, 2013, at an inflation factor based on year-over-year United States consumer price index) plus 1.25% of the amount by which the Total Capitalization Value exceeds an initial reference value determined based on its market capitalization immediately following combination of the assets of the Fund and Brookfield Power Renewable Assets into BEP. In the event that the measured Total Capitalization Value in a given period is less than the initial reference value, the Service Provider will receive only the Base Management Fee of $20 million annually (subject to an annual escalation by the specified inflation factor described above). The Base Management Fee is calculated and paid on a quarterly basis. For any quarter in which the Managing General Partner determines that there is insufficient available cash to pay the base management fee as well as the next regular distribution on our LP Units, we may elect to pay all or a portion of the base management fee in our LP Units or in limited partnership units of BRELP, subject to certain conditions. See Item 6.A. “Directors and Senior Management – Our Master Services Agreement – Management Fee”.

Page 193

Subject to the terms of any BRELP Preferred Units outstanding, if, prior to the dissolution of BRELP, available cash is deemed by its general partner, in its sole discretion, to be (i) attributable to sales or other dispositions of BRELP’s assets and (ii) representative of unrecovered capital, then such available cash shall be distributed to the partners of BRELP, other than holders of BRELP Preferred Units, in proportion to the unrecovered capital attributable to BRELP’s partnership interests held by such partners until such time as the unrecovered capital attributable to each such partnership interest is equal to zero. Thereafter, distributions of available cash made by BRELP (to the extent made prior to dissolution) will be made in accordance with the Regular Distribution Waterfall.

Upon the occurrence of an event resulting in the dissolution of BRELP, all cash and property of BRELP in excess of that required to discharge BRELP’s liabilities will be distributed as follows: (i) to the extent such cash and/or property is attributable to a realization event occurring prior to the event of dissolution, such cash and/or property will be distributed in accordance with the Regular Distribution Waterfall and/or the distribution waterfall applicable to unrecovered capital; and (ii) all other cash and/or property will be distributed in the manner set forth below: 

·first, 100% to BEP until BEP has received an amount equal to the excess of (i) the amount of BEP’s outlays and expenses incurred during the term of BRELP, over (ii) the aggregate amount of distributions received by BEP pursuant to the first tier of the Regular Distribution Waterfall during the term of BRELP;

·second, 100% to the BRELP Preferred Unitholders pro rata in proportion to their respective relative percentage of BRELP Preferred Units held (determined by reference to the aggregate value of the issue price of the BRELP Preferred Units held by each holder of BRELP Preferred Units relative to the aggregate value of the issue price of all BRELP Preferred Units then outstanding) until there has been distributed in respect of each BRELP Preferred Unit outstanding an amount equal to any preferential distributions to which the holder of BRELP Preferred Units are entitled in the event of dissolution, liquidation, or winding up of BRELP under the terms of the BRELP Preferred Units then outstanding (including any outstanding accrued and unpaid preferential distributions from prior periods);

·third, if there are BRELP Preferred Units outstanding, an amount equal to the amount of cash or property held by BRELP at such time, that is attributable to a realization event occurring prior to the date of a dissolution event and that has been deemed by the general partner of BRELP as capital surplus shall be distributed as though such amount has been deemed by the general partner of BRELP to be (i) attributable to sales or other dispositions of BRELP’s assets and (ii) representative of unrecovered capital;

·fourth, 100% to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, in proportion to their respective amounts of unrecovered capital in BRELP;

·fifth, 100% to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, until an amount has been distributed in respect of each limited partnership unit of BRELP, other than BRELP Preferred Units, equal to the excess of (i) the First Distribution Threshold for each quarter during the term of BRELP (subject to adjustment upon the subsequent issuance of additional partnership interests in BRELP), over (ii) the aggregate amount of distributions made in respect of a BRELP’s limited partnership unit, other than BRELP Preferred Units, pursuant to the fourth tier of the Regular Distribution Waterfall during the term of BRELP (subject to adjustment upon the subsequent issuance of additional partnership interests in BRELP);

·sixth, 85% to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, and 15% to its general partner, until an amount has been distributed in respect of each limited partnership unit of BRELP, other than BRELP Preferred Units, equal to the excess of (i) the Second Distribution Threshold less the First Distribution Threshold for each quarter during the term of BRELP (subject to adjustment upon the subsequent issuance of additional partnership interests in BRELP), over (ii) the aggregate amount of distributions made in respect of a limited partnership units of BRELP pursuant to the fourth tier of the Regular Distribution Waterfall during the term of BRELP (subject to adjustment upon the subsequent issuance of additional partnership interests in BRELP); and

Page 194

·thereafter, 75% to the owners of BRELP’s partnership interests, other than holders of BRELP Preferred Units, pro rata to their percentage interests, and 25% to its general partner.

Each partner’s percentage interest is determined by the relative portion of all outstanding partnership interests, other than any BRELP Preferred Units, held by that partner from time to time and is adjusted upon and reflects the issuance of additional partnership interests of BRELP. In addition, the unreturned capital attributable to each of the partnership interests, as well as certain of the distribution thresholds set forth above, may be adjusted pursuant to the terms of the Amended and Restated Limited Partnership Agreement of BRELP so as to ensure the uniformity of the economic rights and entitlements of (i) the previously outstanding partnership interests of BRELP, and (ii) the subsequently-issued partnership interests of BRELP.

The Amended and Restated Limited Partnership Agreement of BRELP provides that, to the extent that any Holding Entity or any operating entity pays to Brookfield any comparable performance or incentive distribution, the amount of any incentive distributions paid to the BRELP GP LP in accordance with the distribution entitlements described above will be reduced in an equitable manner to avoid duplication of distributions.

BRELP GP LP may elect, at its sole discretion, to reinvest incentive distributions in Redeemable/Exchangeable partnership units.

Sale or Other Disposition of Assets

The Amended and Restated Limited Partnership Agreement of BRELP generally prohibits the general partner of BRELP, without the prior approval of the holders of at least 50% of the voting power of the units of BRELP, other than BRELP Preferred Units, from causing BRELP to, among other things, sell, exchange or otherwise dispose of all or substantially all of BRELP or Brookfield Renewable’s assets in a single transaction or a series of related transactions.

No Management or Control

BRELP’s limited partners, in their capacities as such, may not take part in the management or control of the activities and affairs of BRELP and do not have any right or authority to act for or to bind BRELP or to take part or interfere in the conduct or management of BRELP.

Limited partners are not entitled to vote on matters relating to BRELP, although holders of units are entitled to consent to certain matters as described under “— Amendment of the Amended and Restated Limited Partnership Agreement of BRELP”, “— Opinion of Counsel and Limited Partner Approval” and “— Withdrawal of the General Partner” which may be effected only with the consent of the holders of the percentages of outstanding units specified below. Each unit shall entitle the holder thereof to one vote for the purposes of any approvals of holders of units. Except as otherwise provided by law or as set out in the provisions attached to any series of BRELP Class A Preferred Units and except for meetings of the holders of BRELP Class A Preferred Units as a class or meetings of the holders of a series thereof, the holders of a series of BRELP Class A Preferred Units are not entitled to receive notice of, attend, or vote at any meeting of holders of units.

In addition, pursuant to the Voting Agreement, BEP, through the Managing General Partner, has a number of voting rights, including the right to direct all eligible votes in the election of the directors of the BRELP General Partner. See Item 7.B “Related Party Transactions — Voting Agreement”.

Meetings

Special meetings of the limited partners of BRELP may be called by its general partner at a time and place outside of Canada determined by it on a date not less than 10 days nor more than 60 days after the mailing of notice of the meeting. Special meetings of the limited partners may also be called by limited partners holding 50% or more of the voting power of the outstanding partnership interests of the class or classes for which a meeting is proposed. For this purpose, the partnership interests outstanding do not include partnership interests owned by its general partner or any of its affiliates other than any member of Brookfield Renewable. Only holders of partnership interests of BRELP of record on the date set by its general partner (which may not be less than 10 days nor more than 60 days, before the meeting) are entitled to notice of any meeting.

Page 195

Amendment of the Amended and Restated Limited Partnership Agreement of BRELP

Amendments to the Amended and Restated Limited Partnership Agreement of BRELP may only be proposed by or with the consent of its general partner. To adopt a proposed amendment, other than the amendments that do not require limited partner approval discussed below, the general partner must seek approval of at least 66^2/3% of the voting power of BRELP’s outstanding units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Notwithstanding the above, in addition to any other approvals required by law, the approval of all amendments to the rights, privileges, restrictions and conditions attaching to the BRELP Class A Preferred Units as a class and any other approval to be given (i) by the holders of the BRELP Class A Preferred Units may be given by a resolution signed by the holders of BRELP Class A Preferred Units owning not less than the percentage of the BRELP Class A Preferred Units that would be necessary to authorize such action at a meeting of the holders of the BRELP Class A Preferred Units at which all holders of the BRELP Class A Preferred Units were present and voted or were represented by proxy, or (ii) passed by an affirmative vote of at least 66^2/3% of the votes cast at a meeting of holders of the BRELP Class A Preferred Units duly called for that purpose and at which the holders of at least 25% of the outstanding BRELP Class A Preferred Units are present or represented by proxy or, if no quorum is present at such meeting, at an adjourned meeting at which the holders of BRELP Class A Preferred Units then present would form the necessary quorum. At any meeting of holders of BRELP Class A Preferred Units as a class, each such holder shall be entitled to one vote in respect of each BRELP Class A Preferred Unit held.

Further, in addition to any other approvals required by law, the approval of all amendments to the rights, privileges, restrictions and conditions attaching to each series of BRELP Class A Preferred Units, as a series, and any other approval to be given by the holders of each series of BRELP Class A Preferred Units, as a series, may be given (i) by a resolution signed by the holders of the applicable series of BRELP Class A Preferred Units owning not less than the percentage of such series of BRELP Class A Preferred Units that would be necessary to authorize such action at a meeting of the holders of the applicable series of BRELP Class A Preferred Units at which all holders of the applicable series of BRELP Class A Preferred Units were present and voted or were represented by proxy, or (ii) passed by an affirmative vote of at least 66^2/3% of the votes cast at a meeting of holders of the applicable series of BRELP Class A Preferred Units duly called for that purpose and at which the holders of at least 25% of the outstanding applicable series of BRELP Class A Preferred Units are present or represented by proxy or, if no quorum is present at such meeting, at an adjourned meeting at which the holders of the applicable series of BRELP Class A Preferred Units then present would form the necessary quorum. At any meeting of holders of a series of BRELP Class A Preferred Units, as a series, each such holder shall be entitled to one vote in respect of each applicable BRELP Class A Preferred Unit held.

Prohibited Amendments

No amendment may be made to the Amended and Restated Limited Partnership Agreement of BRELP that would: 

(i)enlarge the obligations of any limited partner without its consent, except that any amendment that would have a material adverse effect on the rights or preferences of any class of partnership interests in relation to other classes of partnership interests may be approved by at least a majority of the type or class of partnership interests so affected; or

(ii)enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by BRELP to the BRELP GP LP or any of its affiliates without the consent of the BRELP GP LP which may be given or withheld in its sole discretion.

The provision of the Amended and Restated Limited Partnership Agreement of BRELP preventing the amendments having the effects described directly above can be amended upon the approval of the holders of not less than 90% of the outstanding units.

No Limited Partner Approval

Page 196

Subject to applicable law, the BRELP GP LP may generally make amendments to the Amended and Restated Limited Partnership Agreement of BRELP without the approval of any limited partner to reflect: 

·a change in the name of BRELP, the location of BRELP’s registered office or BRELP’s registered agent;

·the admission, substitution or withdrawal or removal of partners in accordance with the Amended and Restated Limited Partnership Agreement of BRELP;

·a change that its general partner determines is reasonable and necessary or appropriate for BRELP to qualify or to continue its qualification as an exempted limited partnership under the laws of Bermuda or a partnership in which the limited partners have limited liability under the laws of any jurisdiction or is necessary or advisable in the opinion of its general partner to ensure that BRELP will not be treated as an association taxable as a corporation or otherwise taxed as an entity for tax purposes;

·an amendment that the BRELP GP LP determines to be necessary or appropriate to address certain changes in tax regulations, legislation or interpretation;

·an amendment that is necessary, in the opinion of counsel, to prevent BRELP or its general partner or its directors, officers, agents or trustees, from having a material risk of being in any manner subjected to the provisions of the Investment Company Act or similar legislation in other jurisdictions;

·an amendment that its general partner determines in its sole discretion to be necessary or appropriate for the creation, authorization or issuance of any class or series of partnership interests or options, rights, warrants or appreciation rights relating to partnership securities;

·any amendment expressly permitted in the Amended and Restated Limited Partnership Agreement of BRELP to be made by its general partner acting alone;

·any amendment that in the sole discretion of the BRELP GP LP is necessary or appropriate to reflect and account for the formation by BRELP of, or its investment in, any person, as otherwise permitted by the Amended and Restated Limited Partnership Agreement of BRELP;

·a change in its fiscal year and related changes;

·any amendment concerning the computation or allocation of specific items of income, gain, expense or loss among the partners that, in the sole discretion of its general partner, is necessary or appropriate to (i) comply with the requirements of applicable law, (ii) reflect the partners’ interests in BRELP, or (iii) consistently reflect the distributions made by BRELP to the partners pursuant to the terms of the Amended and Restated Limited Partnership Agreement of BRELP;

·any amendment that in the sole discretion of the BRELP GP LP is necessary or appropriate to address any statute, rule, regulation, notice, or announcement that affects or could affect the U.S. federal income tax treatment of any allocation or distribution related to any interest of the BRELP GP LP in the profits of BRELP; and

·any other amendments substantially similar to any of the matters described directly above.

In addition, amendments to the Amended and Restated Limited Partnership Agreement of BRELP may be made by the BRELP GP LP without the approval of any limited partner if those amendments, in the discretion of the BRELP GP LP: 

·do not adversely affect BRELP’s limited partners considered as a whole (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;

·are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion or binding directive, order, ruling or regulation of any governmental agency or judicial authority;

·are necessary or appropriate for any action taken by its general partner relating to splits or combinations of units made in accordance with the provisions of the Amended and Restated Limited Partnership Agreement of BRELP; or

Page 197

·are required to effect the intent of the provisions of the Amended and Restated Limited Partnership Agreement of BRELP or are otherwise contemplated by the Amended and Restated Limited Partnership Agreement of BRELP.

Opinion of Counsel and Limited Partner Approval

The BRELP GP LP will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners if one of the amendments described above under “— No Limited Partner Approval” should occur. No other amendments to the Amended and Restated Limited Partnership Agreement of BRELP will become effective without the approval of holders of at least 90% of the voting power of BRELP’s units, unless it obtains an opinion of counsel to the effect that the amendment will not (i) cause BRELP to be treated as an association taxable as a corporation or otherwise taxable as an entity for tax purposes (provided that for U.S. tax purposes its general partner has not made the election described below under “— Election to be Treated as a Corporation”) or (ii) affect the limited liability under the Limited Partnership Act 1883 of any of BRELP’s limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will also require the approval of the holders of at least a majority of the outstanding partnership interests of the class so affected.

In addition, any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding voting units constitute not less than the voting requirement sought to be reduced.

Election to be Treated as a Corporation

If, in the determination of its general partner, it is no longer in BRELP’s best interests to continue as a partnership for U.S. federal income tax purposes, the BRELP GP LP may elect to treat BRELP as an association or as a publicly traded partnership taxable as a corporation for U.S. federal (and applicable state) income tax purposes.

Dissolution

BRELP shall dissolve and its affairs shall be wound up, upon the earlier of (i) the service of notice by its general partner, with the approval of a majority of the members of the independent directors of the Managing General Partner, that, in the opinion of the general partner, the coming into force of any law, regulation or binding authority renders illegal or impracticable the continuation of BRELP; (ii) the election of its general partner, with the approval of its independent directors, if BRELP, as determined by its general partner, based on an opinion of counsel, is required to register as an “investment company” under the Investment Company Act or similar legislation in other jurisdictions; (iii) the date that its general partner withdraws from the partnership (unless a successor entity becomes the general partner of BRELP as described below under “— Withdrawal of the General Partner”); (iv) the date on which any court of competent jurisdiction enters a decree of judicial dissolution of BRELP or an order to wind-up or liquidate its general partner without the appointment of a successor in compliance with the provisions of the Amended and Restated Limited Partnership Agreement of BRELP that are described below under “— Withdrawal of the General Partner”; and (v) the date on which its general partner decides to dispose of, or otherwise realize proceeds in respect of, all or substantially all of BRELP’s assets in a single transaction or series of transactions.

BRELP will be reconstituted and continue without dissolution if, within 30 days of the date of dissolution (and provided that a notice of dissolution with respect to BRELP has not been filed with the Bermuda Monetary Authority), a successor general partner executes a transfer deed pursuant to which the new general partner assumes the rights and undertakes the obligations of the original general partner, but only if BRELP receives an opinion of counsel that the admission of the new general partner will not result in the loss of limited liability of any limited partner of BRELP.

Withdrawal of the General Partner

The BRELP GP LP may withdraw as general partner without first obtaining approval of BRELP’s limited partners or holders of BRELP Preferred Units by giving 180 days advance notice, and that

Page 198

withdrawal will not constitute a violation of the Amended and Restated Limited Partnership Agreement of BRELP.

Upon the withdrawal of the BRELP GP LP, the holders of at least a majority of the voting power of the outstanding class of units that are not Redeemable/Exchangeable partnership units may elect a successor to the BRELP GP LP. If a successor is not selected, or is elected but an opinion of counsel regarding limited liability, tax matters and the Investment Company Act (and similar legislation in other jurisdictions) cannot be obtained, BRELP will be dissolved, wound up and liquidated. See “— Dissolution” above.

The BRELP GP LP may not be removed unless that removal is approved by the vote of the holders of at least 66^2/3% of the outstanding class of units that are not Redeemable/Exchangeable partnership units and it receives a withdrawal opinion of counsel regarding limited liability, tax matters and the Investment Company Act (and similar legislation in other jurisdictions). Any removal of the BRELP GP LP is also subject to the approval of a successor general partner by the vote of the holders of a majority of the voting power of its outstanding units that are not Redeemable/Exchangeable partnership units.

In the event of the removal of the BRELP GP LP under circumstances where cause exists or withdrawal of the BRELP GP LP where that withdrawal violates the Amended and Restated Limited Partnership Agreement of BRELP, a successor general partner will have the option to purchase the general partnership interest of the BRELP GP LP for a cash payment equal to its fair market value. Under all other circumstances where the BRELP GP LP withdraws or is removed by the limited partners, BRELP GP LP will have the option to require the successor general partner to purchase the general partnership interest of BRELP GP LP for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between BRELP GP LP and the successor general partner. If no agreement is reached within 30 days of BRELP GP LP’s departure, an independent investment banking firm or other independent expert selected by BRELP GP LP and the successor general partner will determine the fair market value. If BRELP GP LP and the successor general partner cannot agree upon an expert within 45 days of BRELP GP LP’s departure, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partnership interests will automatically convert into units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

Transfer of the General Partnership Interest

BRELP GP LP may transfer all or any part of its general partnership interest without first obtaining approval of any holders of BRELP limited partnership units or BRELP Preferred Units. As a condition of this transfer, the transferee must (i) be an affiliate of the general partner of BEP (or the transfer must be made concurrently with a transfer of the general partnership units of BEP to an affiliate of the transferee), (ii) agree to assume the rights and duties of the general partner to whose interest that transferee has succeeded, (iii) agree to be bound by the provisions of the Amended and Restated Limited Partnership Agreement of BRELP and (iv) furnish an opinion of counsel regarding limited liability and tax matters. Any transfer of the general partnership interest is subject to prior notice to and approval of the relevant Bermuda regulatory authority. At any time, the members of the BRELP GP LP may sell or transfer all or part of their units in the BRELP GP LP without the approval of the holders of BRELP limited partnership units.

Transactions with Interested Parties

The general partner of BRELP, its affiliates and its respective partners, members, shareholders, directors, officers, employees and shareholders, which we refer to in the BRELP Amended and Restated Limited Partnership Agreement as “interested parties”, may become limited partners or beneficially interested in limited partners and may hold, dispose of or otherwise deal with units of BRELP with the same rights they would have if the general partner of BRELP were not a party to the Amended and Restated Limited Partnership Agreement of BRELP. An interested party will not be liable to account either to other interested parties or to BRELP, its partners or any other persons for any profits or benefits made or derived by or in connection with any such transaction.

Page 199

The Amended and Restated Limited Partnership Agreement of BRELP permits an interested party to sell investments to, purchase assets from, invest assets in and enter into any contract, arrangement or transaction with BRELP, any of the Holding Entities, any operating entity or any other holding vehicle established by BRELP and may be interested in any such contract, transaction or arrangement and shall not be liable to account either to BRELP, any of the Holding Entities, any operating entity or any other holding vehicle established by BRELP or any other person in respect of any such contract, transaction or arrangement, or any benefits or profits made or derived therefrom, by virtue only of the relationship between the parties concerned, subject to the Conflicts Policy.

Outside Activities of the General Partner

Under the Amended and Restated Limited Partnership Agreement of BRELP, the general partner will be required to maintain as its sole activity the role of the general partner of BRELP. The general partner will not be permitted to engage in any activity or incur or guarantee any debts or liabilities except in connection with or incidental to its performance as general partner or incurring, guaranteeing, acquiring, owning or disposing of debt or equity securities of a subsidiary of a Holding Entity or any other holding vehicle established by BRELP.

The Amended and Restated Limited Partnership Agreement of BRELP provides that each person who is entitled to be indemnified by BRELP, as described below under “— Indemnification; Limitations on Liability” (other than the general partner) will have the right to engage in businesses of every type and description and other activities for profit, and to engage in and possess interests in business ventures of any and every type or description, irrespective of whether (i) such businesses and activities are similar to our activities, or (ii) such businesses and activities directly compete with, or disfavor or exclude, BRELP, its general partner, any Holding Entity, operating entity, or any other holding vehicle established by BRELP. Such business interests, activities and engagements will be deemed not to constitute a breach of the Amended and Restated Limited Partnership Agreement of BRELP or any duties stated or implied by law or equity, including fiduciary duties, owed to any of BRELP, its general partner, any Holding Entity, operating entity, and any other holding vehicle established by BRELP (or any of their respective investors), and shall be deemed not to be a breach of its general partner’s fiduciary duties or any other obligation of any type whatsoever of the general partner. None of BRELP, its general partner, any Holding Entity, operating entity, any other holding vehicle established by BRELP or any other person shall have any rights by virtue of the Amended and Restated Limited Partnership Agreement of BRELP or the partnership relationship established thereby or otherwise in any business ventures of any person who is entitled to be indemnified by BRELP as described below under “— Indemnification; Limitations on Liability”.

The BRELP GP LP and the other indemnified persons described in the preceding paragraph will not have any obligation under the Amended and Restated Limited Partnership Agreement of BRELP to present business or investment opportunities to BRELP, any Holding Entity, operating entity, or any other holding vehicle established by BRELP. These provisions will not affect any obligation of such indemnified person to present business or investment opportunities to BRELP, any Holding Entity, operating entity or any other holding vehicle established by BRELP pursuant to the Relationship Agreement or any other separate written agreement between such persons.

Indemnification; Limitations on Liability

Under the Amended and Restated Limited Partnership Agreement of BRELP, BRELP is required to indemnify on an after-tax basis out of the assets and to the fullest extent permitted by law its general partner, the Service Provider and any of their respective affiliates (and their respective officers, directors, agents, shareholders, partners, members and employees), any person who serves on a Governing Body of BRELP, BEP, a Holding Entity, operating entity or any other holding vehicle established by BEP and any other person designated by its general partner as an indemnified person, in each case, against all losses, claims, damages, liabilities, costs or expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements and other amounts arising from any and all claims, demands, actions, suits or proceedings, incurred by an indemnified person in connection with its business, investments and activities or by reason of their holding such positions, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from the indemnified person’s gross negligence, bad faith, fraud or willful misconduct, or in the case of a criminal

Page 200

matter, action that the indemnified person knew to have been unlawful. In addition, under the Amended and Restated Limited Partnership Agreement of BRELP, (i) the liability of such persons has been limited only where their conduct involves gross negligence, bad faith, fraud or willful misconduct, or in the case of a criminal matter, action that the indemnified person knew to have been unlawful and (ii) subject to applicable law, any matter that is approved by the independent directors will not constitute a breach of any duties stated or implied by law or equity, including fiduciary duties. The Amended and Restated Limited Partnership Agreement of BRELP requires it to advance funds to pay the expenses of an indemnified person in connection with a matter in which indemnification may be sought until it is determined that the indemnified person is not entitled to indemnification. In addition, under the Amended and Restated Limited Partnership Agreement of BRELP, the general partner of BRELP, on behalf of Brookfield, is required under certain circumstances to indemnify BRELP and BEP for U.S. federal income taxes imposed under Sections 897, 1445, or 1461 of the U.S. Internal Revenue Code of 1986, as amended, on BRELP or BEP as a result of the exercise of the redemption right or the exchange right by Brookfield or BEP, as the case may be, pursuant to the Amended and Restated Limited Partnership Agreement of BRELP.

Governing Law

The Amended and Restated Limited Partnership Agreement of BRELP is governed by and will be construed in accordance with the laws of Bermuda.

BRP Equity

BRP Equity is an indirect wholly-owned subsidiary of BEP incorporated under the CBCA on February 10, 2010. Other than a receivable from an indirect wholly-owned subsidiary of BEP, BRP Equity has no significant assets or liabilities, no subsidiaries and no ongoing business operations of its own. BRP Equity’s Series 1 Shares and Series 2 Shares are guaranteed by BEP and the other Guarantors under the Preference Share Guarantees described below under “— Preference Share Guarantees”.

Pursuant to BRP Equity’s articles of incorporation, BRP Equity is authorized to issue an unlimited number of common shares (the “Common Shares”), an unlimited number of Class A Preference Shares (the “Class A Preference Shares”), issuable in series (which includes the Series 1 Shares, Series 2 Shares, Series 3 Shares, Series 4 Shares, Series 5 Shares and Series 6 Shares), and an unlimited number of Class B preference shares (the “Class B Preference Shares”), issuable in series. As of the date of this Form 20-F, one Common Share held indirectly by BEP was issued and outstanding, and 5,449,675 Series 1 Shares, 4,510,389 Series 2 Shares, 9,961,399 Series 3 Shares, 4,114,504 Series 5 Shares and 7 million Series 6 Shares were issued and trading on the TSX. As of the date of this Form 20-F, Brookfield Renewable holds 2,885,496 Series 5 Shares that were tendered and taken up by BEP as part of the exchange transaction completed in February 2016.  Brookfield Renewable has waived the right to receive dividends on these Series 5 Shares and they are no longer trading on the TSX.  No series of Class B Preference Shares have been created to date. The following is a summary of rights, privileges, restrictions and conditions attached to the Common Shares, Class A Preference Shares, Series 1 Shares, Series 2 Shares, Series 3 Shares, Series 4 Shares, Series 5 Shares, Series 6 Shares, and the Class B Preference Shares.

Common Shares

Holders of Common Shares are entitled to one vote for each such share held on all votes taken at meetings of the shareholders of BRP Equity, except meetings at which only the holders of a specified class or series of shares of BRP Equity are entitled to vote. Subject to the rights of holders of Class A Preference Shares or any series thereof, Class B Preference Shares or any series thereof, and other shares of BRP Equity ranking prior to the Common Shares, the holders of Common Shares are entitled to dividends as may be declared from time to time by the board of directors of BRP Equity. Holders of Common Shares may make use of various shareholder remedies available pursuant to the CBCA.

Class A Preference Shares

The following is a summary of certain provisions attaching to or affecting the Class A Preference Shares as a class.

Issuance in Series

Page 201

The board of directors of BRP Equity may from time to time issue Class A Preference Shares in one or more series, each series to consist of such number of shares as will before issuance thereof be approved by the directors who will at the same time determine the designation, rights, privileges, restrictions and conditions attaching to that series of Class A Preference Shares.

Priority

The Class A Preference Shares rank senior to the Class B Preference Shares, the Common Shares and all other shares ranking junior to the Class A Preference Shares with respect to priority in payment of dividends and in the distribution of assets in the event of the liquidation, dissolution or winding-up of BRP Equity. Pursuant to the CBCA, each series of Class A Preference Shares participates rateably with every other series of Class A Preference Shares in respect of accumulated dividends and return of capital.

Approval

The approval of the holders of the Class A Preference Shares of any matters to be approved by a separate vote of the holders of the Class A Preference Shares may be given by special resolution in accordance with the share conditions for the Class A Preference Shares. Each holder of Class A Preference Shares entitled to vote at a class meeting of holders of Class A Preference Shares, or at a joint meeting of the holders of two or more series of Class A Preference Shares, has one vote in respect of each C$25.00 of the issue price of each Class A Preference Share held by such holder.

The following is a summary of certain provisions attaching to or affecting each series of Class A Preference Shares as a series:

Page 202

Series	Ticker	Authorized	Issued and Outstanding	Amount (C$ million)(1)	Cumulative Annual Dividend Rate	Earliest Redemption Date	Redemption Price Per Share (C$)(2) (3)	Holder’s Conversion Option
1	BRF.PR.A	10,000,000	5,449,675	136	The annual fixed dividend rate for each 5-year fixed rate period will be the sum of the Government of Canada Yield plus 2.62%	April 30, 2020	$25.00 on April 30, 2020 and April 30 every five years thereafter	Into Series 2 on a one-for-one basis on April 30, 2020 and on April 30 every five years thereafter and automatically in certain circumstances
2	BRF.PR.B	10,000,000	4,510,389	113	An amount equal to the sum of the three-month Government of Canada Treasury Bill Rate plus 2.62%	April 30, 2020	$25.00 on April 30, 2020 and April 30 every five years thereafter	Into Series 1 on a one-for-one basis on April 30, 2020 and on April 30 every five years thereafter and automatically in certain circumstances
3	BRF.PR.C	10,000,000	9,961,399	249	C$1.10 per share until July 31, 2019; thereafter the annual fixed dividend rate for each 5-year fixed rate period will be the sum of the Government of Canada Yield plus 2.94%	July 31, 2019	$25.00 on July 31, 2019 and July 31 every five years thereafter	Into Series 4 on a one-for-one basis on July 31, 2019 and on July 31 every five years thereafter and automatically in certain circumstances
4	N/A	10,000,000	nil	nil	An amount equal to the sum of the three-month Government of Canada Treasury Bill Rate plus 2.94%	July 31, 2019	$25.00 for redemptions on July 31, 2024 and July 31 every five years thereafter; $25.50 otherwise	Into Series 3 on a one-for-one basis on July 31, 2019 and on July 31 every five years thereafter and automatically in certain circumstances
5	BRF.PR.E	7,000,000	4,114,504(4)	175	C$1.25 per share	April 30, 2018	$26.00 if before April 30, 2019, with annual $0.25 decreases until April 30, 2022; $25.00 thereafter	N/A
6	BRF.PR.F	7,000,000	7,000,000	175	C$1.25 per share	July 31, 2018	$26.00 if before July 31, 2019, with annual $0.25 decreases until July 31, 2022; $25.00 thereafter	N/A

Page 203

⁽¹⁾     Rounded to the nearest million.

⁽²⁾       Payable quarterly on the last day of January, April, July and October of each year.

⁽³⁾       Together with accrued and unpaid dividends.

⁽⁴⁾       As of the date of this Form 20-F, Brookfield Renewable holds 2,885,496 Series 5 Shares that were tendered and taken up by BEP as part of the exchange transaction completed in February 2016. Brookfield Renewable has waived the right to receive dividends on these Series 5 Shares and they are no longer trading on the TSX.

Voting

Holders of all series of Class A Preference Shares are only entitled to receive notice of and to attend all meetings of shareholders if eight quarterly dividends on such series of Class A Preference Shares, whether or not consecutive, have not been paid. In the event of such non-payment, and for only so long as any such dividends remain in arrears, the holders of such series of Class A Preference Shares will be entitled to receive notice of and to attend each meeting of shareholders, other than meetings at which only holders of another specified class or series are entitled to vote. When entitled to vote, holders shall be entitled to one vote in respect of each C$25.00 of the applicable series of Class A Preference Shares held.

Rights on Liquidation

Holders of Class A Preference Shares are entitled to C$25.00 per share (plus accrued and unpaid dividends) in priority to any distribution to holders of shares ranking junior as to capital. Upon such payment, holders of Class A Preference Shares are not entitled to share in any further distribution of assets of the Corporation.

Restrictions on Dividends and Retirement and Issue of Shares

Without the approval of holders of the applicable series of Class A Preference shares in each case, BRP Equity will not:

a)    declare, pay or set apart for payment any dividends (other than stock dividends payable in shares of BRP Equity ranking as to capital and dividends junior to the applicable series of Class A Preference Shares) on shares of BRP Equity ranking as to dividends junior to the applicable series of Class A Preference Shares;

b)    except out of the net cash proceeds of a substantially concurrent issue of shares of BRP Equity ranking as to return of capital and dividends junior to the applicable series of Class A Preference Shares, redeem or call for redemption, purchase or otherwise pay off, retire or make any return of capital in respect of any shares of BRP Equity ranking as to capital junior to the applicable series of Class A Preference Shares;

c)    redeem or call for redemption, purchase or otherwise pay off or retire for value or make any return of capital in respect of less than all of the applicable series of Class A Preference Shares then outstanding; or

d)    except pursuant to any purchase obligation, sinking fund, retraction privilege or mandatory redemption provisions attaching thereto, redeem or call for redemption, purchase or otherwise pay off, retire or make any return of capital in respect shares of BRP Equity ranking on a parity with the applicable series of Class A Preference Shares;

unless, in each such case, all accrued and unpaid dividends up to and including the dividend payable for the last completed period for which dividends were payable on the applicable series of Class A

Page 204

Preference Shares and on all other shares of BRP Equity ranking prior to or on parity with such series of Class A Preference Shares with respect to the payment of dividends, have been declared and paid or set aside for payment.

Purchase for Cancellation

Subject to applicable law and to the provisions described under “– Restrictions on Dividends and Retirement and Issue of Shares”, BRP Equity may at any time purchase for cancellation in whole or any part of the applicable series of Class A Preference Shares at the lowest price or prices at which in the opinion of the board of directors of BRP Equity such shares are obtainable.

Shareholder Approvals

Approval of all amendments to the rights, privileges, restrictions and conditions attaching to the applicable series of Class A Preference Shares and any other approval to be given by the holders of the applicable series of Class A Preference Shares may be given by a resolution carried by at least 66^2/3% of the votes cast at a meeting where the required quorum is present. The required quorum for Series 5 Shares and Series 6 Shares is holders of at least 25% of the outstanding shares present in person or represented by proxy. The required quorum for all other Class A Preference Shares is 50% of the outstanding shares present in person or represented by proxy.

Preference Share Guarantees

The Preference Share Guarantees provide that the applicable series of Class A Preference Shares will be fully and unconditionally guaranteed by BEP and the other Preference Share Guarantors as to (i) payment of dividends, as and when declared, (ii) payment of amounts due on redemption of the applicable series of Class A Preference Shares, and (iii) payment of amounts due on the liquidation, dissolution or winding up of BRP Equity. As long as the declaration or payments of dividends on the applicable series of Class A Preference Shares are in arrears, BEP will not make any distributions on our LP Units nor will any other Preference Share Guarantor make any distributions or pay any dividends on equity securities of such Preference Share Guarantor. The Preference Share Guarantees by the Preference Share Guarantors will be subordinated to all of their respective senior and subordinated debt and will rank senior to the LP Units. The Preference Share Guarantees will rank on a pro rata and pari passu basis with each other. The rights, obligations and liabilities of a Preference Share Guarantor pursuant to the Preference Share Guarantees will terminate upon the conveyance, distribution, transfer or lease of all or substantially all of its properties, securities and assets to another Preference Share Guarantor. A Preference Share Guarantor may not otherwise convey, distribute, transfer or lease all or substantially all of its properties, securities and assets to another person, unless the person which acquires the properties, securities and assets of such Preference Share Guarantor assumes such Preference Share Guarantor’s obligations under the Preference Share Guarantees.

Finco

Finco is an indirect wholly-owned subsidiary of BEP incorporated under the ABCA on September 14, 2011. Other than approximately C$2.1 billion aggregate principal amount of publicly-issued Finco Bonds and notes receivable from an indirect wholly-owned subsidiary of BEP, Finco has no significant assets or liabilities, no subsidiaries and no operations of its own.

 Pursuant to Finco’s articles of incorporation, Finco is authorized to issue an unlimited number of common shares. As of the date of this Form 20-F, one common share held indirectly by BEP was issued and outstanding. Holders of common shares are entitled to one vote for each such share held on all votes taken at meetings of the shareholders of Finco, except meetings at which only the holders of a specified class or series of shares of Finco are entitled to vote. Subject to the rights of holders of any shares of Finco ranking prior to the common shares, the holders of common shares are entitled to dividends as may be declared from time to time by the board of directors of Finco. Holders of common shares may make use of various shareholder remedies available pursuant to the ABCA.

The Finco Bonds are governed under the Bond Indenture and guaranteed by BEP and the other Guarantors as described below under “— Bond Indenture and Guarantees”. The Finco Bonds consist of the following fixed rate medium term notes:

Page 205

			Principal Amount as
			at December 31, 2017
Medium-term notes	Maturity	Interest Rate	(in millions)
Series 3 (C$200 million)	2018	5.25%	C$200 million
Series 4 (C$150 million)	2036	5.84%	C$150 million
Series 7 (C$450 million)	2020	5.14%	C$450 million
Series 8 (C$400 million)	2022	4.79%	C$400 million
Series 9 (C$400 million)	2025	3.75%	C$400 million
Series 10 (C$500 million)	2027	3.63%	C$500 million

Bond Indenture and Guarantees

The Bond Indenture provides for the issuance of one or more series of unsecured debentures or notes of Finco, a wholly-owned subsidiary of BEP, by way of supplemental indentures. The Bond Indenture amends and restates the trust indenture dated as of December 16, 2004, as amended, supplemented or restated, between Brookfield, Bank of New York Mellon and BNY Trust Company of Canada (the “Original Bond Indenture”). The Bond Indenture provided for Finco to assume Brookfield’s obligations in respect of the Series 3, Series 4 and Series 7 notes issued under supplemental indentures to the Original Bond Indenture. The Amended and Restated Second Supplemental Indenture to the Original Bond Indenture, dated October 27, 2006, provides for the issue of C$200 million aggregate principal amount of Series 3 medium term notes and C$150 million aggregate principal amount of Series 4 medium term notes. The Fifth Supplemental Indenture to the Original Bond Indenture, dated November 27, 2009, provides for the issue of C$450 million aggregate principal amount of Series 7 notes. The Seventh Supplemental Indenture dated February 7, 2012, provides for the issue of C$400 million aggregate principal amount of Series 8 notes. The Ninth Supplemental Indenture dated March 6, 2015, provides for the issue of C$400 million aggregate principal amount of Series 9 notes. The Tenth Supplemental Indenture dated August 12, 2016, provides for the issue of C$500 million aggregate principal amount of Series 10 notes.  Finco Bonds are unconditionally guaranteed by BEP and the other Finco Bond Guarantors as to payment of the principal of, premium, if any, and interest on all debentures issued by Finco under the Bond Indenture from time to time and all other obligations and liabilities owing by Finco to the trustee under the Bond Indenture. Pursuant to the guarantees, each of the Finco Bond Guarantors has agreed to not enter into any transaction whereby all or substantially all of the undertaking, property and assets of the Finco Bond Guarantor would become the property of any other person unless the other person assumed the obligations of the Finco Bond Guarantor under the guarantee and certain other conditions are met or unless the transaction is between or among any one or more of Finco, the Finco Bond Guarantor, another Finco Bond Guarantor and/or any subsidiary of any of them. The rights, obligations and liabilities of a Finco Bond Guarantor will terminate in the event that it transfers all or substantially all of its assets to another Finco Bond Guarantor.

10.C            MATERIAL CONTRACTS

The following are the only material contracts, other than contracts entered into in the ordinary course of business, to which we have been a party within the past two years:

·Relationship Agreement, dated November 28, 2011, by and among BEP, BRELP, the Service Provider, Brookfield, and others (see Item 7.B “Related Party Transactions – Relationship Agreement”).

·Registration Rights Agreement, dated November 28, 2011, between BEP and BRPI (see Item 7.B “Related Party Transactions – Registration Rights Agreement”).

·Amended and Restated Indenture, dated as of November 23, 2011, among Finco, BNY Trust Company of Canada and The Bank of New York Mellon (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

Page 206

·Guarantee, dated November 23, 2011, by BRELP and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Guarantee, dated November 23, 2011, by BEP and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Guarantee, dated November 23, 2011, by LATAM Holdco and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Guarantee, dated November 23, 2011, by NA Holdco and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Energy Revenue Agreement, dated November 23, 2011, between BEM LP and BPUSHA (see Item 7.B “Related Party Transactions – Energy Revenue Agreement”).

·Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, BRP Equity, and Computershare Trust Company of Canada (Class A Preference Shares, Series 1) (see Item 10.B “Memorandum and Articles of Association – BRP Equity – Preference Share Guarantees”).

·Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, BRP Equity, and Computershare Trust Company of Canada (Class A Preference Shares, Series 2) (see Item 10.B “Memorandum and Articles of Association – BRP Equity – Preference Share Guarantees”).

·Guarantee Indenture, dated October 11, 2012, by and among the Preference Share Guarantors from time to time party thereto, BRP Equity, and Computershare Trust Company of Canada (Class A Preference Shares, Series 3) (see Item 10.B “Memorandum and Articles of Association – BRP Equity – Preference Share Guarantees”).

·Guarantee Indenture, dated January 29, 2013, by and among the Preference Share Guarantors from time to time party thereto, BRP Equity, and Computershare Trust Company of Canada (Class A Preference Shares, Series 5) (see Item 10.B “Memorandum and Articles of Association – BRP Equity – Preference Share Guarantees”).

·Guarantee Indenture, dated May 1, 2013, by and among the Preference Share Guarantors from time to time party thereto, BRP Equity, and Computershare Trust Company of Canada (Class A Preference Shares, Series 6) (see Item 10.B “Memorandum and Articles of Association – BRP Equity – Preference Share Guarantees”).

·Guarantee dated October 7, 2014, by Euro Holdco and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Guarantee dated February 26, 2015, by Investco and BNY Trust Company of Canada (see Item 10.B “Memorandum and Articles of Association – Finco – Bond Indenture and Guarantees”).

·Second Amended and Restated Master Services Agreement, dated February 26, 2015, by and among Brookfield Asset Management Inc., BEP, BRELP, and others (see Item 6.A “Directors and Senior Management – Our Master Services Agreement”).

·Guarantee Indenture, dated November 25, 2015, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 7 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units,

Page 207

Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP — Preferred Unit Guarantees”).

·Guarantee Indenture, dated November 25, 2015, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 8 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated February 11, 2016, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 5 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Third Amended and Restated Limited Partnership Agreement of BRELP, dated February 11, 2016, as amended on May 25, 2016 and February 14, 2017, and further amended on January 16, 2018 (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”).

·Fourth Amended and Restated Limited Partnership Agreement of BEP, dated May 3, 2016, as amended on May 25, 2016 and February 14, 2017, and further amended on January 16, 2018 (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP”).

·Guarantee Indenture, dated May 25, 2016, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 9 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated May 25, 2016, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 10 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated February 14, 2017, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 11 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated February 14, 2017, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 12 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated January 16, 2018, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 13 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

·Guarantee Indenture, dated January 16, 2018, by and among the Preferred Unit Guarantors, BEP, and Computershare Trust Company of Canada (Series 14 Preferred Units) (see Item 10.B “Memorandum and Articles of Association — Description of our LP Units, Preferred

Page 208

Units and the Amended and Restated Limited Partnership Agreement of BEP— Preferred Unit Guarantees”).

Copies of the agreements noted above will be made available, free of charge, by the Managing General Partner and are available electronically on our EDGAR profile at www.sec.gov and on our SEDAR profile at www.sedar.com. Written requests for such documents should be directed to our Corporate Secretary at 73 Front Street, 5th Floor, Hamilton, HM 12, Bermuda, +441-294-3304.

10.D            EXCHANGE CONTROLS

There are currently no governmental laws, decrees, regulations or other legislation of Bermuda or the United States which restrict the import or export of capital, including the availability of cash and cash equivalents for use by BREP and its subsidiaries, or the remittance of distributions, interest or other payments to non-residents of Bermuda or the United States holding our LP Units.

10.E            TAXATION

The following summary discusses the material United States, Canadian and Bermudian tax considerations related to the holding and disposition of our Units as of the date of this Form 20-F. Holders of our Units are advised to consult their own tax advisers concerning the consequences under the tax laws of the country of which they are resident or in which they are otherwise subject to tax of making an investment in our Units.

Material U.S. Federal Income Tax Considerations

This summary discusses the material United States federal income tax considerations for LP Unitholders relating to the ownership and disposition of LP Units as of the date hereof. This summary is based on provisions of the U.S. Internal Revenue Code on the regulations promulgated under the U.S. Internal Revenue Code, and on published administrative rulings, judicial decisions, and other applicable authorities, all as in effect on the date hereof and all of which are subject to change at any time, possibly with retroactive effect. This summary is necessarily general and may not apply to all categories of investors, some of whom may be subject to special rules, including, without limitation, persons that own (directly or indirectly, applying certain attribution rules) 5% or more of our LP Units, dealers in securities or currencies, financial institutions or financial services entities, mutual funds, life insurance companies, persons that hold LP Units as part of a straddle, hedge, constructive sale or conversion transaction with other investments, persons whose LP Units are loaned to a short seller to cover a short sale of LP Units, persons whose functional currency is not the U.S. dollar, persons who have elected mark-to-market accounting, persons who hold LP Units through a partnership or other entity treated as a pass-through entity for U.S. federal income tax purposes, persons for whom LP Units are not a capital asset, persons who are liable for the alternative minimum tax and certain U.S. expatriates or former long-term residents of the United States. This summary does not address any tax consequences to holders of Preferred Units. Tax-exempt organizations are addressed separately below. The actual tax consequences of the ownership and disposition of LP Units will vary depending on an LP Unitholder’s individual circumstances.

For purposes of this discussion, a “U.S. Holder” is a beneficial owner of LP Units who is for U.S. federal tax purposes: (i) an individual citizen or resident of the United States; (ii) a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia; (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source; or (iv) a trust (a) the primary supervision of which is subject to a court within the United States and all substantial decisions of which one or more U.S. persons have the authority to control or (b) that has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

A “Non-U.S. Holder” is a beneficial owner of LP Units, other than a U.S. Holder or an entity classified as a partnership or other fiscally transparent entity for U.S. federal tax purposes.

If a partnership holds LP Units, the tax treatment of a partner of such partnership generally will depend upon the status of the partner and the activities of the partnership. Partners of partnerships that hold LP Units should consult an independent tax adviser.

Page 209

This discussion does not constitute tax advice and is not intended to be a substitute for tax planning. Each LP Unitholder should consult an independent tax adviser concerning the U.S. federal, state and local income tax consequences particular to the ownership and disposition of LP Units, as well as any tax consequences under the laws of any other taxing jurisdiction.

Partnership Status of BEP and BRELP

Each of BEP and BRELP has made a protective election to be classified as a partnership for U.S. federal tax purposes. An entity that is treated as a partnership for U.S. federal tax purposes incurs no U.S. federal income tax liability. Instead, each partner is required to take into account its allocable share of items of income, gain, loss, deduction, or credit of the partnership in computing its U.S. federal income tax liability, regardless of whether cash distributions are made. Distributions of cash by a partnership to a partner generally are not taxable unless the amount of cash distributed to a partner is in excess of the partner’s adjusted basis in its partnership interest.

An entity that would otherwise be classified as a partnership for U.S. federal income tax purposes may nonetheless be taxable as a corporation if it is a “publicly traded partnership”, unless an exception applies to that entity. BEP is publicly traded. However, an exception, referred to as the “Qualifying Income Exception”, exists with respect to a publicly traded partnership if (i) at least 90% of such partnership’s gross income for every taxable year consists of “qualifying income” and (ii) the partnership would not be required to register under the Investment Company Act if it were a U.S. corporation. Qualifying income includes certain interest income, dividends, real property rents, gains from the sale or other disposition of real property, and any gain from the sale or disposition of a capital asset or other property held for the production of income that otherwise constitutes qualifying income.

The Managing General Partner and the BRELP General Partner intend to manage the affairs of BEP and BRELP, respectively, so that BEP will meet the Qualifying Income Exception in each taxable year. Accordingly, the Managing General Partner believes that BEP will be treated as a partnership and not as a corporation for U.S. federal income tax purposes.

If BEP fails to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, or if BEP is required to register under the Investment Company Act, BEP will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which BEP fails to meet the Qualifying Income Exception, in return for stock in such corporation, and then distributed the stock to our LP Unitholders in liquidation. This deemed contribution and liquidation generally would be tax-free to a U.S. Holder, unless BEP were to have liabilities in excess of the tax basis of its assets at such time. Thereafter, BEP would be treated as a corporation for U.S. federal income tax purposes.

If BEP were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception, an election by the Managing General Partner or otherwise, BEP’s items of income, gain, loss, deduction, or credit would be reflected only on BEP’s tax return rather than being passed through to LP Unitholders, and BEP would be subject to U.S. corporate income tax and potentially branch profits tax with respect to its income, if any, effectively connected with a U.S. trade or business. Moreover, under certain circumstances, BEP might be classified as a PFIC for U.S. federal income tax purposes, and a U.S. Holder would be subject to the rules applicable to PFICs discussed below. See “— Consequences to U.S. Holders — Passive Foreign Investment Companies”. Subject to the PFIC rules, distributions made to U.S. Holders would be treated as taxable dividend income to the extent of BEP’s current or accumulated earnings and profits. Any distribution in excess of current and accumulated earnings and profits would first be treated as a tax-free return of capital to the extent of a U.S. Holder’s adjusted tax basis in its LP Units. Thereafter, to the extent such distribution were to exceed a U.S. Holder’s adjusted tax basis in its LP Units, the distribution would be treated as gain from the sale or exchange of such LP Units. The amount of a distribution treated as a dividend could be eligible for reduced rates of taxation, provided certain conditions are met. Based on the foregoing consequences, the treatment of BEP as a corporation could materially reduce a holder’s after-tax return and therefore could result in a substantial reduction of the value of LP Units. If BRELP were to be treated as a corporation for U.S. federal income tax purposes, consequences similar to those described above would apply to BEP’s interests in BRELP.

Page 210

The remainder of this summary assumes that BEP and BRELP will be treated as partnerships for U.S. federal tax purposes. BEP expects that a substantial portion of the items of income, gain, deduction, loss, or credit realized by BEP will be realized in the first instance by BRELP and allocated to BEP for reallocation to LP Unitholders. Unless otherwise specified, references in this section to realization of BEP’s items of income, gain, loss, deduction, or credit include a realization of such items by BRELP and the allocation of such items to BEP.

Consequences to U.S. Holders

Holding of LP Units

Income and loss. Each U.S. Holder must take into account, as described below, its allocable share of BEP’s items of income, gain, loss, deduction, and credit for each of BEP’s taxable years ending with or within such U.S. Holder’s taxable year. Each item generally will have the same character and source as though such holder had realized the item directly. Each U.S. Holder must report such items without regard to whether any distribution has been or will be received from BEP. Although not required by the Amended and Restated Limited Partnership Agreement of BEP, BEP intends to make cash distributions to all LP Unitholders on a quarterly basis in amounts generally expected to be sufficient to permit U.S. Holders to fund their estimated U.S. tax obligations (including U.S. federal, state, and local income taxes) with respect to their allocable shares of BEP’s net income or gain. However, based upon a U.S. Holder’s particular tax situation and simplifying assumptions that BEP will make in determining the amount of such distributions, and depending upon whether a U.S. Holder elects to reinvest such distributions pursuant to the distribution reinvestment plan, if available, a U.S. Holder’s tax liability might exceed cash distributions made by BEP, in which case any tax liabilities arising from the ownership of LP Units would need to be satisfied from such U.S. Holder’s own funds.

With respect to U.S. Holders who are individuals, certain dividends paid by a corporation (including certain qualified foreign corporations) to BEP and that are allocable to such U.S. Holders may qualify for reduced rates of taxation. A qualified foreign corporation includes a foreign corporation that is eligible for the benefits of specified income tax treaties with the United States. In addition, a foreign corporation is treated as a qualified corporation with respect to its shares that are readily tradable on an established securities market in the United States. Among other exceptions, U.S. Holders who are individuals will not be eligible for reduced rates of taxation on any dividends if the payer is a PFIC for the taxable year in which such dividends are paid or for the preceding taxable year. Dividends received by non-corporate U.S. Holders may be subject to an additional Medicare tax on unearned income of 3.8% (see “— Medicare Tax” below). U.S. Holders that are corporations generally will not be entitled to a “dividends received deduction” in respect of dividends paid by non-U.S. corporations in which BEP (through BRELP) owns stock. Each U.S. Holder should consult an independent tax adviser regarding the application of the foregoing rules in light of its particular circumstances.

For U.S. federal income tax purposes, a U.S. Holder’s allocable share of BEP’s items of income, gain, loss, deduction, or credit will be governed by the BEP limited partnership agreement if such allocations have “substantial economic effect” or are determined to be in accordance with such U.S. Holder’s interest in BEP. Similarly, BEP’s allocable share of items of income, gain, loss, deduction, or credit of BRELP will be governed by the BRELP limited partnership agreement if such allocations have “substantial economic effect” or are determined to be in accordance with BEP’s interest in BRELP. The Managing General Partner and the BRELP General Partner believe that, for U.S. federal income tax purposes, such allocations should be given effect, and the Managing General Partner and the BRELP General Partner intend to prepare and file tax returns based on such allocations. If the IRS were to successfully challenge the allocations made pursuant to either the BEP limited partnership agreement or the BRELP limited partnership agreement, the resulting allocations for U.S. federal income tax purposes might be less favorable than the allocations set forth in such agreements.

Basis. Each U.S. Holder will have an initial tax basis in its LP Units equal to the amount of cash paid for such LP Units, increased by such holder’s share of BEP’s liabilities, if any. That basis will be increased by such U.S. Holder’s share of BEP’s income and by increases in such U.S. Holder’s share of BEP’s liabilities, if any. That basis will be decreased, but not below zero, by distributions a U.S. Holder receives from BEP, by such U.S. Holder’s share of BEP’s losses, and by any decrease in such U.S. Holder’s share of BEP’s liabilities. The IRS has ruled that a partner in a partnership, unlike a stockholder

Page 211

of a corporation, has a single, or “unitary”, tax basis in his or her partnership interest. As a result, any amount a U.S. Holder pays to acquire additional LP Units (including through the distribution reinvestment plan, if available) will be averaged with the adjusted tax basis of LP Units owned by such holder prior to the acquisition of such additional LP Units. The Managing General Partner and the BRELP General Partner express no opinion regarding the appropriate methodology to be used in making this determination.

For purposes of the foregoing rules, the rules discussed immediately below, and the rules applicable to a sale or exchange of LP Units, BEP’s liabilities generally will include BEP’s share of any liabilities of BRELP.

Limits on deductions for losses and expenses. A U.S. Holder’s deduction of its allocable share of BEP’s losses will be limited to such U.S. Holder’s tax basis in LP Units and, if the holder is an individual or a corporate holder that is subject to the “at risk” rules, to the amount for which the holder is considered to be “at risk” with respect to BEP’s activities, if that is less than such U.S. Holder’s tax basis. In general, a U.S. Holder will be at risk to the extent of such holder’s tax basis in LP Units, reduced by (i) the portion of that basis attributable to such U.S. Holder’s share of BEP’s liabilities for which the holder will not be personally liable (excluding certain qualified non-recourse financing) and (ii) any amount of money the U.S. Holder borrows to acquire or hold LP Units, if the lender of those borrowed funds owns an interest in BEP, is related to the U.S. Holder, or can look only to LP Units for repayment. A U.S. Holder’s at-risk amount generally will increase by such U.S. Holder’s allocable share of BEP’s income and gain and decrease by distributions received from BEP and such U.S. Holder’s allocable share of losses and deductions. A U.S. Holder must recapture losses deducted in previous years to the extent that distributions cause such U.S. Holder’s at-risk amount to be less than zero at the end of any taxable year. Losses disallowed or recaptured as a result of these limitations will carry forward and will be allowable to the extent that such U.S. Holder’s tax basis or at-risk amount, whichever is the limiting factor, subsequently increases. Upon the taxable disposition of LP Units, any gain recognized by a U.S. Holder can be offset by losses that were previously suspended by the at-risk limitation, but may not be offset by losses suspended by the basis limitation. Any excess loss above the gain previously suspended by the at-risk or basis limitations may no longer be used. Each U.S. Holder should consult an independent tax adviser as to the effects of the at-risk rules.

The Managing General Partner and the BRELP General Partner do not expect to generate income or losses from “passive activities” for purposes of Section 469 of the U.S. Internal Revenue Code. Accordingly, income allocated to a U.S. Holder may not be offset by such holder’s Section 469 passive losses, and losses allocated to a U.S. Holder may not be used to offset such holder’s Section 469 passive income. In addition to the foregoing limitations, under the Tax Cuts and Jobs Act, non-corporate taxpayers are not permitted to deduct “excess business losses” for taxable years beginning after December 31, 2017, and before January 1, 2026. Each U.S. Holder should consult an independent tax adviser regarding the limitations on the deductibility of losses that such holder may be subject to under applicable sections of the U.S. Internal Revenue Code.

Limitations on deductibility of organizational expenses and syndication fees. In general, neither BEP nor any U.S. Holder may deduct organizational or syndication expenses. Similar rules apply to organizational or syndication expenses incurred by BRELP. Syndication fees (which would include any sales or placement fees or commissions) must be capitalized and cannot be amortized or otherwise deducted.

Limitations on interest deductions. A U.S. Holder’s share of BEP’s interest expense, if any, is likely to be treated as “investment interest” expense. For a non-corporate U.S. Holder, the deductibility of “investment interest” expense generally is limited to the amount of such holder’s “net investment income”. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment.  A U.S. Holder’s share of BEP’s dividend and interest income will be treated as investment income, although “qualified dividend income” subject to reduced rates of tax in the hands of an individual will only be treated as investment income if such individual elects to treat such dividend as ordinary income not subject to reduced rates of tax. In addition, state and local

Page 212

tax laws may disallow deductions for a U.S. Holder’s share of BEP’s interest expense.  Under Section 163(j) of the U.S. Internal Revenue Code, as amended by the Tax Cuts and Jobs Act, additional limitations may apply to a corporate U.S. Holder’s share of BEP’s interest expense, if any.

Deductibility of partnership investment expenditures by individual partners and by trusts and estates. Under the Tax Cuts and Jobs Act, individuals and certain estates and trusts will not be permitted to claim miscellaneous itemized deductions for taxable years beginning after December 31, 2017, and before January 1, 2026.  Such miscellaneous itemized deductions may include the operating expenses of BEP, including BEP’s allocable share of any management fees.

Treatment of Distributions

Distributions of cash by BEP generally will not be taxable to a U.S. Holder to the extent of such holder’s adjusted tax basis (described above) in LP Units. Any cash distributions in excess of a U.S. Holder’s adjusted tax basis generally will be considered to be gain from the sale or exchange of LP Units (described below). Such gain generally will be treated as capital gain and will be long-term capital gain if a U.S. Holder’s holding period for LP Units exceeds one year. A reduction in a U.S. Holder’s allocable share of BEP liabilities, and certain distributions of marketable securities by BEP, if any, will be treated similar to cash distributions for U.S. federal income tax purposes.

Sale or Exchange of LP Units

A U.S. Holder will recognize gain or loss on the sale or taxable exchange of LP Units equal to the difference, if any, between the amount realized and such U.S. Holder’s tax basis in LP Units sold or exchanged. A U.S. Holder’s amount realized will be measured by the sum of the cash or the fair market value of other property received plus such U.S. Holder’s share of BEP’s liabilities, if any.

Gain or loss recognized by a U.S. Holder upon the sale or exchange of LP Units generally will be taxable as capital gain or loss and will be long-term capital gain or loss if the U.S. Holder held our LP Units for more than one year on the date of such sale or exchange. Assuming a U.S. Holder has not elected to treat its share of BEP’s investment in any PFIC as a “qualified electing fund”, gain attributable to such investment in a PFIC would be taxable in the manner described below in “— Passive Foreign Investment Companies”. In addition, certain gain attributable to “unrealized receivables” or “inventory items” could be characterized as ordinary income rather than capital gain. For example, if BEP were to hold debt acquired at a market discount, accrued market discount on such debt would be treated as “unrealized receivables”. The deductibility of capital losses is subject to limitations.

Each U.S. Holder who acquires LP Units at different times and intends to sell all or a portion of our LP Units within a year of the most recent purchase is urged to consult an independent tax adviser regarding the application of certain “split holding period” rules to such sale and the treatment of any gain or loss as long-term or short-term capital gain or loss.

Medicare Tax

U.S. Holders that are individuals, estates, or trusts may be required to pay a 3.8% Medicare tax on the lesser of (i) the excess of such U.S. Holders’ “modified adjusted gross income” (or “adjusted gross income” in the case of estates and trusts) over certain thresholds and (ii) such U.S. Holders’ “net investment income” (or “undistributed net investment income” in the case of estates and trusts). Net investment income generally is expected to include an LP Unitholder’s allocable share of BEP’s income, as well as gain realized by an LP Unitholder from a sale of LP Units.

Foreign Tax Credit Limitations

Each U.S. Holder generally will be entitled to a foreign tax credit with respect to such U.S. Holder’s allocable share of creditable foreign taxes paid on BEP’s income and gains. Complex rules may, depending on such U.S. Holder’s particular circumstances, limit the availability or use of foreign tax credits. For example, gain from the sale of BEP’s investments may be treated as U.S.-source gain. Consequently, a U.S. Holder may not be able to use the foreign tax credit arising from any foreign taxes imposed on such gains unless the credit can be applied (subject to applicable limitations) against U.S. tax due on other income treated as derived from foreign sources. Certain losses that BEP incurs may be

Page 213

treated as foreign-source losses, which could reduce the amount of foreign tax credits otherwise available.

Deduction for Qualified Business Income

Under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, and before January 1, 2026, U.S. taxpayers who have domestic “qualified business income” from a partnership generally are entitled to deduct the lesser of such qualified business income or 20% of taxable income. The 20% deduction is also allowed for “qualified publicly traded partnership income”. A U.S. Holder’s allocable share of BEP’s income is not expected to be treated as qualified business income or as qualified publicly traded partnership income.

Section 754 Election

BEP and BRELP have each made the election permitted by Section 754 of the U.S. Internal Revenue Code, or the Section 754 Election. The Section 754 Election cannot be revoked without the consent of the IRS. The Section 754 Election generally requires BEP to adjust the tax basis in its assets, or inside basis, attributable to a transferee of LP Units under Section 743(b) of the U.S. Internal Revenue Code to reflect the purchase price paid by the transferee for LP Units. This election does not apply to a person who purchases LP Units directly from BEP. For purposes of this discussion, a transferee’s inside basis in BEP’s assets will be considered to have two components: (i) the transferee’s share of BEP’s tax basis in BEP’s assets, or common basis, and (ii) the adjustment under Section 743(b) of the U.S. Internal Revenue Code to that basis. The foregoing rules would also apply to BRELP.

Generally, a Section 754 Election would be advantageous to a transferee U.S. Holder if such U.S. Holder’s tax basis in its LP Units were higher than such LP Units’ share of the aggregate tax basis of BEP’s assets immediately prior to the transfer. In that case, as a result of the Section 754 Election, the transferee U.S. Holder would have a higher tax basis in its share of BEP’s assets for purposes of calculating, among other items, such holder’s share of any gain or loss on a sale of BEP’s assets. Conversely, a Section 754 Election would be disadvantageous to a transferee U.S. Holder if such U.S. Holder’s tax basis in its LP Units were lower than such LP Units’ share of the aggregate tax basis of BEP’s assets immediately prior to the transfer. Thus, the fair market value of LP Units may be affected either favorably or adversely by the election.

Without regard to whether the Section 754 Election is made, if LP Units are transferred at a time when BEP has a “substantial built-in loss” in its assets, BEP will be obligated to reduce the tax basis in the portion of such assets attributable to such LP Units.

The calculations involved in the Section 754 Election are complex, and the Managing General Partner and the BRELP General Partner advise that each will make such calculations on the basis of assumptions as to the value of BEP assets and other matters. Each U.S. Holder should consult an independent tax adviser as to the effects of the Section 754 Election.

Uniformity of LP Units

Because BEP cannot match transferors and transferees of LP Units, BEP must maintain the uniformity of the economic and tax characteristics of LP Units to a purchaser of LP Units. In the absence of uniformity, BEP may be unable to comply fully with a number of U.S. federal income tax requirements. A lack of uniformity can result from a literal application of certain Treasury Regulations to BEP’s Section 743(b) adjustments, a determination that BEP’s Section 704(c) allocations are unreasonable, or other reasons. Section 704(c) allocations would be intended to reduce or eliminate the disparity between tax basis and the value of BEP’s assets in certain circumstances, including on the issuance of additional LP Units. In order to maintain the fungibility of all LP Units at all times, BEP will seek to achieve the uniformity of U.S. tax treatment for all purchasers of LP Units which are acquired at the same time and price (irrespective of the identity of the particular seller of LP Units or the time when LP Units are issued), through the application of certain tax accounting principles that the Managing General Partner believes are reasonable for BEP. However, the IRS may disagree with BEP and may successfully challenge its application of such tax accounting principles. Any non-uniformity could have a negative impact on the value of LP Units.

 Foreign Currency Gain or Loss

Page 214

BEP’s functional currency is the U.S. dollar, and BEP’s income or loss is calculated in U.S. dollars. It is likely that BEP will recognize “foreign currency” gain or loss with respect to transactions involving non-U.S. dollar currencies. In general, foreign currency gain or loss is treated as ordinary income or loss. Each U.S. Holder should consult an independent tax adviser regarding the tax treatment of foreign currency gain or loss.

Passive Foreign Investment Companies

U.S. Holders may be subject to special rules applicable to indirect investments in foreign corporations, including an investment through BEP in a PFIC. A PFIC is defined as any foreign corporation with respect to which (after applying certain look-through rules) either (i) 75% or more of its gross income for a taxable year is “passive income” or (ii) 50% or more of its assets in any taxable year (generally based on the quarterly average of the value of its assets) produce or are held for the production of “passive income”. There are no minimum stock ownership requirements for PFICs. If a U.S. Holder holds an interest in a foreign corporation for any taxable year during which the corporation is classified as a PFIC with respect to such holder, then the corporation will continue to be classified as a PFIC with respect to that U.S. Holder for any subsequent taxable year during which the U.S. Holder continues to hold an interest in the corporation, even if the corporation’s income or assets would not cause it to be a PFIC in such subsequent taxable year, unless an exception applies.

Subject to certain elections described below, any gain on the disposition of stock of a PFIC owned by a U.S. Holder indirectly through BEP, as well as income realized on certain “excess distributions” by such PFIC, would be treated as though realized ratably over the shorter of such U.S. Holder’s holding period of LP Units or BEP’s holding period for the PFIC. Such gain or income generally would be taxable as ordinary income and dividends paid by the PFIC would not be eligible for the preferential tax rates for dividends paid to non-corporate U.S. Holders. In addition, an interest charge would apply, based on the tax deemed deferred from prior years.

If a U.S. Holder were to make an election to treat such U.S. Holder’s share of BEP’s interest in a PFIC as a “qualified electing fund”, such election a “QEF Election”, for the first year such holder were treated as holding such interest, then in lieu of the tax consequences described in the paragraph immediately above, the U.S. Holder would be required to include in income each year a portion of the ordinary earnings and net capital gains of the PFIC, even if not distributed to BEP or to the holder. A QEF Election must be made by a U.S. Holder on an entity-by-entity basis. To make a QEF Election, a U.S. Holder must, among other things, (i) obtain a PFIC annual information statement (through an intermediary statement supplied by BEP) and (ii) prepare and submit IRS Form 8621 with such U.S. Holder’s annual income tax return. To the extent reasonably practicable, BEP intends to timely provide U.S. Holders with the information necessary to make a QEF Election with respect to any BEP entity that the Managing General Partner and the BRELP General Partner believe is a PFIC with respect to a U.S. Holder. Any such election should be made for the first year BEP holds an interest in such entity or for the first year in which a U.S. Holder holds LP Units, if later. Non-corporate U.S. Holders making QEF Elections are also subject to special rules for determining their taxable income and basis in LP Units for purposes of the 3.8% Medicare tax (as described above under “— Medicare Tax”).

In the case of a PFIC that is a publicly traded foreign company, and in lieu of making a QEF Election, an election may be made to “mark to market” the stock of such foreign company on an annual basis. Pursuant to such an election, a U.S. Holder would include in each year as ordinary income the excess, if any, of the fair market value of such stock over its adjusted basis at the end of the taxable year. However, none of the existing BEP entities are expected to be publicly traded, although BEP may in the future acquire interests in PFICs which are publicly traded foreign companies. Thus the mark-to-market election is not expected to be available to any U.S. Holder in respect of its indirect ownership interest in any foreign corporation owned by BEP.

Based on the organizational structure of BEP, as well as BEP’s expected income and assets, the Managing General Partner and the BRELP General Partner currently believe that a U.S. Holder is unlikely to be regarded as owning an interest in a PFIC solely by reason of owning LP Units during the taxable year ending December 31, 2018. However, there can be no assurance that an existing BEP entity or a future entity in which BEP acquires an interest will not be classified as a PFIC with respect to a U.S. Holder, because PFIC status is a factual determination that depends on the assets and income of a given

Page 215

entity and must be made on an annual basis. Moreover, in order to ensure that it satisfies the Qualifying Income Exception, among other reasons, BEP may decide to hold an existing or future Operating Entity through a Holding Entity that would be classified as a PFIC. See “— Investment Structure” below.

Subject to certain exceptions, a U.S. person who directly or indirectly owns an interest in a PFIC generally is required to file an annual report with the IRS, and the failure to file such report could result in the imposition of penalties on such U.S. person and in the extension of the statute of limitations with respect to federal income tax returns filed by such U.S. person. Each U.S. Holder should consult an independent tax adviser regarding the PFIC rules, including the potential effect of this legislation on such U.S. Holder’s filing requirements and the advisability of making a QEF Election or, if applicable, a mark-to-market election, with respect to any PFIC in which such holder is treated as owning an interest through BEP.

Investment Structure

To ensure that it meets the Qualifying Income Exception for publicly traded partnerships (discussed above) and complies with certain requirements in its limited partnership agreement, among other reasons, BEP may structure certain investments through an entity classified as a corporation for U.S. federal income tax purposes. Such investments will be structured as determined in the sole discretion of the Managing General Partner and the BRELP General Partner generally to be efficient for LP Unitholders. However, because LP Unitholders will be located in numerous taxing jurisdictions, no assurance can be given that any such investment structure will benefit all LP Unitholders to the same extent, and such an investment structure might even result in additional tax burdens on some LP Unitholders. As discussed above, if any such entity were a non-U.S. corporation, it might be considered a PFIC. If any such entity were a U.S. corporation, it would be subject to U.S. federal net income tax on its income, including any gain recognized on the disposition of its investments. In addition, if the investment were to involve U.S. real property, gain recognized on the disposition of the investment by a corporation generally would be subject to corporate-level tax, whether the corporation were a U.S. or a non-U.S. corporation.

Taxes in Other Jurisdictions

In addition to U.S. federal income tax consequences, an investment in BEP could subject a U.S. Holder to U.S. state and local taxes in the U.S. state or locality in which such holder is a resident for tax purposes. A U.S. Holder could also be subject to tax return filing obligations and income, franchise, or other taxes, including withholding taxes, in non-U.S. jurisdictions in which BEP invests. BEP will attempt, to the extent reasonably practicable, to structure its operations and investments so as to avoid income tax filing obligations by U.S. Holders in non-U.S. jurisdictions. However, there may be circumstances in which BEP is unable to do so. Income or gain from investments held by BEP may be subject to withholding or other taxes in jurisdictions outside the U.S., except to the extent an income tax treaty applies. A U.S. Holder who wishes to claim the benefit of an applicable income tax treaty might be required to submit information to tax authorities in such jurisdictions. Each U.S. Holder should consult an independent tax adviser regarding the U.S. state, local, and non-U.S. tax consequences of an investment in BEP.

Transferor/Transferee Allocations

BEP may allocate items of income, gain, loss, and deduction using a monthly convention, whereby any such items recognized in a given month by BEP are allocated to our LP Unitholders as of a specified date of such month. As a result, a U.S. Holder who transfers LP Units might be allocated income, gain, loss, and deduction realized by BEP after the date of the transfer. Similarly, if a U.S. Holder acquires additional LP Units, such holder may be allocated income, gain, loss, and deduction realized by BEP prior to such U.S. Holder’s ownership of such LP Units.

Section 706 of the U.S. Internal Revenue Code generally governs allocations of items of partnership income and deductions between transferors and transferees of partnership interests, and the Treasury Regulations provide a safe harbor allowing a publicly traded partnership to use a monthly simplifying convention for such purposes. However, it is not clear that BEP’s allocation method complies with the requirements. If BEP’s convention were not permitted, the IRS might contend that BEP’s taxable income or losses must be reallocated among LP Unitholders. If such a contention were sustained, a U.S. Holder’s tax liabilities might be adjusted to such holder’s detriment. The Managing General Partner is

Page 216

authorized to revise BEP’s method of allocation between transferors and transferees (as well as among investors whose interests otherwise vary during a taxable period).

U.S. Federal Estate Tax Consequences

If LP Units are included in the gross estate of a U.S. citizen or resident for U.S. federal estate tax purposes, then a U.S. federal estate tax might be payable in connection with the death of such person. Individual U.S. Holders should consult an independent tax adviser concerning the potential U.S. federal estate tax consequences with respect to LP Units.

Certain Reporting Requirements

A U.S. Holder who invests more than $100,000 in BEP may be required to file IRS Form 8865 reporting the investment with such U.S. Holder’s U.S. federal income tax return for the year that includes the date of the investment. A U.S. Holder may be subject to substantial penalties if it fails to comply with this and other information reporting requirements with respect to an investment in LP Units. Each U.S. Holder should consult an independent tax adviser regarding such reporting requirements.

U.S. Taxation of Tax-Exempt U.S. Holders of LP Units

Income recognized by a U.S. tax-exempt organization is exempt from U.S. federal income tax except to the extent of the organization’s UBTI. UBTI is defined generally as any gross income derived by a tax-exempt organization from an unrelated trade or business that it regularly carries on, less the deductions directly connected with that trade or business. In addition, income arising from a partnership (or other entity treated as a partnership for U.S. federal income tax purposes) that holds operating assets or is otherwise engaged in a trade or business generally will constitute UBTI. Notwithstanding the foregoing, UBTI generally does not include any dividend income, interest income, certain other categories of passive income, or capital gains realized by a tax-exempt organization, so long as such income is not “debt-financed”, as discussed below. The Managing General Partner believes that BEP should not be regarded as engaged in a trade or business, and anticipates that any operating assets held by BEP will be held through entities that are treated as corporations for U.S. federal income tax purposes.

The exclusion from UBTI does not apply to income from “debt-financed property”, which is treated as UBTI to the extent of the percentage of such income that the average acquisition indebtedness with respect to the property bears to the average tax basis of the property for the taxable year. If an entity treated as a partnership for U.S. federal income tax purposes incurs acquisition indebtedness, a tax-exempt partner in such partnership will be deemed to have acquisition indebtedness equal to its allocable portion of such acquisition indebtedness. If any such indebtedness were used by BEP or by BRELP to acquire property, such property generally would constitute debt-financed property, and any income from or gain from the disposition of such debt-financed property allocated to a tax-exempt organization generally would constitute UBTI to such tax-exempt organization. In addition, even if such indebtedness were not used either by BEP or by BRELP to acquire property but were instead used to fund distributions to LP Unitholders, if a tax-exempt organization subject to taxation in the United States were to use such proceeds to make an investment outside BEP, the IRS might assert that such investment constitutes debt-financed property to such LP Unitholder with the consequences noted above. BEP and BRELP currently do not have any outstanding indebtedness used to acquire property, and the Managing General Partner and the BRELP General Partner do not believe that BEP or BRELP will generate UBTI attributable to debt-financed property in the future. Moreover, the Managing General Partner and the BRELP General Partner intend to use commercially reasonable efforts to structure the activities of BEP and BRELP, respectively, to avoid generating income connected with the conduct of a trade or business (which income generally would constitute UBTI to the extent allocated to a tax-exempt organization). However, neither BEP nor BRELP is prohibited from incurring indebtedness, and no assurance can be provided that neither BEP nor BRELP will generate UBTI attributable to debt-financed property in the future. Tax-exempt U.S. Holders should consult an independent tax adviser regarding the tax consequences of an investment in LP Units.

Consequences to Non-U.S. Holders

Holding of LP Units and Other Considerations

Page 217

The Managing General Partner and the BRELP General Partner intend to use commercially reasonable efforts to structure the activities of BEP and BRELP, respectively, to avoid the realization by BEP and BRELP of income treated as effectively connected with a U.S. trade or business, including effectively connected income attributable to the sale of a “United States real property interest”, as defined in the U.S. Internal Revenue Code. Specifically, BEP intends not to make an investment, whether directly or through an entity which would be treated as a partnership for U.S. federal income tax purposes, if the Managing General Partner believes at the time of such investment that such investment would generate income treated as effectively connected with a U.S. trade or business. If, as anticipated, BEP is not treated as engaged in a U.S. trade or business or as deriving income which is treated as effectively connected with a U.S. trade or business, and provided that a Non-U.S. Holder is not itself engaged in a U.S. trade or business, then such Non-U.S. Holder generally will not be subject to U.S. tax return filing requirements solely as a result of owning LP Units and generally will not be subject to U.S. federal income tax on its allocable share of BEP’s interest and dividends from non-U.S. sources or gain from the sale or other disposition of securities or real property located outside of the United States.

However, there can be no assurance that the law will not change or that the IRS will not deem BEP to be engaged in a U.S. trade or business. If, contrary to the Managing General Partner’s expectations, BEP is treated as engaged in a U.S. trade or business, then a Non-U.S. Holder generally would be required to file a U.S. federal income tax return, even if no effectively connected income were allocable to it. If BEP were to have income treated as effectively connected with a U.S. trade or business, then a Non-U.S. Holder would be required to report that income and would be subject to U.S. federal income tax at the regular graduated rates. In addition, BEP generally would be required to withhold U.S. federal income tax on such Non-U.S. Holder’s distributive share of such income. A corporate Non-U.S. Holder might also be subject to branch profits tax at a rate of 30%, or at a lower treaty rate, if applicable. Under the Tax Cuts and Jobs Act, if, contrary to expectation, BEP were engaged in a U.S. trade or business, then gain or loss from the sale of LP Units by a Non-U.S. Holder would be treated as effectively connected with such trade or business to the extent that such Non-U.S. Holder would have had effectively connected gain or loss had BEP sold all of its assets at their fair market value as of the date of such sale. In such case, any such effectively connected gain generally would be taxable at the regular graduated rates, and the amount realized from such sale generally would be subject to a 10% U.S. federal withholding tax. The 10% U.S. federal withholding tax obligation temporarily is suspended with respect to the disposition of an interest in a publicly traded partnership until regulations or other guidance has been issued.

In general, even if BEP is not engaged in a U.S. trade or business, and assuming a Non-U.S. Holder is not otherwise engaged in a U.S. trade or business, such holder will nonetheless be subject to a federal withholding tax equal to 30% of the gross amount of its allocable share of certain U.S.-source income (such as dividends and interest) which is not effectively connected with a U.S. trade or business. However, the Managing General Partner does not expect BEP to earn any such U.S.-source income. Accordingly, the 30% withholding tax is not expected to apply. If, contrary to expectation, BEP were to earn such income, then a Non-U.S. Holder’s allocable share of distributions of such income generally would be subject to U.S. withholding tax at a rate of 30%, or at a lower treaty rate, if applicable. A Non-U.S. Holder might be required to take additional steps to receive a credit or refund of any excess withholding tax paid on such holder’s account, which could include the filing of a non-resident U.S. income tax return with the IRS, unless such holder were not subject to U.S. tax based on its tax status or were otherwise eligible for a reduced rate of U.S. withholding under an applicable income tax treaty. Each Non-U.S. Holder should consult an independent tax adviser regarding the potential for the 30% withholding tax to apply to its allocable share of income of BEP.

Special rules may apply in the case of any Non-U.S. Holder (i) that has an office or fixed place of business in the United States; (ii) that is present in the United States for 183 days or more in a taxable year; or (iii) that is (a) a former citizen or long-term resident of the United States, (b) a foreign insurance company that is treated as holding a partnership interest in BEP in connection with its U.S. business, (c) a PFIC, or (d) a corporation that accumulates earnings to avoid U.S. federal income tax. Each Non-U.S. Holder should consult an independent tax adviser regarding the application of these special rules.

Administrative Matters

Page 218

Information Returns and Audit Procedures

BEP has agreed to use commercially reasonable efforts to provide U.S. tax information on its website (including IRS Schedule K-1 information needed to determine an LP Unitholder’s allocable share of BEP’s income, gain, losses, and deductions) no later than 90 days after the end of BEP’s taxable year. In addition, BEP will provide an IRS Schedule K-1 to any LP Unitholder that furnishes BEP or its agents with certain basic information regarding such holder’s LP Units. To assist each LP Unitholder in this regard, BEP maintains a website in respect of 2012 and subsequent taxation years. However, providing this U.S. tax information to LP Unitholders will be subject to delay in the event of, among other reasons, the late receipt of any necessary tax information from lower-tier entities. It is therefore possible that, in any taxable year, an LP Unitholder will need to apply for an extension of time to file such LP Unitholder’s tax returns. In preparing this U.S. tax information, BEP will use various accounting and reporting conventions, some of which have been mentioned in the previous discussion, to determine an LP Unitholder’s share of income, gain, loss, and deduction. The IRS may successfully contend that certain of these reporting conventions are impermissible, which could result in an adjustment to an LP Unitholder’s income or loss.

BEP may be audited by the IRS. Adjustments resulting from an IRS audit could require an LP Unitholder to adjust a prior year’s tax liability and result in an audit of such holder’s own tax return. Any audit of an LP Unitholder’s tax return could result in adjustments not related to BEP’s tax returns, as well as those related to BEP’s tax returns. Under the Bipartisan Budget Act of 2015, for taxable years beginning after December 31, 2017, if the IRS makes an audit adjustment to BEP’s income tax returns, it may assess and collect any taxes (including penalties and interest) resulting from such audit adjustment directly from BEP instead of LP Unitholders (as under prior law). BEP may be permitted to elect to have the Managing General Partner and LP Unitholders take such audit adjustment into account in accordance with their interests in BEP during the taxable year under audit. However, there can be no assurance that BEP will choose to make such election or that it will be available in all circumstances. If BEP does not make the election, and it pays taxes, penalties, or interest as a result of an audit adjustment, then cash available for distribution to LP Unitholders might be substantially reduced. As a result, current LP Unitholders might bear some or all of the cost of the tax liability resulting from such audit adjustment, even if current LP Unitholders did not own LP Units during the taxable year under audit. The foregoing considerations also apply with respect to BEP’s interest in BRELP.

For taxable years beginning on or before December 31, 2017, the Managing General Partner will act as BEP’s “tax matters partner”. As the tax matters partner, the Managing General Partner will have the authority, subject to certain restrictions, to act on behalf of BEP in connection with any administrative or judicial review of BEP’s items of income, gain, loss, deduction, or credit. For taxable years beginning after December 31, 2017, a “partnership representative” designated by BEP will have the sole authority to act on behalf of BEP in connection with such administrative or judicial review. In particular, our partnership representative will have the sole authority to bind both our former and current LP Unitholders and to make certain elections on behalf of BEP pursuant to the Bipartisan Budget Act of 2015.

The application of the Bipartisan Budget Act of 2015 to BEP and LP Unitholders is uncertain and remains subject to Treasury Regulations and IRS guidance yet to be made final. Each LP Unitholder should consult an independent tax adviser regarding the implications of the Bipartisan Budget Act of 2015 for an investment in LP Units.

Tax Shelter Regulations and Related Reporting Requirements

If BEP were to engage in a “reportable transaction”, BEP (and possibly LP Unitholders) would be required to make a detailed disclosure of the transaction to the IRS in accordance with regulations governing tax shelters and other potentially tax-motivated transactions. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or “transaction of interest”, or that it produces certain kinds of losses exceeding certain thresholds. An investment in BEP may be considered a “reportable transaction” if, for example, BEP were to recognize certain significant losses in the future. In certain circumstances, an LP Unitholder who disposes of an interest in a transaction resulting in the recognition by such holder of significant losses in excess of certain threshold amounts may be obligated to disclose its participation in such transaction. Certain of these rules are unclear, and the scope of

Page 219

reportable transactions can change retroactively. Therefore, it is possible that the rules may apply to transactions other than significant loss transactions.

Moreover, if BEP were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, an LP Unitholder might be subject to significant accuracy-related penalties with a broad scope, for those persons otherwise entitled to deduct interest on federal tax deficiencies, non-deductibility of interest on any resulting tax liability, and in the case of a listed transaction, an extended statute of limitations. BEP does not intend to participate in any reportable transaction with a significant purpose to avoid or evade tax, nor does BEP intend to participate in any listed transactions. However, no assurance can be provided that the IRS will not assert that BEP has participated in such a transaction.

Each LP Unitholder should consult an independent tax adviser concerning any possible disclosure obligation under the regulations governing tax shelters with respect to the disposition of LP Units.

Taxable Year

BEP currently uses the calendar year as its taxable year for U.S. federal income tax purposes. Under certain circumstances which BEP currently believes are unlikely to apply, a taxable year other than the calendar year may be required for such purposes.

Backup Withholding

For each calendar year, BEP may be required to report to each LP Unitholder and to the IRS the amount of distributions that BEP pays, and the amount of tax (if any) that BEP withholds on these distributions. Under the backup withholding rules, an LP Unitholder may be subject to backup withholding tax with respect to distributions paid unless such holder: (i) is an exempt recipient and demonstrates this fact when required; or (ii) provides a taxpayer identification number, certifies as to no loss of exemption from backup withholding tax, and otherwise complies with the applicable requirements of the backup withholding tax rules. A U.S. Holder that is exempt should certify such status on a properly completed IRS Form W-9. A Non-U.S. Holder may qualify as an exempt recipient by submitting a properly completed IRS Form W-8. Backup withholding is not an additional tax. The amount of any backup withholding from a payment to an LP Unitholder will be allowed as a credit against such LP Unitholder’s U.S. federal income tax liability and may entitle such LP Unitholder to a refund from the IRS, provided the LP Unitholder supplies the required information to the IRS in a timely manner.

If an LP Unitholder does not timely provide BEP, or the applicable nominee, broker, clearing agent, or other intermediary, with IRS Form W-9 or IRS Form W-8, as applicable, or such form is not properly completed, then BEP may become subject to U.S. backup withholding taxes in excess of what would have been imposed had BEP or the applicable intermediary received properly completed forms from all LP Unitholders. For administrative reasons, and in order to maintain the fungibility of our LP Units, such excess U.S. backup withholding taxes may be treated by BEP as an expense that will be borne indirectly by all LP Unitholders on a pro rata basis (e.g., since it may be impractical for BEP to allocate any such excess withholding tax cost to our LP Unitholders that failed to timely provide the proper U.S. tax forms).

Foreign Account Tax Compliance

FATCA imposes a 30% withholding tax on “withholdable payments” made to a “foreign financial institution” or a “non-financial foreign entity”, unless such financial institution or entity satisfies certain information reporting or other requirements. Withholdable payments include certain U.S.-source income, such as interest, dividends, and other passive income. Beginning January 1, 2019, withholdable payments also include gross proceeds from the sale or disposition of property that can produce U.S.-source interest or dividends. Based on the organizational structure of BEP, as well as BEP’s expected income and assets, our Managing General Partner currently believes that BEP is unlikely to receive or to make any such “withholdable payments” subject to 30% withholding tax under FATCA. Moreover, we intend to comply with FATCA so as to ensure that the 30% withholding tax does not apply to withholdable payments, if any, received by BEP, BRELP, the Holding Entities or the Operating Entities. Nonetheless, the 30% withholding tax may apply to an LP Unitholder’s allocable share of distributions attributable to

Page 220

withholdable payments, if any, unless such LP Unitholder properly certifies its FATCA status on IRS Form W-8 or IRS Form W-9 (as applicable) and satisfies any additional requirements under FATCA.

In compliance with FATCA, information regarding certain LP Unitholders’ ownership of LP Units may be reported to the IRS or to a non-U.S. governmental authority. FATCA remains subject to modification by an applicable intergovernmental agreement between the United States and another country, such as the agreement in effect between the United States and Bermuda for cooperation to facilitate the implementation of FATCA, or by future Treasury Regulations or guidance. Each LP Unitholder should consult its own tax adviser regarding the consequences under FATCA of an investment in LP Units.

Information Reporting with Respect to Foreign Financial Assets

Under Treasury Regulations, certain U.S. persons that own “specified foreign financial assets” with an aggregate fair market value exceeding either $50,000 on the last day of the taxable year or $75,000 at any time during the taxable year generally are required to file an information report with respect to such assets with their tax returns. Significant penalties may apply to persons who fail to comply with these rules. Specified foreign financial assets include not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person, and any interest in a foreign entity. The failure to report information required under the current regulations could result in substantial penalties and in the extension of the statute of limitations with respect to federal income tax returns filed by an LP Unitholder. Each LP Unitholder should consult an independent tax adviser regarding the possible implications of these Treasury Regulations for an investment in LP Units.

Certain Effects of a Transfer of LP Units

BEP may allocate items of income, gain, loss, deduction, and credit using a monthly convention, whereby any such items recognized in a given month by BEP are allocated to LP Unitholders as of a specified date of such month. BRELP may invest in debt obligations or other securities for which the accrual of interest or income thereon is not matched by a contemporaneous receipt of cash. Any such accrued interest or other income would be allocated pursuant to such monthly convention. Consequently, LP Unitholders may recognize income in excess of cash distributions received from BEP, and any income so included by an LP Unitholder would increase the basis such LP Unitholder has in LP Units and would offset any gain (or increase the amount of loss) realized by such LP Unitholder on a subsequent disposition of its LP Units.

BRELP has invested and will continue to invest in certain Holding Entities and Operating Entities organized in non-U.S. jurisdictions, and income and gain from such investments may be subject to withholding and other taxes in such jurisdictions. If any such non-U.S. taxes were imposed on income allocable to an LP Unitholder, and such LP Unitholder were thereafter to dispose of its LP Units prior to the date distributions were made in respect of such income, under applicable provisions of the U.S. Internal Revenue Code and Treasury Regulations, the LP Unitholder to whom such income was allocated (and not the LP Unitholder to whom distributions were ultimately made) would, subject to other applicable limitations, be the party permitted to claim a credit for such non-U.S. taxes for U.S. federal income tax purposes. Thus an LP Unitholder may be affected either favorably or adversely by the foregoing rules. Complex rules may, depending on an LP Unitholder’s particular circumstances, limit the availability or use of foreign tax credits, and LP Unitholders are urged to consult an independent tax adviser regarding all aspects of foreign tax credits.

Nominee Reporting

Persons who hold an interest in BEP as a nominee for another person may be required to furnish to BEP:

i.the name, address and taxpayer identification number of the beneficial owner and the nominee;

Page 221

ii.whether the beneficial owner is (a) a person that is not a U.S. person, (b) a foreign government, an international organization, or any wholly-owned agency or instrumentality of either of the foregoing, or (c) a tax-exempt entity;

iii.the amount and description of LP Units held, acquired, or transferred for the beneficial owner; and

iv.specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions may be required to furnish additional information, including whether they are U.S. persons and specific information on LP Units they acquire, hold, or transfer for their own account. A penalty of $250 per failure (as adjusted for inflation), up to a maximum of $3,000,000 per calendar year (as adjusted for inflation), generally is imposed by the U.S. Internal Revenue Code for the failure to report such information to BEP. The nominee is required to supply the beneficial owner of LP Units with the information furnished to BEP.

New Legislation or Administrative or Judicial Action

The U.S. federal income tax treatment of LP Unitholders depends, in some instances, on determinations of fact and interpretations of complex provisions of U.S. federal income tax law for which no clear precedent or authority may be available. LP Unitholders should be aware that the U.S. federal income tax rules, particularly those applicable to partnerships, are constantly under review (including currently) by the Congressional tax-writing committees and other persons involved in the legislative process, the IRS, the U.S. Treasury Department and the courts, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to regulations and other modifications and interpretations, any of which could adversely affect the value of LP Units and be effective on a retroactive basis. For example, changes to the U.S. federal tax laws and interpretations thereof could make it more difficult or impossible for BEP to be treated as a partnership that is not taxable as a corporation for U.S. federal income tax purposes, change the character or treatment of portions of BEP’s income (including changes that recharacterize certain allocations as potentially non-deductible fees), reduce the net amount of distributions available to LP Unitholders, or otherwise affect the tax considerations of owning LP Units. Such changes could also affect or cause BEP to change the way it conducts its activities and adversely affect the value of LP Units.

BEP’s organizational documents and agreements permit the Managing General Partner to modify the limited partnership agreement of BEP from time to time, without the consent of our LP Unitholders, to elect to treat BEP as a corporation for U.S. federal tax purposes, or to address certain changes in U.S. federal income tax regulations, legislation or interpretation. In some circumstances, such revisions could have a material adverse impact on some or all LP Unitholders.

THE FOREGOING DISCUSSION IS NOT INTENDED AS A SUBSTITUTE FOR CAREFUL TAX PLANNING. THE TAX MATTERS RELATING TO BEP AND LP UNITHOLDERS ARE COMPLEX AND ARE SUBJECT TO VARYING INTERPRETATIONS. MOREOVER, THE EFFECT OF EXISTING INCOME TAX LAWS, THE MEANING AND IMPACT OF WHICH IS UNCERTAIN, AND OF PROPOSED CHANGES IN INCOME TAX LAWS WILL VARY WITH THE PARTICULAR CIRCUMSTANCES OF EACH LP UNITHOLDER, AND IN REVIEWING THIS FORM 20-F THESE MATTERS SHOULD BE CONSIDERED. EACH LP UNITHOLDER SHOULD CONSULT AN INDEPENDENT TAX ADVISER WITH RESPECT TO THE U.S. FEDERAL, STATE, LOCAL, AND OTHER TAX CONSEQUENCES OF ANY INVESTMENT IN LP UNITS.

Certain Material Canadian Federal Income Tax Considerations

The following is a summary of the principal Canadian federal income tax consequences under the Tax Act of the holding and disposition of our Units generally applicable to a Unitholder who, for purposes of the Tax Act and at all relevant times, holds our Units as capital property, deals at arm’s length with and is not affiliated with BEP, BRELP, the Managing General Partner, the BRELP General Partner, the BRELP GP LP or their respective affiliates (a “Holder”). Generally, our Units will be considered to be

Page 222

capital property to a Holder, provided that the Holder does not use or hold our Units in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure or concern in the nature of trade.

This summary is not applicable to a Holder: (i) that is a “financial institution” (as defined in the Tax Act) for purposes of the “mark-to-market” property rules; (ii) that is a “specified financial institution” (as defined in the Tax Act); (iii) who makes or has made a functional currency reporting election pursuant to section 261 of the Tax Act; (iv) an interest in which would be a “tax shelter investment” (as defined in the Tax Act) or who acquires a Unit as a “tax shelter investment” (and this summary assumes that no such persons hold our Units); (v) that has, directly or indirectly, a “significant interest” (as defined in subsection 34.2(1) of the Tax Act) in BEP; (vi) if  any affiliate of BRELP is, or becomes as part of a series of transactions that includes the acquisition of Units, a “foreign affiliate” (for purposes of the Tax Act) to such Holder or to any corporation that does not deal at arm’s length with such Holder for purposes of the Tax Act, or (vii) that has entered or will enter into a “derivative forward agreement” (as defined in the Tax Act) in respect of our Units. Any such Holders should consult their own tax advisors with respect to an investment in our Units.  This summary does not address the split income rules in Section 120.4 of the Tax Act as proposed to be amended. Holders should consult their own tax advisors in that regard.

This summary is based on the current provisions of the Tax Act, all specific proposals to amend the Tax Act publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Tax Proposals”), and the current published administrative and assessing policies and practices of the CRA. This summary assumes that all Tax Proposals will be enacted in the form proposed but no assurance can be given that the Tax Proposals will be enacted in the form proposed or at all.

This summary does not otherwise take into account or anticipate any changes in law, whether by judicial, administrative or legislative decision or action, or changes in the CRA’s administrative and assessing policies and practices, nor does it take into account provincial, territorial or foreign income tax legislation or considerations, which may differ significantly from those described herein. This summary is not exhaustive of all possible Canadian federal income tax consequences that may affect Holders. Holders should consult their own tax advisors in respect of the provincial, territorial or foreign income tax consequences to them of holding and disposing of our Units.

This summary also assumes that except for corporations that are organized in and resident in Canada, no subsidiary of BEP or BRELP will invest in any property in Canada or receive dividends, rents, interest or royalties from any Canadian resident person. However, no assurance can be given in this regard.

This summary also assumes that neither BEP nor BRELP is a “tax shelter” (as defined in the Tax Act) or a “tax shelter investment”. However, no assurance can be given in this regard.

This summary also assumes that neither BEP nor BRELP will be a “SIFT partnership” at any relevant time for purposes of the SIFT Rules on the basis that neither BEP nor BRELP will be a “Canadian resident partnership” at any relevant time. However, there can be no assurance that the SIFT Rules will not be revised or amended such that the SIFT Rules will apply.

This summary assumes that no payments to a Holder in respect of any Preferred Units are made by the Preferred Unit Guarantors pursuant to the Preferred Unit Guarantees

This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any particular Holder, and no representation with respect to the Canadian federal income tax consequences to any particular Holder is made. Consequently, Holders are advised to consult their own tax advisors with respect to their particular circumstances. See also Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

For purposes of the Tax Act, all amounts relating to the acquisition, holding or disposition of our Units must be expressed in Canadian dollars including any distributions, adjusted cost base and proceeds of disposition. For purposes of the Tax Act, amounts denominated in a currency other than the Canadian dollar generally must be converted into Canadian dollars using the appropriate exchange rate determined in accordance with the detailed rules in the Tax Act in that regard. 

Taxation of Holders Resident in Canada

Page 223

The following portion of the summary is generally applicable to a Holder who, for purposes of the Tax Act and at all relevant times, is resident or deemed to be resident in Canada (a “Resident Holder”).  

Computation of Income or Loss

Each Resident Holder is required to include (or, subject to the “at-risk rules” discussed below, entitled to deduct) in computing his or her income for a particular taxation year the Resident Holder’s share of BEP’s income (or loss) for its fiscal year ending in, or coincidentally with, the Resident Holder’s taxation year end, whether or not any of that income is distributed to the Resident Holder in the taxation year and regardless of whether or not our Units were held throughout such year.

BEP will not itself be a taxable entity and is not expected to be required to file an income tax return in Canada for any taxation year. However, BEP’s income (or loss) for a fiscal period for purposes of the Tax Act will be computed as if BEP were a separate person resident in Canada and the partners will be allocated a share of that income (or loss) in accordance with the Amended and Restated Limited Partnership Agreement of BEP. BEP’s income (or loss) will include its share of the income (or loss) of BRELP for a fiscal year determined in accordance with the Amended and Restated Limited Partnership Agreement of BRELP. For this purpose, BEP’s fiscal year end and that of BRELP will be December 31.

BEP’s income for tax purposes for a given fiscal year will be allocated to each Resident Holder in an amount calculated by multiplying such income that is allocable to Unitholders by a fraction, the numerator of which is the sum of the distributions received by such Resident Holder with respect to such fiscal year and the denominator of which is the aggregate amount of the distributions made by BEP to all Unitholders with respect to such fiscal year, subject to adjustment in respect of distributions on the Preferred Units that are in satisfaction of accrued distributions on the Preferred Units that were not paid in a previous fiscal year of our partnership where the Managing General Partner determines that the allocation to Preferred Unitholders based on such distributions would result in a Preferred Unitholder being allocated more income than it would have been if the distributions were paid in the fiscal year of BEP in which they were accrued.

If, with respect to a given fiscal year, no distribution is made by BEP to Unitholders or BEP has a loss for tax purposes, one quarter of the income, or loss, as the case may be, for tax purposes for such fiscal year that is allocable to our Unitholders will be allocated to the Resident Holders of record at the end of each calendar quarter ending in such fiscal year as follows: (i) to the Preferred Unitholders in respect of the Preferred Units held by them on each such date, such amount of BEP’s income or loss for tax purposes, as the case may be, as the Managing General Partner determines is reasonable in the circumstances having regard to such factors as the Managing General Partner considers to be relevant, including, without limitation, the relative amount of capital contributed to our partnership on the issuance of Preferred Units as compared to all other Units and the relative fair market value of the Preferred Units, as the case may be, as compared to all other Units, and (ii) to the Unitholders other than in respect of the Preferred Units, the remaining amount of our partnership’s income or loss for tax purposes, as the case may be, in accordance with their respective percentage interests.

BEP’s income as determined for purposes of the Tax Act may differ from its income as determined for accounting purposes and may not be matched by cash distributions. The above allocations of income for Canadian tax purposes are subject to a special allocation of income for Canadian tax purposes, that would allocate to Brookfield or certain of its affiliates for Canadian income tax purposes only, a portion of certain gains recognized in respect of a disposition of shares of NA Holdco which will reduce, to the extent provided in the relevant partnership agreement, the income for Canadian tax purposes, if any, allocated to Unitholders associated with such gains, if any. In addition, for purposes of the Tax Act, all income (or losses) of BEP and BRELP must be calculated in Canadian currency. Where BEP (or BRELP) holds investments denominated in U.S. dollars or other foreign currencies, gains and losses may be realized by BEP as a consequence of fluctuations in the relative values of the Canadian and foreign currencies.

In computing BEP’s income (or loss), deductions may be claimed in respect of reasonable administrative costs, interest and other expenses incurred by BEP for the purpose of earning income, subject to the relevant provisions of the Tax Act. BEP may also deduct from its income for the year a portion of the reasonable expenses, if any, incurred by BEP to issue our Units. The portion of such issue

Page 224

expenses deductible by BEP in a taxation year is 20% of such issue expenses, pro-rated where BEP’s taxation year is less than 365 days. BEP and BRELP may be required to withhold and remit Canadian federal withholding tax on any management or administration fees or charges paid or credited to a non-resident person, to the extent that such management or administration fees or charges are deductible in computing BEP’s or BRELP’s income from a source in Canada.

In general, a Resident Holder’s share of BEP’s income (or loss) from a particular source will be treated as if it were income (or loss) of the Resident Holder from that source, and any provisions of the Tax Act applicable to that type of income (or loss) will apply to the Resident Holder. BEP will invest in limited partnership units of BRELP. In computing BEP’s income (or loss) under the Tax Act, BRELP will itself be deemed to be a separate person resident in Canada which computes its income (or loss) and allocates to its partners their respective share of such income (or loss). Accordingly, the source and character of amounts included in (or deducted from) the income of Resident Holders on account of income (or loss) earned by BRELP generally will be determined by reference to the source and character of such amounts when earned by BRELP.

A Resident Holder’s share of taxable dividends received or considered to be received by BEP in a fiscal year from a corporation resident in Canada will be treated as a dividend received by the Resident Holder and will be subject to the normal rules in the Tax Act applicable to such dividends, including the enhanced gross-up and dividend tax credit for “eligible dividends” (as defined in the Tax Act) when the dividend received by BRELP is designated as an “eligible dividend”.

Foreign taxes paid by BEP or BRELP and taxes withheld at source on amounts paid or credited to BEP or BRELP (other than for the account of a particular partner) will be allocated pursuant to the governing partnership agreement. Each Resident Holder’s share of the “business-income tax” and “non-business-income tax” paid to the government of a foreign country for a year will be creditable against its Canadian federal income tax liability to the extent permitted by the detailed foreign tax credit rules contained in the Tax Act. Although the foreign tax credit rules are designed to avoid double taxation, the maximum credit is limited. Because of this, and because of timing differences in recognition of expenses and income and other factors, the foreign tax credit rules may not provide a full foreign tax credit for the “business-income tax” and “non-business-income tax” paid by BEP or BRELP to the government of a foreign country. The Tax Act contains anti-avoidance rules to address certain foreign tax credit generator transactions. Under the Foreign Tax Credit Generator Rules, the foreign “business-income tax” or “non-business-income tax” allocated to a Resident Holder for the purpose of determining such Resident Holder’s foreign tax credit for any taxation year may be limited in certain circumstances, including where a Resident Holder’s share of BEP or BRELP’s income under the income tax laws of any country (other than Canada) under whose laws the income of BEP or BRELP is subject to income taxation (the “Relevant Foreign Tax Law”) is less than the Resident Holder’s share of such income for purposes of the Tax Act. For this purpose, a Resident Holder is not considered to have a lesser direct or indirect share of the income of BEP or BRELP under the Relevant Foreign Tax Law than for the purposes of the Tax Act solely because, among other reasons, of a difference between the Relevant Foreign Tax Law and the Tax Act in the manner of computing the income of BEP or BRELP or in the manner of allocating the income of BEP or BRELP because of the admission or withdrawal of a partner. No assurance can be given that the Foreign Tax Credit Generator Rules will not apply to any Resident Holder. If the Foreign Tax Credit Generator Rules apply, the allocation to a Resident Holder of foreign “business-income tax” or “non-business-income tax” paid by BEP or BRELP, and therefore such Resident Holder’s foreign tax credits, will be limited.

BEP and BRELP will each be deemed to be a non-resident person in respect of certain amounts paid or credited or deemed to be paid or credited to them by a person resident or deemed to be resident in Canada, including dividends or interest. Dividends or interest (other than interest not subject to Canadian federal withholding tax) paid or deemed to be paid by a person resident or deemed to be resident in Canada to BRELP will be subject to withholding tax under Part XIII of the Tax Act at the rate of 25%. However, the CRA’s administrative practice in similar circumstances is to permit the rate of Canadian federal withholding tax applicable to such payments to be computed by looking through the partnership and taking into account the residency of the partners (including partners who are resident in Canada) and any reduced rates of Canadian federal withholding tax that any non-resident partners may be entitled to under an applicable income tax treaty or convention, provided that the residency status and

Page 225

entitlement to the treaty benefits can be established. In determining the rate of Canadian federal withholding tax applicable to amounts paid by the Holding Entities to BRELP, the Managing General Partner and the BRELP General Partner expect the Holding Entities to look-through BRELP and BEP to the residency of BEP’s partners (including partners who are resident in Canada) and to take into account any reduced rates of Canadian federal withholding tax that non-resident partners may be entitled to under an applicable income tax treaty or convention in order to determine the appropriate amount of Canadian federal withholding tax to withhold from dividends or interest paid to BRELP. However, there can be no assurance that the CRA will  apply its administrative practice in this context. Under the Treaty, a Canadian-resident payer is required in certain circumstances to look-through fiscally transparent partnerships, such as BEP and BRELP, to the residency and Treaty entitlements of their partners and to take into account the reduced rates of Canadian federal withholding tax that such partners may be entitled to under the Treaty. Under the Amended and Restated Limited Partnership Agreement of BEP, the amount of any taxes withheld or paid by BEP, BRELP or the Holding Entities in respect of our Units may be treated either as a distribution to our Unitholders or as a general expense of BEP, as determined by the Managing General Partner in its sole discretion. However, the Managing General Partner’s current intention is to treat all such amounts as a distribution to our Unitholders.

If BEP incurs losses for tax purposes, each Resident Holder will be entitled to deduct in the computation of income for tax purposes the Resident Holder’s share of any net losses for tax purposes of BEP for its fiscal year to the extent that the Resident Holder’s investment is “at-risk” within the meaning of the Tax Act. The Tax Act contains “at-risk rules” which may, in certain circumstances, restrict the deduction of a limited partner’s share of any losses of a limited partnership. The Managing General Partner and the BRELP General Partner do not anticipate that BEP or BRELP will incur losses but no assurance can be given in this regard. Accordingly, Resident Holders should consult their own tax advisors for specific advice with respect to the potential application of the “at-risk rules”.

Section 94.1 of the Tax Act contains rules relating to interests held by a taxpayer in Non-Resident Entities that could, in certain circumstances, cause income to be imputed to Resident Holders, either directly or by way of allocation of such income imputed to BEP or BRELP. These rules would apply if it is reasonable to conclude, having regard to all the circumstances, that one of the main reasons for the Resident Holder, BEP or BRELP acquiring, holding or having an investment in a Non-Resident Entity is to derive a benefit from “portfolio investments” in certain assets from which the Non-Resident Entity may reasonably be considered to derive its value in such a manner that taxes under the Tax Act on income, profits and gains from such assets for any year are significantly less than they would have been if such income, profits and gains had been earned directly. In determining whether this is the case, section 94.1 of the Tax Act provides that consideration must be given to, among other factors, the extent to which the income, profits and gains for any fiscal period are distributed in that or the immediately following fiscal period. No assurance can be given that section 94.1 of the Tax Act will not apply to a Resident Holder, BEP or BRELP. If these rules apply to a Resident Holder, BEP or BRELP, income, determined by reference to a prescribed rate of interest plus two percent applied to the “designated cost”, as defined in section 94.1 of the Tax Act, of the interest in the Non-Resident Entity, will be imputed directly to the Resident Holder or to BEP or BRELP and allocated to the Resident Holder in accordance with the rules in section 94.1 of the Tax Act. The rules in section 94.1 of the Tax Act are complex and Resident Holders should consult their own tax advisors regarding the application of these rules to them in their particular circumstances.

Any Non-Resident Subsidiaries in which BRELP directly invests are expected to be CFAs of BRELP. Dividends paid to BRELP by a CFA of BRELP will be included in computing the income of BRELP. To the extent that any CFA or Indirect CFA of BRELP earns income that is characterized as FAPI in a particular taxation year of the CFA or Indirect CFA, the FAPI allocable to BRELP under the rules in the Tax Act must be included in computing the income of BRELP for Canadian federal income tax purposes for the fiscal period of BRELP in which the taxation year of that CFA or Indirect CFA ends, whether or not BRELP actually receives a distribution of that FAPI. BEP will include its share of such FAPI of BRELP in computing its income for Canadian federal income tax purposes and Resident Holders will be required to include their proportionate share of such FAPI allocated from BEP in computing their income for Canadian federal income tax purposes. As a result, Resident Holders may be required to include amounts in their income even though they have not and may not receive an actual cash

Page 226

distribution of such amounts. If an amount of FAPI is included in computing the income of BRELP for Canadian federal income tax purposes, an amount may be deductible in respect of the “foreign accrual tax” applicable to the FAPI. Any amount of FAPI included in income net of the amount of any deduction in respect of “foreign accrual tax” will increase the adjusted cost base to BRELP of its shares of the particular CFA in respect of which the FAPI was included. At such time as BRELP receives a dividend of this type of income that was previously included in BRELP’s income as FAPI, such dividend will effectively not be included in computing the income of BRELP and there will be a corresponding reduction in the adjusted cost base to BRELP of the particular CFA shares. Under the Foreign Tax Credit Generator Rules, the “foreign accrual tax” applicable to a particular amount of FAPI included in BRELP’s income in respect of a particular “foreign affiliate” of BRELP may be limited in certain specified circumstances, including where the direct or indirect share of the income of any member of BRELP (which is deemed for this purpose to include a Resident Holder) that is a person resident in Canada or a “foreign affiliate” of such a person is, under a Relevant Foreign Tax Law, less than such member’s share of such income for purposes of the Tax Act. No assurance can be given that the Foreign Tax Credit Generator Rules will not apply to BRELP. For this purpose, a Resident Holder is not considered to have a lesser direct or indirect share of the income of BRELP under the Relevant Foreign Tax Law than for the purposes of the Tax Act solely because, among other reasons, of a difference between the Relevant Foreign Tax Law and the Tax Act in the manner of computing the income of BRELP or in the manner of allocating the income of BRELP because of the admission or withdrawal of a partner. If the Foreign Tax Credit Generator Rules apply, the “foreign accrual tax” applicable to a particular amount of FAPI included in BRELP’s income in respect of a particular “foreign affiliate” of BRELP will be limited.

Disposition of Units

The disposition (or deemed disposition) by a Resident Holder of a Unit will result in the realization of a capital gain (or capital loss) by such Resident Holder in the amount, if any, by which the proceeds of disposition of such Unit, less any reasonable costs of disposition, exceed (or are exceeded by) the adjusted cost base of such Unit.

Subject to the general rules on averaging of cost base, the adjusted cost base of each class or series of a Resident Holder’s Units would generally be equal to: (i) the actual cost of such class or series of Units (excluding any portion thereof financed with limited recourse indebtedness); plus (ii) the share of BEP’s income allocated to the Resident Holder for BEP’s fiscal years ending before the relevant time in respect of the particular class or series of Units; less (iii) the aggregate of the share of BEP’s losses allocated to the Resident Holder (other than losses which cannot be deducted because they exceed the Resident Holder’s “at-risk” amount) for BEP’s fiscal years ending before the relevant time in respect of the particular class or series of Units; and less (iv) the Resident Holder’s distributions received from BEP before the relevant time in respect of the particular class or series of Units.

The foregoing discussion of the calculation of the adjusted cost base assumes that our LP Units and Preferred Units are treated as separate property for purposes of the Tax Act. However, the CRA’s position is to treat all the different types of interests in a partnership that a partner may hold as one capital property, including for purposes of determining the adjusted cost base of all such partnership interests. As a result, on a disposition of a particular type of unit, a partner’s total adjusted cost base is required to be allocated in a reasonable manner to the particular type of unit being disposed of. As acknowledged by the CRA, there is no particular method for determining a reasonable allocation of the adjusted cost base of a partnership interest to the part of the partnership interest that is disposed of. Furthermore, more than one method may be reasonable. If the CRA’s position applies, on a disposition by a Resident Holder of our Units, the Resident Holder should generally be able to allocate his or her adjusted cost base in a manner that treats the LP Units and Preferred Units as separate property. Accordingly, the Managing General Partner intends to provide Unitholders with partnership information returns using such allocation.

Where a Resident Holder disposes of all of its Units in BEP, it will no longer be a partner of BEP. If, however, a Resident Holder is entitled to receive a distribution from BEP after the disposition of all such Units, then the Resident Holder will be deemed to dispose of our Units at the later of: (i) the end of BEP’s fiscal year during which the disposition occurred; and (ii) the date of the last distribution made by BEP to which the Resident Holder was entitled. The share of BEP’s income (or loss) for tax purposes for a particular fiscal year which is allocated to a Resident Holder who has ceased to be a partner will

Page 227

generally be added (or deducted) in the computation of the adjusted cost base of the Resident Holder’s Units immediately prior to the time of the disposition.

A Resident Holder will generally realize a deemed capital gain if, and to the extent that, the adjusted cost base of the Resident Holder’s Units is negative at the end of any fiscal year of BEP. In such a case, the adjusted cost base of the Resident Holder’s Units will be nil at the beginning of BEP’s next fiscal year.

Canadian Holders should consult their own tax advisors for advice with respect to the specific tax consequences to them of disposing of our Units.

Taxation of Capital Gains and Capital Losses

In general, one-half of a capital gain realized by a Resident Holder must be included in computing such Resident Holder’s income as a taxable capital gain. One-half of a capital loss is deducted as an allowable capital loss against taxable capital gains realized in the year and any remainder may be deducted against net taxable capital gains in any of the three years preceding the year or any year following the year to the extent and under the circumstances described in the Tax Act.

Special rules in the Tax Act may apply to disallow the one-half treatment on all or a portion of a capital gain realized on a disposition of Units if a partnership interest is acquired by a tax-exempt person or a non-resident person (or by a partnership or trust (other than certain trusts) of which a tax-exempt person or a non-resident person is a member or beneficiary, directly or indirectly through one or more partnerships or trusts (other than certain trusts)). The Managing General Partner and the BRELP General Partner do not expect these rules to apply to any disposition of Units. Resident Holders contemplating such a disposition should consult their own tax advisors in this regard.

A Resident Holder that is throughout the relevant taxation year a “Canadian-controlled private corporation” (as defined in the Tax Act) may be liable to pay an additional refundable tax on its “aggregate investment income” (as defined in the Tax Act) for the year, which is defined to include taxable capital gains.

Eligibility for Investment

Provided that our Units are listed on a “designated stock exchange” (which currently includes the NYSE and the TSX), our Units will  be “qualified investments” under the Tax Act for a trust governed by an  RRSP, deferred profit sharing plan, RRIF, RESP, RDSP, and a TFSA.

Notwithstanding the foregoing, a holder of a TFSA or an RDSP, a subscriber of an RESP or an annuitant under an RRSP or RRIF, as the case may be, will be subject to a penalty tax if our Units are a “prohibited investment” (as defined in the Tax Act) for the TFSA, RDSP, RESP, RRSP or RRIF.  Our Units generally will not be a “prohibited investment” on the date hereof if the holder of the TFSA or RDSP, the subscriber of the RESP or the annuitant under the RRSP or RRIF, as applicable:  (i) deals at arm’s length for the purposes of the Tax Act with BEP;  and (ii) does not have a “significant interest” (as defined in the Tax Act for purposes of the “prohibited investment” rules) in BEP.

Holders who hold our Units in a TFSA, RDSP, RESP, RRSP or RRIF should consult their own tax advisors regarding the application of the foregoing “prohibited investment” rules having regard to their particular circumstances.

Alternative Minimum Tax

Resident Holders that are individuals or trusts may be subject to the alternative minimum tax rules. Such Resident Holders should consult their own tax advisors.

Holders Not Resident in Canada

The following portion of the summary is generally applicable to a Holder who, for purposes of the Tax Act and at all relevant times, is not, and is not deemed to be, resident in Canada and who does not use or hold and is not deemed to use or hold its Units in connection with a business carried on in Canada (a “Non-Resident Holder”).  

Page 228

The following portion of the summary assumes that (i) our Units are not, and will not at any relevant time constitute, “taxable Canadian property” of any Non-Resident Holder and (ii) BEP and BRELP will not dispose of property that is “taxable Canadian property”. “Taxable Canadian property” includes, but is not limited to, property that is used or held in a business carried on in Canada and shares of corporations that are not listed on a “designated stock exchange” if more than 50% of the fair market value of the shares is derived from certain Canadian properties in  the 60-month period immediately preceding the particular time. In general, our Units will not constitute “taxable Canadian property” of any Non-Resident Holder at the time of disposition or deemed disposition, unless (a) at any time in the 60-month period immediately preceding the disposition or deemed disposition, more than 50% of the fair market value of our Units was derived, directly or indirectly (excluding through a corporation, partnership or trust, the shares or interests in which were not themselves “taxable Canadian property”), from one or any combination of (i) real or immovable property situated in Canada; (ii) “Canadian resource properties”; (iii) “timber resource properties”;  and (iv) options in respect of, or interests in, or for civil law rights in, such property, whether or not such property exists, or (b) our Units are otherwise deemed to be “taxable Canadian property”. Since BEP’s assets will consist principally of units of BRELP, our Units would generally be “taxable Canadian property” at a particular time if the units of BRELP held by BEP derived, directly or indirectly (excluding through a corporation, partnership or trust, the shares or interests in which were not themselves “taxable Canadian property”), more than 50% of their fair market value from properties described in (i) to (iv) above, at any time in the 60-month period preceding the particular time. The Managing General Partner and the BRELP General Partner do not expect our Units to be “taxable Canadian property” of any Non-Resident Holder and they do not expect BEP or BRELP to dispose of “taxable Canadian property”. However, no assurance can be given in these regards. See Item 3.D “Risk Factors — Risks Related to Taxation — Canada”.

The following portion of the summary also assumes that neither BEP nor BRELP will be considered to carry on business in Canada. The Managing General Partner and the BRELP General Partner intend to organize and conduct the affairs of each of these entities, to the extent possible, so that neither of these entities should be considered to carry on business in Canada for purposes of the Tax Act. However, no assurance can be given in this regard. If BEP or BRELP carry on business in Canada, the tax implications to BEP or the BRELP and to Non-Resident Holders may be materially and adversely different than as set out herein.

Special rules, which are not discussed in this summary, may apply to a Non-Resident Holder that is an insurer carrying on business in Canada and elsewhere.

Taxation of Income or Loss

A Non-Resident Holder will not be subject to Canadian federal income tax under Part I of the Tax Act on its share of income from a business carried on by BEP (or BRELP) outside Canada or the non-business income earned by BEP (or BRELP) from sources in Canada. However, a Non-Resident Holder may be subject to Canadian federal withholding tax under Part XIII of the Tax Act, as described below.

BEP and BRELP will each be deemed to be a non-resident person in respect of certain amounts paid or credited or deemed to be paid or credited to them by a person resident or deemed to be resident in Canada, including dividends or interest. Dividends or interest (other than interest not subject to Canadian federal withholding tax) paid or deemed to be paid by a person resident or deemed to be resident in Canada to BRELP will be subject to withholding tax under Part XIII of the Tax Act at the rate of 25%. However, the CRA’s administrative practice in similar circumstances is to permit the rate of Canadian federal withholding tax applicable to such payments to be computed by looking through the partnership and taking into account the residency of the partners (including partners who are resident in Canada) and any reduced rates of Canadian federal withholding tax that any non-resident partners may be entitled to under an applicable income tax treaty or convention, provided that the residency status and entitlement to the treaty benefits can be established. In determining the rate of Canadian federal withholding tax applicable to amounts paid by the Holding Entities to BRELP, the Managing General Partner and the BRELP General Partner expect the Holding Entities to look-through BRELP and BEP to the residency of BEP’s partners (including partners who are resident in Canada) and to take into account any reduced rates of Canadian federal withholding tax that non-resident partners may be entitled to under an applicable income tax treaty or convention in order to determine the appropriate amount of Canadian

Page 229

federal withholding tax to withhold from dividends or interest paid to BRELP. However, there can be no assurance that the CRA will  apply its administrative practice in this context. Under the Treaty, a Canadian-resident payer is required in certain circumstances to look through fiscally transparent partnerships, such as BEP and BRELP, to the residency and Treaty entitlements of their partners and take into account the reduced rates of Canadian federal withholding tax that such partners may be entitled to under the Treaty. Under the Amended and Restated Limited Partnership Agreement of BEP, the amount of any taxes withheld or paid by BEP, BRELP or the Holding Entities in respect of our Units may be treated either as a distribution to our Unitholders or as a general expense of BEP, as determined by the Managing General Partner in its sole discretion. However, the Managing General Partner’s current intention is to treat all such amounts as a distribution to our Unitholders.

Bermuda Tax Considerations

As a Bermuda exempted limited partnership and under current Bermuda law, neither BEP nor BRELP is subject to tax on profits, income or dividends, nor is there any capital gains tax, estate duty or death duty in Bermuda.

Furthermore, each of BEP and BRELP has received an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 (as amended), that in the event that Bermuda enacts any legislation imposing tax computed on profits, income, any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, each of BEP and BRELP and none of its operations or its shares, debentures or other obligations shall be exempt from the imposition of such tax until 31 March 2035, provided that such exemption shall not prevent the application of any tax payable in accordance with the provisions of the Land Tax Act, 1967 or otherwise payable in relation to land in Bermuda leased to BEP or BRELP.

10.F            DIVIDENDS AND PAYING AGENTS

Not applicable.

10.G            STATEMENT OF EXPERTS

Not applicable.

10.H            DOCUMENTS ON DISPLAY

Any statement in this Form 20-F about any of our contracts or other documents is not necessarily complete. If the contract or document is filed as an exhibit to this Form 20-F the contract or document is deemed to modify the description contained in this Form 20-F. You must review the exhibits themselves for a complete description of the contract or document.

As a foreign private issuer under the SEC’s regulations, we will file annual reports on a Form 20-F and other reports on Form 6-K. The information disclosed in our reports may be less extensive than that required to be disclosed in annual and quarterly reports on Forms 10-K and 10-Q required to be filed with the SEC by U.S. issuers. Moreover, as a foreign private issuer, we will not be subject to the proxy requirements under Section 14 of the Exchange Act, and our directors and principal shareholders are not subject to the insider short swing profit reporting and recovery rules under Section 16 of the Exchange Act.

            The contracts and other documents referred to in this Form 20-F, and our SEC filings are and will be available on our EDGAR profile at www.sec.gov, respectively. You may also read and copy any document Brookfield Renewable files with the SEC at the public reference facilities maintained by the SEC at SEC Headquarters, Public Reference Section, 100 F Street, N.E., Washington D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330.

In addition, Brookfield Renewable is required to file documents required by Canadian securities laws electronically with Canadian securities regulatory authorities and these filings are available on Brookfield Renewable’s SEDAR profile at www.sedar.com. Written requests for such documents should be directed to our Corporate Secretary at 73 Front Street, 5th Floor, Hamilton, HM 12, Bermuda, +441-294-3304.

Page 230

10.I             SUBSIDIARY INFORMATION

Not applicable.

ITEM 11.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                  

See the information contained in this Form 20-F under Item 5.A “Operating Results — Risk Management and Financial Instruments”.

ITEM 12.     DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES     

Not applicable.

Page 231

PART II

ITEM 13.     DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES   

None.

ITEM 14.     MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS   

Not applicable.

ITEM 15.     CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), as of the end of the period covered by this Form 20-F. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2017, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that material information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. While disclosure controls and procedures and internal controls over financial reporting were adequate and effective we continue to implement certain measures to strengthen control processes and procedures.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. Under the supervision and with the participation of our management, including persons performing the functions of principal executive and principal financial officers for us, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2017, based on the criteria set forth in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on evaluation under the foregoing, our management concluded that our internal control over financial reporting was effective as of December 31, 2017. Management excluded from its design and assessment of internal control over financial reporting the internal controls of the 16 MW Shantavny wind project in Northern Ireland and TerraForm Global both of which were acquired in 2017, whose total assets, net assets on a combined basis constitute approximately 7% and 5%, respectively, of the consolidated financial statement amounts as of December 31, 2017 and nil% of revenues and net income, for the year then ended.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Report of Independent Registered Public Accounting Firm

The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by Ernst & Young LLP, Chartered Professional Accountants, Licensed Public Accountants, who have also audited our consolidated financial statements, as stated in their reports which are included herein.

Page 232

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Changes in Internal Control

There was no change in our internal control over financial reporting during the year ended December 31, 2017, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16.     [RESERVED]       

16.A            AUDIT COMMITTEE FINANCIAL EXPERT

Our Managing General Partner’s board of directors has determined that Patricia Zuccotti possesses specific accounting and financial management expertise and that she is the audit committee financial expert as defined by the SEC, and that she is independent within the meaning of the rules of the NYSE. Our Managing General Partner’s board of directors has also determined that other members of the Audit Committee have sufficient experience and ability in finance and compliance matters to enable them to adequately discharge their responsibilities.

16.B            CODE OF ETHICS

Brookfield Renewable has adopted a Code of Business Conduct and Ethics that applies to the members of the board of directors of our Managing General Partner, our partnership and any officers or employees of our Managing General Partner. The Code has been updated as of November 2016 and we have posted a copy of the current Code on our website at https://bep.brookfield.com/en/corporate-governance/governance-documents.

16.C            PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our Managing General Partner has retained Ernst & Young LLP to act as our partnership’s independent registered chartered accountants.

The table below summarizes the fees for professional services rendered by Ernst & Young LLP for the audit of our annual financial statements for the years ended December 31, 2017, 2016, and 2015. A majority of the fees to Ernst & Young are billed and settled in Canadian dollars. In order to provide comparability with BEP’s financial statements, which are reported in U.S. dollars, all Canadian dollar amounts in the table have been converted to U.S. dollars at an average rate as follows:  2017: C$1.00 = US$0.77, 2016: C$1.00 = US$0.75, and 2015: C$1.00 = US$0.78.

$ THOUSANDS	2017	2016	2015
Audit Fees (1)	8,198	6,668	6,759
Audit-related fees (2)	862	932	518
Tax fees (3)	84	38	140
	9,144	7,638	7,417

⁽¹⁾Audit fees include fees for the audit of our annual consolidated financial statements, internal control over financing reporting and interim reviews of the consolidated financial statements included in our quarterly interim reports.  This fee also includes fees for the audit or review of financial statements for certain of our subsidiaries, including audits of individual assets to comply with lender, joint venture partner or regulatory requirements.

⁽²⁾Audit-related fees relate primarily to services pertaining to financial due diligence, capital market transactions, Sarbanes-Oxley readiness activities, Form 20-F and other securities related matters. Audit-related fees also include other services.

⁽³⁾Includes professional services related to tax compliance, tax advice and tax planning in connection with domestic and foreign operations and corresponding tax implications.

The Audit Committee of our Managing General Partner pre-approves all audit and non-audit services provided to our partnership by Ernst & Young LLP.

Page 233

16.D            EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEE

None.

16.E            PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

BEP Repurchases

BEP may from time-to-time, subject to applicable law, purchase LP Units for cancellation in the open market, provided that any necessary approval has been obtained. In December 2017, the TSX accepted a notice of BEP’s intention to renew its normal course issuer bid, which permitted BEP to repurchase up to 9,000,000 issued and outstanding LP Units. The price to be paid for our LP Units under the normal course issuer bid was the market price at the time of purchase. The actual number of LP Units to be purchased and the timing of such purchases will be determined by BEP, and all purchases were made through the facilities of the TSX or the NYSE. Repurchases were authorized to commence on December 29, 2017 and required to terminate on December 28, 2018 or earlier should BEP have completed its repurchases prior to such date. For the year ended December 31, 2017, BEP made no repurchases.

Issuer Purchases of Equity Securities
Period	(a) Total Number  of LP  Units Purchased	(b) Average Price Paid per LP Unit	(c) Total Number of LP Units Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of LP Units that May Yet Be Purchased Under the Plans or Programs
December 29, 2016 to December 28, 2017	Nil	Nil	Nil	8,300,000

BRP Equity Repurchases

In June 2017, the TSX accepted a notice of BRP Equity’s intention to renew its normal course issuer bid in connection with its outstanding Class A Preference Shares, which permits BRP Equity to repurchase up to 10% of the total public float of each series of the Class A Preference Shares.   Repurchases were authorized to commence on June 27, 2017 and the bid will expire on June 26, 2018 or earlier should BRP Equity complete its repurchases prior to such date. For the year ended December 31, 2017, BRP Equity made no repurchases.

Page 234

Issuer Purchases of Equity Securities
Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share	(c) Total number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1, 2017 to June 26, 2017	Series 1	Nil	Nil	Nil	544,887
	Series 2	Nil	Nil	Nil	451,038
	Series 3	Nil	Nil	Nil	996,139
	Series 5	Nil	Nil	Nil	411,450
	Series 6	Nil	Nil	Nil	700,000
June 27, 2017 to December 31, 2017	Series 1	Nil	Nil	Nil	544,887
	Series 2	Nil	Nil	Nil	451,038
	Series 3	Nil	Nil	Nil	996,139
	Series 5	Nil	Nil	Nil	411,450
	Series 6	Nil	Nil	Nil	700,000

16.F            CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

None.

16.G            CORPORATE GOVERNANCE

Our corporate practices are not materially different from those required of domestic limited partnerships under the NYSE listing standards.

16.H            MINE SAFETY DISCLOSURE

Not applicable.

PART III

ITEM 17.     FINANCIAL STATEMENTS          

Not applicable.

ITEM 18.     FINANCIAL STATEMENTS          

See our financial statements beginning on page F-1, which are filed as part of this Form 20-F.

ITEM 19.     EXHIBITS

Page 235

Number	Description
1.1	Certificate of Registration of Brookfield Renewable Energy Partners L.P., dated June 29, 2011.(1)
1.2	Certificate of Deposit of Supplementary Certificate of Brookfield Renewable Energy Partners L.P., dated August 29, 2011.(1)
1.3	Certificate of Deposit of Supplementary Certificate of Brookfield Renewable Energy Partners L.P., dated December 21, 2011.(1)
1.4	Certificate of Deposit of Supplementary Certificate of Brookfield Renewable Energy Partners L.P., dated May 11, 2012.(1)
1.5	Certificate of Deposit of Supplementary Certificate of Brookfield Renewable Partners L.P., dated May 4, 2016.(6)
1.6	Certificate of Deposit of Memorandum of Increase of Share Capital, dated November 23, 2011.(1)
1.7	Fourth Amended and Restated Limited Partnership Agreement of Brookfield Renewable Partners L.P., dated May 3, 2016.(7)
1.8	First Amendment to the Fourth Amended and Restated Limited Partnership Agreement of Brookfield Renewable Partners L.P., dated May 25, 2016.(8)
1.9	Second Amendment to the Fourth Amended and Restated Limited Partnership Agreement of Brookfield Renewable Partners L.P., dated February 14, 2017.(10)
1.10	Third Amendment to the Fourth Amended and Restated Limited Partnership Agreement of Brookfield Renewable Partners L.P., dated January 16, 2018.(11)
1.11	Articles of Incorporation of Brookfield Renewable Partners Limited.(1)
1.12	Form 13 Amending the Registered Office of Brookfield Renewable Partners Limited.(1)
1.13	Bye-laws of Brookfield Renewable Partners Limited.(5)
4.1	Third Amended and Restated Limited Partnership Agreement of Brookfield Renewable Energy L.P., dated February 11, 2016.(4)
4.2	First Amendment to the Third Amended and Restated Limited Partnership Agreement of Brookfield Renewable Energy L.P., dated May 25, 2016.(8)
4.3	Second Amendment to the Third Amended and Restated Limited Partnership Agreement of Brookfield Renewable Energy L.P., dated February 14, 2017.(10)
4.4	Third Amendment to the Third Amended and Restated Limited Partnership Agreement of Brookfield Renewable Energy L.P., dated January 16, 2018.(11)
4.5	Amended and Restated Master Services Agreement, dated February 26, 2015, by and among Brookfield Asset Management Inc., Brookfield Renewable Energy Partners L.P., Brookfield Renewable Energy L.P., and others.(2)
4.6	Relationship Agreement, dated November 28, 2011, by and among Brookfield Renewable Energy Partners L.P., Brookfield Renewable Energy L.P., the Service Provider, Brookfield Asset Management Inc., and others.(1)
4.7	Registration Rights Agreement, dated November 28, 2011, between Brookfield Renewable Energy Partners L.P. and Brookfield Renewable Power Inc.(1)
4.8	Combination Agreement, dated September 12, 2011, by and among Brookfield Renewable Power Inc., Brookfield Renewable Power Fund, Brookfield Renewable Power Trust and Brookfield Renewable Energy Partners L.P.(1)
4.9	Amended and Restated Indenture, dated as of November 23, 2011, among Brookfield Renewable Energy Partners ULC (formerly BRP Finance ULC), BNY Trust Company of Canada and The Bank of New York Mellon.(1)
4.10	Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc., and Computershare Trust Company of Canada (Class A Preference Shares, Series 1).(1)
4.11	Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc., and Computershare Trust Company of Canada (Class A Preference Shares, Series 2).(1)
4.12	Guarantee, dated November 23, 2011, by Brookfield Renewable Energy L.P. and BNY Trust Company of Canada.(1)
4.13	Guarantee, dated November 23, 2011, by Brookfield Renewable Energy Partners L.P. and BNY Trust Company of Canada.(1)
4.14	Guarantee, dated November 23, 2011, by BRP Bermuda Holdings I Limited and BNY Trust Company of Canada.(1)
4.15	Guarantee, dated November 23, 2011, by Brookfield BRP Holdings (Canada) Inc. and BNY Trust Company of Canada.(1)
4.16	Energy Revenue Agreement, dated November 23, 2011, between Brookfield Energy Marketing LP and Brookfield Power US Holding America Co.(1)
4.17	Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc. and Computershare Trust Company of Canada (Class A Preference Shares, Series 1).(1)
4.18	Amended and Restated Guarantee Indenture, dated November 25, 2011, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc. and Computershare Trust Company of Canada (Class A Preference Shares, Series 2).(1)
4.19	Guarantee Indenture, dated October 11, 2012, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc. and Computershare Trust Company of Canada (Class A Preference Shares, Series 3).(1)
4.20	Guarantee Indenture, dated October 11, 2012, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc., and Computershare Trust Company of Canada (Class A Preference Shares, Series 4).(1)
4.21	Guarantee Indenture, dated January 29, 2013, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc., and Computershare Trust Company of Canada (Class A Preference Shares, Series 5).(1)
4.22	Guarantee Indenture, dated May 1, 2013, by and among the Preference Share Guarantors from time to time party thereto, Brookfield Renewable Power Preferred Equity Inc., and Computershare Trust Company of Canada (Class A Preference Shares, Series 6).(1)
4.23	Guarantee, dated October 7, 2014, by Brookfield BRP Europe Holdings (Bermuda) Limited and BNY Trust Company of Canada.(2)
4.24	Guarantee, dated February 26, 2015, by Brookfield Renewable Investments Limited and BNY Trust Company of Canada.(2)
4.25	Guarantee Indenture, dated November 25, 2015, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Energy Partners L.P., and Computershare Trust Company of Canada (Series 7 Preferred Units).(3)
4.26	Guarantee Indenture, dated November 25, 2015, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Energy Partners L.P., and Computershare Trust Company of Canada (Series 8 Preferred Units).(3)
4.27	Guarantee Indenture, dated February 11, 2016, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Energy Partners L.P., and Computershare Trust Company of Canada (Series 5 Preferred Units).(4)
4.28	Guarantee Indenture, dated May 25, 2016, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 9 Preferred Units).(8)
4.29	Guarantee Indenture, dated May 25, 2016, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 10 Preferred Units).(8)
4.30	Guarantee Indenture, dated February 14, 2017, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 11 Preferred Units).(10)
4.31	Guarantee Indenture, dated February 14, 2017, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 12 Preferred Units).(10)
4.32	Guarantee Indenture, dated January 16, 2018, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 13 Preferred Units).(11)
4.33	Guarantee Indenture, dated January 16, 2018, by and among the Preferred Unit Guarantors from time to time party thereto, Brookfield Renewable Partners L.P., and Computershare Trust Company of Canada (Series 14 Preferred Units).(11)
8.1	Significant subsidiaries (as defined in §210-1.02(w) of Regulation S-X) of Brookfield Renewable Partners L.P. (incorporated by reference to Item 4.C “Organizational Structure”).
11.1	Code of Business Conduct and Ethics.(9)
12.1	Certification of Sachin Shah, Chief Executive Officer of BRP Energy Group L.P., the Service Provider of Brookfield Renewable Partners L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(12)
12.2	Certification of Wyatt Hartley, Chief Financial Officer of BRP Energy Group L.P., the Service Provider of Brookfield Renewable Partners L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(12)
13.1	Certification of Sachin Shah, Chief Executive Officer of BRP Energy Group L.P., the Service Provider of Brookfield Renewable Partners L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes Oxley Act of 2002.(12)
13.2	Certification of Wyatt Hartley, Chief Financial Officer of BRP Energy Group L.P., the Service Provider of Brookfield Renewable Partners L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes Oxley Act of 2002.(12)
15.1	Board of Directors Charter of the Managing General Partner of Brookfield Renewable Partners L.P.(12)
15.2	Audit Committee Charter of the Managing General Partner of Brookfield Renewable Partners L.P.(12)
15.3	Consent of Ernst & Young LLP.(12)
101	The following materials from Brookfield Renewable Partners L.P.’s annual report on Form 20-F for the year ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Financial Statements of Brookfield Renewable Partners L.P. and (ii) Notes to the Consolidated Financial Statements of Brookfield Renewable Partners L.P., tagged as blocks of text and in detail.(12)

Page 236

⁽¹⁾               Filed as an exhibit to Registration Statement on Form 20-F including all amendments thereto, with the last such amendment having been made on May 16, 2013, and incorporated herein by reference.          

⁽²⁾               Filed as an exhibit to our 2014 form 20-F as filed on February 27, 2015 and incorporated herein by reference.

⁽³⁾               Filed as an exhibit to form 6-K on November 27, 2015, and incorporated herein by reference.

⁽⁴⁾               Filed as an exhibit to form 6-K on February 11, 2016, and incorporated herein by reference.

⁽⁵⁾               Filed as an exhibit to our 2015 form 20-F as filed on February 26, 2016, and incorporated herein by reference.

⁽⁶⁾               Filed as an exhibit to form 6-K on May 4, 2016, and incorporated herein by reference.

⁽⁷⁾               Filed as an exhibit to form 6-K on May 6, 2016, and incorporated herein by reference.

⁽⁸⁾               Filed as an exhibit to form 6-K on May 26, 2016, and incorporated herein by reference.

⁽⁹⁾               Filed as an exhibit to form 6-K on November 15, 2016, and incorporated herein by reference.

⁽¹⁰⁾             Filed as an exhibit to form 6-K on February 14, 2017, and incorporated herein by reference.

⁽¹¹⁾             Filed as an exhibit to form 6-K on January 17, 2018, an incorporated herein by reference.

⁽¹²⁾             Filed herewith.

Page 239

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing this Form 20-F and that it has duly caused and authorized the undersigned to sign this Form 20-F on its behalf.

Dated: February 28, 2018	BROOKFIELD RENEWABLE PARTNERS L.P. by its general partner, Brookfield Renewable Partners Limited
	By:
		Name:	Wyatt Hartley
		Title:	Chief Financial Officer of the Service Provider, BRP Energy Group L.P.

Page 240

BROOKFIELD RENEWABLE PARTNERS L.P.

 INDEX TO FINANCIAL STATEMENTS

		Page
Audited Consolidated Financial Statements as at December 31, 2017 and 2016 and for the		F-2
	Years Ended December 31, 2017, 2016 and 2015

Page 241

MANAGEMENT’S RESPONSIBILITY

Management’s Responsibility for Financial Statements

The accompanying consolidated financial statements have been prepared by the Brookfield Renewable Partners L.P. (“Brookfield Renewable”) management which is responsible for their integrity, consistency, objectivity and reliability. To fulfill this responsibility, Brookfield Renewable maintains policies, procedures and systems of internal control to ensure that its reporting practices and accounting and administrative procedures are appropriate to provide a high degree of assurance that relevant and reliable financial information is produced and assets are safeguarded. These controls include the careful selection and training of employees, the establishment of well-defined areas of responsibility and accountability for performance, and the communication of policies and the code of conduct throughout the company.

These consolidated financial statements have been prepared in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board and, where appropriate, reflect estimates based on management’s judgment. 

Ernst & Young LLP, the Independent Registered Public Accountants appointed by the directors of the general partner of Brookfield Renewable, have audited the consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States) to enable them to express to the partners their opinion on the consolidated financial statements. Their report outlines the scope of their examination and opinion on the consolidated financial statements.

The consolidated financial statements have been further reviewed and approved by the Board of Directors of the general partner of Brookfield Renewable acting through its Audit Committee, which is comprised of directors who are not officers or employees of Brookfield Renewable. The Audit Committee, which meets with the auditors and management to review the activities of each and reports to the Board of Directors, oversees management’s responsibilities for the financial reporting and internal control systems. The auditors have full and direct access to the Audit Committee and meet periodically with the committee both with and without management present to discuss their audit and related findings.

Sachin Shah Chief Executive Officer	Wyatt Hartley Chief Financial Officer

  February 28, 2018

F - 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Brookfield Renewable Partners Limited (General Partner of Brookfield Renewable Partners L.P.) and Partners of Brookfield Renewable Partners L.P.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated financial statements of Brookfield Renewable Partners L.P. (“Brookfield Renewable”), which comprise the consolidated statements of financial position as at December 31, 2017 and December 31, 2016, the consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the years in the three-year period ended December 31, 2017,and the related notes, comprising a summary of significant accounting policies and other explanatory information (collectively referred to as the “consolidated financial statements”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Brookfield Renewable as at December 31, 2017 and December 31, 2016, and its consolidated financial performance and its consolidated cash flows for each of the years in the three-year period ended December 31, 2017,in accordance with International Financial Reporting Standards (IFRSs) as issued by the International Accounting Standards Board.

Report on internal control over financial reporting

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), Brookfield Renewable’s internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 2018 expressed an unqualified opinion on the effectiveness of Brookfield Renewable’s internal control over financial reporting.

Basis for Opinion

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards (IFRSs) as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement, whether due to error or fraud. Those standards also require that we comply with ethical requirements, including independence. We are required to be independent with respect to Brookfield Renewable in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, the U.S. federal securities laws and the applicable rules and regulations

F - 3

of the Securities and Exchange Commission and the PCAOB. We are a public accounting firm registered with the PCAOB.

An audit includes performing procedures to assess the risks of material misstatements of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included obtaining and examining, on a test basis, audit evidence regarding the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidatedfinancial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to Brookfield Renewable’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances.

An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a reasonable basis for our audit opinion.

We have served as Brookfield Renewable’s auditors since 2011.

Toronto, Canada

February 28, 2018

F - 4

INTERNAL CONTROL OVER FINANCIAL REPORTING

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Brookfield Renewable Partners L.P. (“Brookfield Renewable”) is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board as defined in Regulation 240.13a–15(f) or 240.15d–15(f).

Management assessed the effectiveness of Brookfield Renewable’s internal control over financial reporting as of December 31, 2017, based on the criteria set forth in Internal Control – Integrated Framework  issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concludes that, as of December 31, 2017, Brookfield Renewable’s internal control over financial reporting is effective. Management excluded from its design and assessment of internal control over financial reporting the internal controls of the 16 MW Shantavny wind project in Northern Ireland and TerraForm Global, Inc. acquired in 2017, whose total assets, net assets on a combined basis constitute approximately 7% and 5%, respectively, of the consolidated financial statement amounts as of December 31, 2017 and nil% of revenues and net income, for the year then ended.  

Brookfield Renewable’s internal control over financial reporting as of December 31, 2017, has been audited by Ernst & Young LLP, the Independent Registered Public Accounting Firm, who also audited Brookfield Renewable’s consolidated financial statements for the year ended December 31, 2017. As stated in the Report of Independent Registered Public Accounting Firm, Ernst & Young LLP expressed an unqualified opinion on the effectiveness of Brookfield Renewable’s internal control over financial reporting as of December 31, 2017.

Sachin Shah Chief Executive Officer	Wyatt Hartley Chief Financial Officer

February 28, 2018

F - 5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Brookfield Renewable Partners Limited (General Partner of Brookfield Renewable Partners L.P.) and Partners of Brookfield Renewable Partners L.P.  

Opinion on Internal Control over Financial Reporting

We have audited Brookfield Renewable Partners L.P. (“Brookfield Renewable”)’s internal control over  financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework (2013) issued by  the Committee of Sponsoring Organizations of the Treadway   Commission (the “COSO criteria”). In our opinion, Brookfield Renewable maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based onthe COSO criteria.   

As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the 16 MW Shantavny wind project in Northern Ireland and TerraForm Global acquired in 2017, which are included in the 2017 consolidated financial statements of Brookfield Renewable and constituted approximately 7% and 5% of total and net assets, respectively, as of December 31, 2017 and nil% of revenues and net income for the year then ended. Our audit of internal control over financial reporting of Brookfield Renewable also did not include an evaluation of the internal control over financial reporting of the 16 MW Shantavny wind project in Northern Ireland and TerraForm Global acquired in 2017.

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public  Company  Accounting Oversight Board (United States) (“PCAOB”), the 2017 consolidated financial statements of Brookfield Renewable and our report dated February 28, 2018 expressed an unqualified opinion on those consolidated financial statements. 

Basis for Opinion   

Brookfield Renewable’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness  of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility  is to express an opinion on Brookfield Renewable’s internal control over financial reporting based on our audit.We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Brookfield Renewable in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, the U.S. federal securities laws and the applicable rules and regulations  of the Securities and Exchange Commission and the PCAOB. 

F - 6

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Toronto, Canada 

February 28, 2018

F - 7

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEAR ENDED DECEMBER 31
(MILLIONS, EXCEPT AS NOTED)			Notes	2017		2016		2015
Revenues			27	$	2,625	$	2,452	$	1,628
Other income			7		47		64		122
Direct operating costs			8		(978)		(1,038)		(552)
Management service costs			27		(82)		(62)		(48)
Interest expense – borrowings			13		(632)		(606)		(429)
Share of earnings from equity-accounted investments			19		2		-		10
Unrealized financial instruments loss			5		(33)		(4)		(9)
Depreciation			12		(782)		(781)		(616)
Other			9		(28)		(38)		(63)
Income tax (expense) recovery
	Current		11		(39)		(44)		(18)
	Deferred		11		(49)		97		78
					(88)		53		60
Net income				$	51	$	40	$	103
Net income attributable to:
Non-controlling interests
	Participating non-controlling interests - in
		operating subsidiaries	14	$	53	$	65	$	69
	General partnership interest in a holding
		subsidiary held by Brookfield	14		(1)		-		-
	Participating non-controlling interests - in a
		holding subsidiary - Redeemable/
		Exchangeable units held by Brookfield	14		(23)		(29)		1
	Preferred equity		14		26		25		30
Preferred limited partners' equity			15		28		15		1
Limited partners' equity			16		(32)		(36)		2
				$	51	$	40	$	103
Basic and diluted (loss) earnings per LP Unit				$	(0.18)	$	(0.23)	$	0.01
The accompanying notes are an integral part of these consolidated financial statements.

F - 8

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEAR ENDED DECEMBER 31
(MILLIONS)				Notes	2017		2016		2015
Net income					$	51	$	40	$	103
Other comprehensive income that will not be
	reclassified to net income
		Revaluations of property, plant and equipment		12		872		417		1,197
		Revaluations of property, plant and equipment
			related to equity-accounted investments	19		54		7		96
		Actuarial (loss) gain on defined benefit plans		29		(2)		(2)		5
		Deferred income taxes on above items		11		338		(34)		(283)
Total items that will not be reclassified to net income						1,262		388		1,015
Other comprehensive income (loss) that may be
	reclassified to net income
	Gains arising during the year on financial
		instruments designated as cash-flow hedges		5		4		8		10
	Unrealized (loss) gain on available-for-sale securities			5		(22)		61		-
	Reclassification adjustments for amounts
		recognized in net income		5		(1)		(41)		(32)
	Foreign currency translation			10		190		986		(1,138)
	Unrealized (loss) gain on foreign exchange swaps -
		net investment hedge		5		(94)		(66)		55
	Deferred income taxes on above items			11		11		(7)		(8)
Total items that may be reclassified subsequently to net income						88		941		(1,113)
Other comprehensive income (loss)						1,350		1,329		(98)
Comprehensive income					$	1,401	$	1,369	$	5
Comprehensive income attributable to:
Non-controlling interests
	Participating non-controlling interests - in
		operating subsidiaries		14	$	436	$	700	$	273
	General partnership interest in a holding
		subsidiary held by Brookfield		14		8		6		(2)
	Participating non-controlling interests - in a holding
		subsidiary - Redeemable/Exchangeable
		units held by Brookfield		14		370		275		(86)
	Preferred equity			14		65		41		(87)
Preferred limited partners' equity				15		28		15		1
Limited partners' equity				16		494		332		(94)
					$	1,401	$	1,369	$	5
The accompanying notes are an integral part of these consolidated financial statements.

F - 9

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS AT DECEMBER 31
(MILLIONS)			Notes		2017		2016
Assets
Current assets
	Cash and cash equivalents		20	$	799	$	223
	Restricted cash		21		181		121
	Trade receivables and other current assets		22		554		454
	Financial instrument assets		5		72		55
	Due from related parties		27		60		54
					1,666		907
Financial instrument assets			5		113		145
Equity-accounted investments			19		721		206
Property, plant and equipment, at fair value			12		27,096		25,257
Goodwill			17		901		896
Deferred income tax assets			11		177		150
Other long-term assets			23		230		176
				$	30,904	$	27,737
Liabilities
Current liabilities
	Accounts payable and accrued liabilities		24	$	542	$	467
	Financial instrument liabilities		5		184		156
	Due to related parties		27		112		76
	Current portion of long-term debt		13		1,676		1,034
					2,514		1,733
Financial instrument liabilities			5		86		72
Long-term debt and credit facilities			13		10,090		9,148
Deferred income tax liabilities			11		3,588		3,802
Other long-term liabilities			25		344		310
					16,622		15,065
Equity
Non-controlling interests
	Participating non-controlling interests - in operating
		subsidiaries	14		6,298		5,589
	General partnership interest in a holding subsidiary
		held by Brookfield	14		58		55
	Participating non-controlling interests - in a holding subsidiary
		- Redeemable/Exchangeable units held by Brookfield	14		2,843		2,680
	Preferred equity		14		616		576
Preferred limited partners' equity			15		511		324
Limited partners' equity			16		3,956		3,448
					14,282		12,672
				$	30,904	$	27,737
The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of Brookfield Renewable Partners L.P.:

	Patricia Zuccotti Director		David Mann Director

F - 10

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
				Accumulated other comprehensive income (loss)														Non-controlling interests
																								Participating
																						General		non-controlling
																						partnership		interests - in a
								Actuarial												Participating		interest in		holding subsidiary
								losses on				Available-		Total		Preferred				non-controlling		a holding		- Redeemable
		Limited		Foreign				defined				for-sale		limited		limited				interests - in		subsidiary		/Exchangeable
YEAR ENDED DECEMBER 31		partners'		currency		Revaluation		benefit		Cash flow		invest-		partners'		partners'		Preferred		operating		held by		units held by		Total
(MILLIONS)		equity		translation		surplus		plans		hedges		ments		equity		equity		equity		subsidiaries		Brookfield		Brookfield		equity
Balance, as at December 31, 2016		$	(257)	$	(404)	$	4,124	$	(8)	$	(31)	$	24	$	3,448	$	324	$	576	$	5,589	$	55	$	2,680	$	12,672
Net (loss) income			(32)		-		-		-		-		-		(32)		28		26		53		(1)		(23)		51
Other comprehensive income (loss)			-		26		508		(1)		2		(9)		526		-		39		383		9		393		1,350
Preferred LP Units and LP Units issued
	- (Note 15, 16)
	Net proceeds		411		-		-		-		-		-		411		187		-		-		-		-		598
	Adjustment		(63)												(63)		-		-		-		1		62		-
Capital contributions (Note 14)			-		-		-		-		-		-		-		-		-		294		-		-		294
Acquisition			-		-		-		-		-		-		-		-		-		525		-		-		525
Distributions or dividends declared			(328)		-		-		-		-		-		(328)		(28)		(26)		(539)		(35)		(243)		(1,199)
Distribution reinvestment plan			10		-		-		-		-		-		10		-		-		-		-		-		10
Other			-		-		(16)		-		-		-		(16)		-		1		(7)		29		(26)		(19)
Change in  year			(2)		26		492		(1)		2		(9)		508		187		40		709		3		163		1,610
Balance, as at December 31, 2017		$	(259)	$	(378)	$	4,616	$	(9)	$	(29)	$	15	$	3,956	$	511	$	616	$	6,298	$	58	$	2,843	$	14,282
Balance, as at December 31, 2015		$	(485)	$	(670)	$	4,019	$	(7)	$	(30)	$	-	$	2,827	$	128	$	610	$	2,587	$	52	$	2,559	$	8,763
Net income			(36)		-		-		-		-		-		(36)		15		25		65		-		(29)		40
Other comprehensive (loss) income			-		241		105		(1)		(1)		24		368		-		16		635		6		304		1,329
Exchange of preferred shares			-		-		-		-		-		-		-		49		(49)		-		-		-		-
Preferred LP Units and LP Units issued
	Net proceeds		657		-		-		-		-		-		657		147		-		-		-		-		804
	Adjustment		(85)		-		-		-		-		-		(85)		-		-		-		2		83		-
Capital contributions			-		-		-		-		-		-		-		-		-		2,621		-		-		2,621
Acquisition			-		-		-		-		-		-		-		-		-		1,417		-		-		1,417
Distributions or dividends declared			(281)		-		-		-		-		-		(281)		(15)		(25)		(119)		(24)		(232)		(696)
Distribution reinvestment plan			9		-		-		-		-		-		9		-		-		-		-		-		9
MTO adjustments			(24)		25		-		-		-		-		1		-		-		(1,617)		-		-		(1,616)
Other			(12)		-		-		-		-		-		(12)		-		(1)		-		19		(5)		1
Change in  year			228		266		105		(1)		(1)		24		621		196		(34)		3,002		3		121		3,909
Balance, as at December 31, 2016		$	(257)	$	(404)	$	4,124	$	(8)	$	(31)	$	24	$	3,448	$	324	$	576	$	5,589	$	55	$	2,680	$	12,672
The accompanying notes are an integral part of these consolidated financial statements.

F - 11

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
				Accumulated other comprehensive income (loss)												Non-controlling interests
																						Participating
																				General		non-controlling
																				partnership		interests - in a
								Actuarial										Participating		interest in		holding subsidiary
								losses on				Total		Preferred				non-controlling		a holding		- Redeemable
		Limited		Foreign				defined				limited		limited				interests - in		subsidiary		/Exchangeable
YEAR ENDED DECEMBER 31		partners'		currency		Revaluation		benefit		Cash flow		partners'		partners'		Preferred		operating		held by		units held by		Total
(MILLIONS)		equity		translation		surplus		plans		hedges		equity		equity		equity		subsidiaries		Brookfield		Brookfield		equity
Balance, as at December 31, 2014		$	(241)	$	(241)	$	3,685	$	(9)	$	(27)	$	3,167	$	-	$	728	$	2,062	$	59	$	2,865	$	8,881
Net income			2		-		-		-		-		2		1		30		69		-		1		103
Other comprehensive (loss) income			-		(429)		334		2		(3)		(96)		-		(117)		204		(2)		(87)		(98)
Preferred LP Units issued			-		-		-		-		-		-		128		-		-		-		-		128
LP Units and preferred shares purchased
	for cancellation		(9)		-		-		-		-		(9)		-		(1)		-		-		-		(10)
Capital contributions			-		-		-		-		-		-		-		-		460		-		-		460
Distributions or dividends declared			(239)		-		-		-		-		(239)		(1)		(30)		(208)		(12)		(217)		(707)
Distribution reinvestment plan			5		-		-		-		-		5		-		-		-		-		-		5
Other			(3)		-		-		-		-		(3)		-		-		-		7		(3)		1
Change in  year			(244)		(429)		334		2		(3)		(340)		128		(118)		525		(7)		(306)		(118)
Balance, as at December 31, 2015		$	(485)	$	(670)	$	4,019	$	(7)	$	(30)	$	2,827	$	128	$	610	$	2,587	$	52	$	2,559	$	8,763
The accompanying notes are an integral part of these consolidated financial statements.

F - 12

BROOKFIELD RENEWABLE PARTNERS L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31
(MILLIONS)			Notes		2017		2016		2015
Operating activities
Net income				$	51	$	40	$	103
Adjustments for the following non-cash items:
	Depreciation		12		782		781		616
	Unrealized financial instrument loss		5		33		4		9
	Share of earnings from
		equity-accounted investments			(2)		-		(10)
	Deferred income tax expense (recovery)		11		49		(97)		(78)
	Gain on disposal		7		-		-		(53)
	Other non-cash items				4		24		62
Dividends received from equity-accounted investments					31		6		19
Changes in due to or from related parties					5		11		(18)
Net change in working capital balances					(25)		(137)		(62)
					928		632		588
Financing activities
Long-term debt - borrowings			13		1,874		3,477		944
Long-term debt - repayments			13		(1,607)		(1,975)		(855)
Capital contributions from participating non-controlling
	interests - in operating subsidiaries		14		294		2,621		460
Acquisition of Isagen from non-controlling interests			14		(5)		(1,540)		-
Issuance of preferred limited partnership units			15		187		147		128
Issuance of LP Units			16		411		657		-
Repurchase of LP Units and preferred shares					-		-		(10)
Distributions paid:
	To participating non-controlling interests - in operating
		subsidiaries	14		(539)		(119)		(208)
	To preferred shareholders				(25)		(25)		(31)
	To preferred limited partners' unitholders		15		(26)		(12)		-
	To unitholders of Brookfield Renewable or BRELP		14, 16		(591)		(522)		(461)
					(27)		2,709		(33)
Investing activities
Acquisitions			3		(234)		(2,886)		(682)
Acquisitions of equity-accounted investments			3		(439)		-		-
Cash and cash equivalents in acquired entity			3		611		117		19
Investment in:
	Sustaining capital expenditures		12		(138)		(118)		(94)
	Development and construction of renewable power
		generating assets	12		(217)		(251)		(191)
Capital distribution received from equity-accounted investments, net					-		-		144
Proceeds from disposal of assets			4		150		-		143
Investment in securities			5		(77)		(60)		(18)
Restricted cash and other					16		7		56
					(328)		(3,191)		(623)
Foreign exchange gain (loss) on cash					3		10		(19)
Cash and cash equivalents
	Increase (decrease)				576		160		(87)
	Balance, beginning of  year				223		63		150
	Balance, end of  year			$	799	$	223	$	63
Supplemental cash flow information:
	Interest paid			$	611	$	588	$	414
	Interest received			$	27	$	40	$	18
	Income taxes paid			$	48	$	55	$	32
The accompanying notes are an integral part of these consolidated financial statements.

F - 13

brookfield renewable partners l.p.

notes to the annual consolidated financial statements

The business activities of Brookfield Renewable Partners L.P. (“Brookfield Renewable”) consist of owning a portfolio of renewable power generating facilities in North America, Colombia, Brazil, Europe, and other countries (including India and China).

Unless the context indicates or requires otherwise, the term “Brookfield Renewable” means Brookfield Renewable Partners L.P. and its controlled entities.

Brookfield Renewable is a publicly traded limited partnership established under the laws of Bermuda pursuant to an amended and restated limited partnership agreement dated November 20, 2011.

The registered office of Brookfield Renewable is 73 Front Street, Fifth Floor, Hamilton HM12, Bermuda.

The immediate parent of Brookfield Renewable is its general partner, Brookfield Renewable Partners Limited (“BRPL”). The ultimate parent of Brookfield Renewable is Brookfield Asset Management Inc. (“Brookfield Asset Management”). Brookfield Asset Management and its subsidiaries, other than Brookfield Renewable, are also individually and collectively referred to as “Brookfield” in these financial statements.

Brookfield Renewable’s non-voting limited partnership units (“LP Units”) are traded under the symbol “BEP” on the New York Stock Exchange and under the symbol “BEP.UN” on the Toronto Stock Exchange. Brookfield Renewable’s Class A Series 5, Series 7, Series 9, Series 11 and Series 13 preferred limited partners’ equity are traded under the symbols “BEP.PR.E”, “BEP.PR.G”, “BEP.PR.I”, “BEP.PR.K” and “BEP.PR.M” respectively, on the Toronto Stock Exchange.

Notes to consolidated financial statements	Page
GENERAL APPLICATION
1.Basis of preparation and significant accounting policies	16
2.Principal subsidiaries	30
3.Acquisitions	31
4.Disposal of assets	36
5.Risk management and financial instruments	37
6.Segmented information	46
CONSOLIDATED RESULTS OF OPERATIONS
7.Other income	52
8.Direct operating costs	52
9.Other	53
10.Foreign currency translation	53
11.Income taxes	54
CONSOLIDATED FINANCIAL POSITION
12.Property, plant and equipment, at fair value	56
13.Long-term debt and credit facilities	59
14.Non-controlling interests	62
15.Preferred limited partner’s equity	67
16.Limited partners’ equity	67
17.Goodwill	68
18.Capital management	68
19.Equity-accounted investments	69
20.Cash and cash equivalents	70
21.Restricted cash	71
22.Trade receivables and other current assets	71
23.Other long-term assets	71
24.Accounts payable and accrued liabilities	72
25.Other long-term liabilities	72
26.Commitments, contingencies and guarantees	73
OTHER
27.Related party transactions	74
28.Supplemental information	78
29.Pension and employee future benefits	78
30.Subsidiary public issuers	82
31.Subsequent events	83

F - 14

1.  BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES

(a) Statement of compliance

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).  The accounting policies used in the consolidated financial statements are based on the IFRS applicable as at December 31, 2017, which encompass individual IFRS, International Accounting Standards (“IAS”), and interpretations made by the International Financial Reporting Interpretations Committee (“IFRIC”) and the Standard Interpretations Committee (“SIC”). The policies set out below are consistently applied to all periods presented, unless otherwise noted. 

These consolidated financial statements have been authorized for issuance by the Board of Directors of its general partner, BRPL, on February 28, 2018.  

Certain comparative figures have been reclassified to conform to the current year’s presentation.

References to $, C$, €, R$, £, and COP are to United States (“U.S.”) dollars, Canadian dollars, Euros, Brazilian reais, British pounds sterling, and Colombian pesos, respectively.

All figures are presented in millions of U.S. dollars unless otherwise noted.

(b) Basis of preparation

The consolidated financial statements have been prepared on the basis of historical cost, except for the revaluation of property, plant and equipment and certain assets and liabilities which have been measured at fair value. Cost is recorded based on the fair value of the consideration given in exchange for assets.

(i)      Consolidation

These consolidated financial statements include the accounts of Brookfield Renewable and its subsidiaries, which are the entities over which Brookfield Renewable has control. An investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Non-controlling interests in the equity of Brookfield Renewable’s subsidiaries are shown separately in equity in the consolidated statements of financial position.

Brookfield Renewable has entered into a voting agreement with Brookfield, which provides Brookfield Renewable with control of the general partner of Brookfield Renewable Energy L.P. (“BRELP”), a holding subsidiary. Accordingly, Brookfield Renewable consolidates the accounts of BRELP and its subsidiaries. In addition, BRELP issued redeemable-exchangeable limited partnership units to Brookfield (“Redeemable/Exchangeable partnership units”), pursuant to which the holder may at its request require BRELP to redeem the Redeemable/Exchangeable partnership units for cash consideration. This right is subject to Brookfield Renewable’s right of first refusal which entitles it, at its sole discretion, to elect to acquire all of the Redeemable/Exchangeable partnership units so presented to BRELP that are tendered for redemption in exchange for LP Units. As Brookfield Renewable, at its sole discretion, has the right to settle the obligation with LP Units, the Redeemable/Exchangeable partnership units are classified as equity of Brookfield Renewable (“Participating non-controlling interests – in a holding subsidiary – Redeemable/Exchangeable units held by Brookfield”).

Brookfield Renewable has entered into voting agreements with Brookfield, whereby Brookfield Renewable gained control of the entities that own certain renewable power generating operations in the United States, Brazil, Europe and other countries (including India and China). Brookfield Renewable has also entered into a voting agreement with our consortium partners in respect of our Colombian

F - 15

operations. These voting agreements provide Brookfield Renewable the authority to direct the election of the Boards of Directors of the relevant entities, among other things, and therefore provide Brookfield Renewable with control. Accordingly, Brookfield Renewable consolidates the accounts of these entities. Refer to Note 27 - Related party transactions for further information.

For entities previously controlled by Brookfield Asset Management, the voting agreements entered into do not represent business combinations in accordance with IFRS 3, Business Combinations (“IFRS 3”), as all combining businesses are ultimately controlled by Brookfield Asset Management both before and after the transactions were completed. Brookfield Renewable accounts for these transactions involving entities under common control in a manner similar to a pooling of interest, which requires the presentation of pre-voting agreement financial information as if the transactions had always been in place. Refer to Note 1(o)(ii) - Critical judgments in applying accounting policies - Common control transactions for Brookfield Renewable’s policy on accounting for transactions under common control.

(ii)     Equity-accounted investments

Equity-accounted investments are entities over which Brookfield Renewable has significant influence or joint arrangements representing joint ventures. Significant influence is the ability to participate in the financial and operating policy decisions of the investee, but without controlling or jointly controlling those investees. Such investments are accounted for using the equity method.

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Brookfield Renewable accounts for its interests in joint ventures using the equity method.

Under the equity method, the carrying value of an interest in an investee is initially recognized at cost and adjusted for Brookfield Renewable’s share of net income, other comprehensive income (“OCI”), distributions by the equity-accounted investment and other adjustments to Brookfield Renewable’s proportionate interest in the investee.

(c) Foreign currency translation

All figures reported in the consolidated financial statements and tabular disclosures to the consolidated financial statements are reflected in millions of U.S. dollars, which is the functional currency of Brookfield Renewable. Each of the foreign operations included in these consolidated financial statements determines its own functional currency, and items included in the financial statements of each subsidiary are measured using that functional currency.

Assets and liabilities of foreign operations having a functional currency other than the U.S. dollar are translated at the rate of exchange prevailing at the reporting date and revenues and expenses at the rate of exchange prevailing at the dates of the transactions during the period. Gains or losses on translation of foreign subsidiaries are included in OCI. Gains or losses on foreign currency denominated balances and transactions that are designated as hedges of net investments in these operations are reported in the same manner.

In preparing the consolidated financial statements of Brookfield Renewable, foreign currency denominated monetary assets and liabilities are translated into the functional currency using the closing rate at the applicable consolidated statement of financial position dates. Non-monetary assets and liabilities, denominated in a foreign currency and measured at fair value, are translated at the rate of exchange prevailing at the date when the fair value was determined and non-monetary assets measured at historical cost are translated at the historical rate. Revenues and expenses are measured in the

F - 16

functional currency at the rates of exchange prevailing at the dates of the transactions with gains or losses included in income.

(d) Cash and cash equivalents

Cash and cash equivalents include cash, term deposits and money market instruments with original maturities of less than 90 days.

(e) Restricted cash

Restricted cash includes cash and cash equivalents, where the availability of funds is restricted primarily by credit agreements.

(f) Property, plant and equipment and revaluation method

Power generating assets are classified as property, plant and equipment and are accounted for using the revaluation method under IAS 16, Property, Plant and Equipment (“IAS 16”). Property, plant and equipment are initially measured at cost and subsequently carried at their revalued amount, being the fair value at the date of the revaluation, less any subsequent accumulated depreciation and any subsequent accumulated impairment losses.

Brookfield Renewable generally determines the fair value of its property, plant and equipment by using a 20-year discounted cash flow model. This model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. The model also includes estimates of future electricity prices, anticipated long-term average generation, estimated operating and capital expenditures, and assumptions about future inflation rates and discount rates by geographical location. Construction work-in-progress (“CWIP”) is revalued when sufficient information exists to determine fair value using the discounted cash flow method. Revaluations are made on an annual basis as at December 31 to ensure that the carrying amount does not differ significantly from fair value. For power generating assets acquired through business combinations during the year, Brookfield Renewable initially measures the assets at fair value consistent with the policy described in Note 1(l) – Business combinations. Accordingly, in the year of acquisition, power generating assets are not revalued at year-end unless there is an indication that assets are impaired.

Where the carrying amount of an asset increased as a result of a revaluation, the increase is recognized in income to the extent the increase reverses a previously recognized decrease recorded through income, with the remainder of the increase recognized in OCI and accumulated in equity under revaluation surplus and non-controlling interest. Where the carrying amount of an asset decreased, the decrease is recognized in OCI to the extent that a balance exists in revaluation surplus with respect to the asset, with the remainder of the decrease recognized in income.

F - 17

Depreciation on power generating assets is calculated on a straight-line basis over the estimated service lives of the assets, which are as follows:

	Estimated service lives
Dams	Up to 115 years
Penstocks	Up to 60 years
Powerhouses	Up to 115 years
Hydroelectric generating units	Up to 115 years
Wind generating units	Up to 30 years
Solar generating units	Up to 30 years
Gas-fired co-generating (“Co-gen”) units	Up to 40 years
Other assets	Up to 60 years

Costs are allocated to significant components of property, plant and equipment.  When items of property, plant and equipment have different useful lives, they are accounted for as separate items (significant components) and depreciated separately. To ensure the accuracy of useful lives and residual values, a review is conducted annually. 

Depreciation is calculated based on the cost of the asset less its residual value. Depreciation commences when the asset is in the location and conditions necessary for it to be capable of operating in the manner intended by management. It ceases at the earlier of the date the asset is classified as held-for-sale and the date the asset is derecognized. An item of property, plant and equipment and any significant component is derecognized upon disposal or when no future economic benefits are expected from its use. Other assets include equipment, buildings and leasehold improvements. Buildings, furniture and fixtures, leasehold improvements and office equipment are recorded at historical cost, less accumulated depreciation. Land and CWIP are not subject to depreciation. 

The depreciation of property, plant and equipment in Brazil is based on the duration of the authorization or the useful life of a concession asset. The weighted-average remaining duration at December 31, 2017 is 15 years (2016: 15 years). Since land rights are part of the concession or authorization, this cost is also subject to depreciation.

Any accumulated depreciation at the date of revaluation is eliminated against the gross carrying amount of the asset, and the net amount is applied to the revalued amount of the asset.

Gains and losses on disposal of an item of property, plant and equipment are recognized in Other income in the consolidated statements of income. The revaluation surplus is reclassified within the respective components of equity and not reclassified to net income when the assets are disposed.

(g) Asset impairment

At each statement of financial position date, management assesses whether there is any indication that assets are impaired. For non-financial tangible and intangible assets (including equity-accounted investments), an impairment is recognized if the recoverable amount, determined as the greater of the estimated fair value, less costs to sell, and the discounted future cash flows generated from use and eventual disposal of an asset or cash-generating unit, is less than its carrying value. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail. Should an impairment loss subsequently reverse, the carrying amount of the asset is increased to the lesser of the revised estimate of the recoverable amount, and the carrying amount that would have been recorded had no impairment loss been recognized previously.

F - 18

(h) Trade receivables and other current assets

Trade receivables and other current assets are recognized initially at fair value, and subsequently measured at amortized cost using the effective interest method, less any allowance for uncollectability.

(i) Financial instruments

All financial instruments are classified into one of the following categories: assets and liabilities at fair value through profit or loss (“FVTPL”), cash, loans and receivables, financial instruments used for hedging, and other financial liabilities.  All financial instruments are recorded at fair value at recognition. Subsequent to initial recognition, financial assets classified as loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method. Financial assets and financial liabilities classified as financial instruments used for cash-flow hedging continue to be recognized at fair value through OCI. Other financial assets and financial liabilities and non-hedging financial instruments are recorded at fair value through profit and loss.

Brookfield Renewable presents the liability and equity components separately upon recognition of such financial instruments. The amount of accretion relating to the liability component is recognized in profit or loss; and the amount of consideration relating to the equity component is recognized in equity.

Brookfield Renewable selectively utilizes derivative financial instruments to manage financial risks, including interest rate, commodity and foreign exchange risks. A derivative is a financial instrument, which requires little or no initial investment, settles at a future date, and has a value that changes in response to the change in a specified variable such as an interest rate, financial instrument price, commodity price, foreign exchange rate, index of prices or rates, credit rating or credit index. Hedge accounting is applied when the derivative is designated as a hedge of a specific exposure, and it is highly probable that it will continue to be effective as a hedge based on an expectation of offsetting cash flows or fair value. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as a hedge or the hedging relationship is terminated. Once discontinued, the cumulative change in fair value of a derivative that was previously recorded in equity by the application of hedge accounting is recognized in income over the remaining term of the original hedging relationship, unless the originally forecasted transaction is no longer expected to occur, at which point it is released to income. The fair values of derivative financial instruments are included in financial instrument assets or financial instrument liabilities, respectively.

(i)      Items qualifying as hedges

Cash flow hedge

The effective portion of unrealized gains and losses on interest rate forward and swap contracts designated as hedges of future interest rate payments are included in equity as cash flow hedges when the interest rate risk relates to an anticipated interest payment. The periodic exchanges of payments on interest rate swap contracts designated as hedges of debt are recorded on an accrual basis as an adjustment to interest expense. The periodic exchanges of payments on interest rate contracts designated as hedges of future interest payments are recorded in income over the term of the corresponding interest payments.

Net investment hedge

Realized and unrealized gains and losses on foreign exchange forward contracts designated as hedges of currency risks are included in equity when the currency risk relates to a net investment in a subsidiary with a functional currency other than the U.S. dollar and are included in income in the period in which the subsidiary is disposed.

F - 19

(ii)     Items not qualifying as hedges

Upon initial recognition of a derivative financial instrument that is not designated as a hedge, a derivative asset or liability is recorded with an offsetting deferred liability or asset, respectively. Gains or losses arising from changes in fair value of the derivative asset or liability are recognized in income through fair value gains or losses in the period the changes occur. The deferred liability or asset is amortized through income, on a straight-line basis, over the life of the derivative financial instrument.

(iii)     Available-for-sale investments

Brookfield Renewable maintains a portfolio of marketable securities comprised of liquid equity and debt securities categorized as available-for-sale when it is not Brookfield Renewable’s strategic intent to sell the securities and the securities were not acquired principally for their near-term sale.  Available-for-sale equity and debt investments are recorded at fair value with unrealized gains and losses recorded in OCI. Realized gains and losses are recorded in income when investments are sold and are calculated using the average carrying amount of securities sold. If the fair value of an investment declines below the carrying amount, qualitative and quantitative assessments of whether the impairment is either significant or prolonged is undertaken. All relevant facts and circumstances in this assessment are undertaken to determine, particularly the length of time and extent to which fair value has declined below the carrying amount. In the case of significant or prolonged decline in fair value of an investment, an impairment loss is recognized.

(j) Revenue and expense recognition

Revenue is derived from the sale of electricity and is recorded at the time power is provided based upon the output delivered and capacity provided at rates specified under either contract terms or prevailing market rates. The revenue must be considered collectible and the costs incurred to provide the electricity to be measurable before recognizing the related revenue. Costs related to the purchases of power or fuel are recorded upon delivery. All other costs are recorded as incurred.

(k) Income taxes

Current income tax assets and liabilities are measured at the amount expected to be paid to tax authorities, net of recoveries, based on the tax rates and laws enacted or substantively enacted at the statement of financial position dates. Current income tax assets and liabilities are included in trade receivables and other current assets and accounts payable and accrued liabilities, respectively.

Deferred tax is recognized on taxable temporary differences between the tax bases and the carrying amounts of assets and liabilities. Deferred tax is not recognized if the temporary difference arises from goodwill or from initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither taxable profit nor accounting profit. Deferred income tax assets are recognized for all deductible temporary differences, carry forwards of unused tax credits and unused tax losses, to the extent that it is probable that deductions, tax credits and tax losses can be utilized. The carrying amount of deferred income tax assets is reviewed at each statement of financial position date and reduced to the extent it is no longer probable that the income tax assets will be recovered. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the statement of financial position dates.

Current and deferred income taxes relating to items recognized directly in OCI are also recognized directly in OCI.

F - 20

 (l) Business combinations

The acquisition of a business is accounted for using the acquisition method.  The consideration for an acquisition is measured at the aggregate of the fair values, at the date of exchange, of the assets transferred, the liabilities incurred to former owners of the acquired business, and equity instruments issued by the acquirer in exchange for control of the acquired business. The acquired business’ identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognized at their fair values at the acquisition date, except for income taxes which are measured in accordance with IAS 12, Income Taxes, share-based payments which are measured in accordance with IFRS 2, Share-based Payment and non-current assets that are classified as held-for-sale which are measured at fair value less costs to sell in accordance with IFRS 5, Non-current Assets Held for Sale and Discontinued Operations. The non-controlling interest in the acquiree is initially measured at the non-controlling interest’s proportion of the net fair value of the identifiable assets, liabilities and contingent liabilities recognized or when applicable, at the fair value of the shares outstanding.

To the extent that the aggregate of the fair value of consideration paid, the amount of any non-controlling interest and the fair value of any previously held interest in the acquiree exceeds the fair value of the net identifiable tangible and intangible assets acquired, goodwill is recognized. To the extent that this difference is negative, the amount is recognized as a gain in income. Goodwill is not amortized and is not deductible for tax purposes. However, after initial recognition, goodwill will be measured at cost less any accumulated impairment losses. An impairment assessment will be performed at least annually, and whenever circumstances such as significant declines in expected revenues, earnings or cash flows indicate that it is more likely than not that goodwill might be impaired. Goodwill impairment charges are not reversible.

When a business combination is achieved in stages, previously held interests in the acquired entity are re-measured to fair value at the acquisition date, which is the date control is obtained, and the resulting gain or loss, if any, is recognized in income. Amounts arising from interests in the acquired business prior to the acquisition date that have previously been recognized in OCI are reclassified to income.  Upon disposal or loss of control of a subsidiary, the carrying amount of the net assets of the subsidiary (including any OCI relating to the subsidiary) are derecognized with the difference between any proceeds received and the carrying amount of the net assets recognized as a gain or loss in income. 

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in fair values are adjusted against the cost of the acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as liabilities will be recognized in the consolidated statements of income, whereas changes in the fair values of contingent consideration classified within equity are not subsequently re-measured.

(m) Other items

(i)      Capitalized costs

Capitalized costs related to CWIP include all eligible expenditures incurred in connection with the development and construction of the power generating asset. The expenditures consist of cost of materials, direct labor and any other costs directly attributable to bringing the asset to a working condition for its intended use, and the costs of dismantling and removing the items and restoring the site on which they are located. Interest and borrowing costs are capitalized when activities that are necessary to prepare the asset for its intended use or sale are in progress, expenditures for the asset have been incurred and funds have been used or borrowed to fund the construction or development. Capitalization of costs ceases when the asset is ready for its intended use.

F - 21

(ii)     Pension and employee future benefits

Pension and employee future benefits are recognized in the consolidated financial statements in respect of employees of the operating entities within Brookfield Renewable. The costs of retirement benefits for defined benefit plans and post-employment benefits are recognized as the benefits are earned by employees. The project unit credit method, using the length of service and management’s best estimate assumptions, is used to value its pension and other retirement benefits. All actuarial gains and losses are recognized immediately through OCI in order for the net pension asset or liability recognized in the consolidated statements of financial position to reflect the full value of the plan deficit or surplus. Net interest is calculated by applying the discount rate to the net defined benefit asset or liability. Changes in the net defined benefit obligation related to service costs (comprising of current service costs, past services costs, gains and losses on curtailments and non-routine settlements), and net interest expense or income are recognized in the consolidated statements of income. 

Re-measurements, comprising of actuarial gains or losses, the effect of the asset ceiling, and the return on plan assets (excluding net interest), are recognized immediately in the consolidated statements of financial position with a corresponding debit or credit to retained earnings through OCI in the period in which they occur. Re-measurements are not reclassified to profit or loss in subsequent periods. For defined contribution plans, amounts are expensed based on employee entitlement.

(iii)     Decommissioning, restoration and environmental liabilities

Legal and constructive obligations associated with the retirement of property, plant and equipment are recorded as liabilities when those obligations are incurred and are measured at the present value of the expected costs to settle the liability, using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The liability is accreted up to the date the liability will be incurred with a corresponding charge to operating expenses. The carrying amount of decommissioning, restoration and environmental liabilities is reviewed annually with changes in the estimates of timing or amount of cash flows added to or deducted from the cost of the related asset.

(iv)     Interest and borrowing costs

Interest and borrowing costs are capitalized when such costs are directly attributable to the acquisition, construction or production of a qualifying asset. A qualifying asset is an asset that takes a substantial period of time to prepare for its intended use.

(v)      Provisions

A provision is a liability of uncertain timing or amount. A provision is recognized if Brookfield Renewable has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount can be reliably estimated. Provisions are not recognized for future operating losses. The provision is measured at the present value of the best estimate of the expenditures expected to be required to settle the obligation using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the obligation. Provisions are re-measured at each statement of financial position date using the current discount rate. The increase in the provision due to the passage of time is recognized as interest expense.

(vi)     Interest income

Interest income is earned with the passage of time and is recorded on an accrual basis.

(vii)    Government grants

Brookfield Renewable becomes eligible for government grants by constructing or purchasing renewable power generating assets, and by bringing those assets to commercial operation, coupled with a successful application to the applicable program or agency. The assessment of whether or not a project

F - 22

has complied with the conditions and that there is reasonable assurance the grants will be received will be undertaken on a case by case basis. Brookfield Renewable reduces the cost of the asset by the amount of the grant.  The grant amounts are recognized in income on a systematic basis as a reduction of depreciation over the periods, and in the proportions, in which depreciation on those assets is charged.

With respect to grants related to income, the government assistance (in the form of the difference between market price and guaranteed fixed price) typically becomes payable once electricity is produced and delivered to the relevant grid. It is at this point that the receipt of the grant becomes reasonably assured, and therefore the grant is recognized as revenue in the month that delivery of the electricity occurs.

(n) Critical estimates

Brookfield Renewable makes estimates and assumptions that affect the carrying value of assets and liabilities, disclosure of contingent assets and liabilities and the reported amount of income and OCI for the year. Actual results could differ from these estimates. The estimates and assumptions that are critical to the determination of the amounts reported in the consolidated financial statements relate to the following:

(i)      Property, plant and equipment

The fair value of Brookfield Renewable’s property, plant and equipment is calculated using estimates and assumptions about future electricity prices from renewable sources, anticipated long-term average generation, estimated operating and capital expenditures, future inflation rates and discount rates, as described in Note 12 - Property, plant and equipment, at fair value. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies - Property, plant and equipment for further details.

Estimates of useful lives and residual values are used in determining depreciation and amortization. To ensure the accuracy of useful lives and residual values, these estimates are reviewed on an annual basis.

(ii)     Financial instruments

Brookfield Renewable makes estimates and assumptions that affect the carrying value of its financial instruments, including estimates and assumptions about future electricity prices, long-term average generation, capacity prices, discount rates and the timing of energy delivery. Non-financial instruments are valued using estimates of future electricity prices which are estimated by considering broker quotes for the years in which there is a liquid market and, for the subsequent years, Brookfield Renewable’s best estimate of electricity prices that would allow new entrants into the market. The fair value of interest rate swaps is the estimated amount that another party would receive or pay to terminate the swap agreements at the reporting date, taking into account current market interest rates. This valuation technique approximates the net present value of future cash flows. See Note 5 - Risk management and financial instruments for more details.

(iii)    Deferred income taxes

The consolidated financial statements include estimates and assumptions for determining the future tax rates applicable to subsidiaries and identifying the temporary differences that relate to each subsidiary. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply during the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the consolidated statement of financial position dates. Operating plans and forecasts are used to estimate when the temporary difference will reverse.

F - 23

(o) Critical judgments in applying accounting policies

The following are the critical judgments that have been made in applying the accounting policies used in the consolidated financial statements and that have the most significant effect on the amounts in the consolidated financial statements:

(i)      Preparation of consolidated financial statements

These consolidated financial statements present the financial position, results of operations and cash flows of Brookfield Renewable. Judgment is required in determining what assets, liabilities and transactions are recognized in the consolidated financial statements as pertaining to Brookfield Renewable’s operations. 

(ii)     Common control transactions

Common control business combinations specifically fall outside of scope of IFRS 3 and as such management has used its judgment to determine an appropriate policy to account for these transactions, considering other relevant accounting guidance that is within the framework of principles in IFRS and that reflects the economic reality of the transactions, in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. As a result, the consolidated financial statements account for assets and liabilities acquired at the previous carrying value on the predecessor’s financial statements. Differences between the consideration given and the assets and liabilities received are recorded directly to equity.

(iii)     Property, plant and equipment

The accounting policy relating to Brookfield Renewable’s property, plant and equipment is described in Note 1(f) - Property, plant and equipment and revaluation method. In applying this policy, judgment is used in determining whether certain costs are additions to the carrying amount of the property, plant and equipment as opposed to repairs and maintenance. If an asset has been developed, judgment is required to identify the point at which the asset is capable of being used as intended and to identify the directly attributable costs to be included in the carrying value of the development asset. The useful lives of property, plant and equipment are determined by independent engineers periodically with an annual review by management.

Annually, Brookfield Renewable determines the fair value of its property, plant and equipment using a methodology that it has judged to be reasonable. The methodology is generally a 20-year discounted cash flow model. Twenty years is the period considered reasonable as Brookfield Renewable has 20-year capital plans and it believes a reasonable third party would be indifferent between extending the cash flows further in the model versus using a discounted terminal value.

The valuation model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. With respect to estimated future generation that does not incorporate long-term power purchase agreement pricing, the cash flow model uses estimates of future electricity prices using broker quotes from independent sources for the years in which there is a liquid market. The valuation of power generating assets not linked to long-term power purchase agreements also requires the development of a long-term estimate of future electricity prices. In this regard the valuation model uses a discount to the all-in cost of construction with a reasonable return, to secure energy from new renewable on-shore wind development resources as the benchmark that will establish the market price for electricity for renewable resources.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth by the year 2025 in North America and Colombia, 2023 in Europe,

F - 24

and 2021 in Brazil.  Based on current supply and demand fundamentals, Brookfield Renewable revised the year of new entry in North America to 2025 from 2023.  The year of new entry is viewed as the point when generators must build additional capacity to maintain system reliability and provide an adequate level of reserve generation with the retirement of older coal fired plants and rising environmental compliance costs in North America and Europe, and overall increasing demand in Colombia and Brazil. For the North American and European businesses, Brookfield Renewable has estimated a discount to these new-build wind prices to determine renewable electricity prices for hydroelectric and wind facilities. In Brazil and Colombia, the estimate of future electricity prices is based on a similar approach as applied in North America using a forecast of the all-in cost of development.

Terminal values are included in the valuation of hydroelectric assets in North America and Colombia. For the hydroelectric assets in Brazil, cash flows have been included based on the duration of the authorization or useful life of a concession asset without consideration of potential renewal value.

Discount rates are determined each year by considering the current interest rates, average market cost of capital as well as the price risk and the geographical location of the operational facilities as judged by management. Inflation rates are also determined by considering the current inflation rates and the expectations of future rates by economists. Operating costs are based on long-term budgets escalated for inflation.  Each operational facility has a 20-year capital plan that it follows to ensure the maximum life of its assets is achieved. Foreign exchange rates are forecasted by using the spot rates and the available forward rates, extrapolated beyond the period available. The inputs described above to the discounted cash flow model require management to consider facts, trends and plans in making its judgments as to what derives a reasonable fair value of its property, plant and equipment.

(iv)     Financial instruments

The accounting policy relating to Brookfield Renewable’s financial instruments is described in Note 1(i) - Financial instruments. In applying the policy, judgments are made in applying the criteria set out in IAS 39, Financial Instruments: Recognition and Measurement (“IAS 39”), to record financial instruments at fair value through profit and loss, and the assessments of the effectiveness of hedging relationships.

(v)      Deferred income taxes

The accounting policy relating to Brookfield Renewable’s income taxes is described in Note 1(k) - Income taxes. In applying this policy, judgments are made in determining the probability of whether deductions, tax credits and tax losses can be utilized.

F - 25

(p) Future changes in accounting policies

The following table provides a brief description of accounting standards issued but not yet effective, none of which will be early adopted by Brookfield Renewable:

Standard	Description	Effective date	Effect on financial statements
In July 2014, the IASB issued the final version of IFRS 9, Financial Instruments (“IFRS 9”).	The standard reflects all phases of the financial instruments project and replaces IAS 39, Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. This standard establishes principles for the financial reporting of financial assets and financial liabilities that will present relevant and useful information to users of financial statements for their assessment of the amounts, timing and uncertainty of an entity’s future cash flows. The new standard makes several improvements to IAS 39; mostly notably adopting a principle based approach to hedge accounting. While this does not change the type of hedging relationships or the requirement to measure ineffectiveness, it simplifies the application of hedge accounting and should allow for better alignment of risk management strategies with accounting presentation. Other changes include replacing the multiple financial asset impairment models in IAS 39 with a single model based on expected credit losses on all financial assets, and replacing the existing complex classifications structure with a business model approach based on the intent and nature of the cash flows.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 9 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard retrospectively with no restatement of comparative periods. The assessment of financial assets and liabilities under the new classification methodology has been completed.  Hedging documentation has been updated for compliance with IFRS 9 and updated risk management policies and internal controls to align with the new standard. Management has also assessed the impact of the new impairment requirements for financial assets. There are no material adjustments from the adoption of the standard.

F - 26

Standard	Description	Effective date	Effect on financial statements
IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) was issued by the IASB on May 28, 2014.	IFRS 15 outlines a single comprehensive model to account for revenue arising from contracts with customers and will replace the majority of existing IFRS requirements on revenue recognition including IAS 18, Revenue, IAS 11, Construction Contracts and related interpretations. The core principle of the standard is to recognize revenue to depict the transfer of goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard has prescribed a five-step model to apply the principles. The standard also specifies how to account for the incremental costs of obtaining a contract and the costs directly related to fulfilling a contract as well as requiring more informative and relevant disclosures. IFRS 15 applies to nearly all contracts with customers, unless covered by another standard, such as leases, financial instruments and insurance contracts. In April 2016, the IASB issued amendments to IFRS 15, which provided additional guidance on the identification of performance obligations, on assessing principal versus agent considerations and on licensing revenue. The amendments also provide additional transition relief upon initial adoption of IFRS 15 and have the same effective date as the IFRS 15 standard.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 15 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard using the modified retrospective approach. This method results in a cumulative catch-up adjustment to equity as of January 1, 2018 as if the standard had always been in effect. Management has completed its review of material revenue streams. The majority of Brookfield Renewable’s revenue streams are within the scope of IFRS 15 and are include the sale of energy, capacity and renewable energy credits through power purchase agreements or through merchant mechanisms. Based on management’s analysis, substantially all of the contracts currently in place for the year beginning on January 1, 2018 do not contain a difference in the timing or measurement of revenue recognition under the new standard and the impact of both the cumulative catch up and ongoing revenue recognition is expected to not be material to the overall statements of Brookfield Renewable.

F - 27

Standard	Description	Effective date	Effect on financial statements
IFRS 16, Leases (“IFRS 16”) was issued by the IASB on January 13, 2016.	IFRS 16 brings most leases onto the statement of financial position for lessees under a single model, eliminating the distinction between operating and finance leases. Lessor accounting remains largely unchanged and the distinction between operating and finance leases is retained. Under IFRS 16 a lessee recognizes a right-of-use asset and a lease liability. The right-of-use asset is treated similarly to other non-financial assets and depreciated accordingly, and the liability accrues interest. The lease liability is initially measured at the present value of the lease payments payable over the lease term, discounted at the rate implicit in the lease. Lessees are permitted to make an accounting policy election, by class of underlying asset, to apply a method like IAS 17’s operating lease accounting and not recognize lease assets and lease liabilities for leases with a lease term of 12 months or less, and on a lease-by-lease basis, to apply a method similar to current operating lease accounting to leases for which the underlying asset is of low value. IFRS 16 supersedes IAS 17, Leases and related interpretations. A lessee will apply IFRS 16 to its leases either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying IFRS 16 being recognized at the date of initial application.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2019, with early adoption permitted.	Management has formed its adoption working group and participated in planning sessions with Brookfield Asset Management. Management continues to evaluate the impact of IFRS 16 on the consolidated financial statements.

F - 28

2. PRINCIPAL SUBSIDIARIES

The following table lists the subsidiaries of Brookfield Renewable which, in the opinion of management, significantly affect its financial position and results of operations as at December 31, 2017:

	Jurisdiction of	Percentage of
	Incorporation	voting securities
	or Organization	owned or controlled
Alta Wind VIII LLC(1)	Delaware	100
BIF II Safe Harbor Holdings LLC(1)	Delaware	100
BIF III Holtwood LLC(1)	Delaware	100
BRE GLBL Holdings L.P.(1)	Bermuda	100
BRI Green Energy Limited(1)	Republic of Ireland	100
Brookfield BRP Canada Corp.	Alberta	100
Brookfield Energia Comercializadora Ltda	Brazil	100
Brookfield Power US Holding America Co.	Delaware	100
Brookfield Power Wind Prince LP	Ontario	100
Brookfield Renewable UK Hydro Limited	England and Wales	100
Brookfield Smoky Mountain Hydropower LLC(1)	Delaware	100
Brookfield White Pine Hydro LLC(1)	Delaware	100
Catalyst Old River Hydroelectric Limited Partnership(2)	Louisiana	75
Erie Boulevard Hydropower, L.P.	Delaware	100
Granite Reliable Power, LLC(1)	Delaware	89.5
Great Lakes Hydro America, LLC	Delaware	100
Great Lakes Power Limited	Ontario	100
Hawks Nest Hydro LLC	Delaware	100
Isagen S.A. E.S.P.(1)	Colombia	99.5
Itiquira Energética S.A.	Brazil	100
Kwagis Power Limited Partnership	British Columbia	75
Lièvre Power L.P.	Québec	100
Mississagi Power Trust	Québec	100
Orion Canadian Holdings 1 AIV L.P.	Ontario	100
PEA - Parque Eólico da Serra, Unipessola S.A.(1)	Portugal	100
Powell River Energy Inc.	Canada	100
Rumford Falls Hydro LLC	Delaware	100
Safe Harbor Water Power Corporation(1)	Pennsylvania	100
Tangará Energia S.A.(1)	Brazil - São Paulo	100
Windstar Energy, LLC	California	100
2016 Comber Wind Limited Partnership	Ontario	100

⁽¹⁾Voting control held through voting agreements with Brookfield.

⁽²⁾Non-voting economic interest held through preferred shares and secured notes.

F - 29

3.  ACQUISITIONS

The following investments were accounted for using the equity method asBrookfield Renewable has significant influence through its position in the business, and the results of operations have been included in the audited annual consolidated financial statements since the date of investment. See Note 19 – Equity-accounted investments.

European Storage

In August 2017, Brookfield Renewable, along with its institutional partners, acquired a 25% interest in FHH Guernsey Ltd which owns a 2.1 GW pumped storage portfolio in the United Kingdom (“European Storage”). Brookfield Renewable retains an approximate 7% economic interest in the portfolio. Total consideration was £194 million ($248 million). The acquisition costs of £1 million ($1 million) were incurred and capitalized.

TerraForm Power

In October 2017, along with its institutional partners, Brookfield Renewable closed the acquisition of a 51% interest in TerraForm Power, Inc. (“TerraForm Power”). TerraForm Power is a 2,600 MW large scale diversified portfolio of solar and wind assets located predominately in the U.S. Brookfield Renewable retains an indirect economic interest of approximately 16% in TerraForm Power for a total net investment of $203 million.

Brookfield Renewable had previously accounted for its indirect interest in TerraForm Power as an available for sale investment. The change from available for sale accounting to equity method accounting resulted in a gain of $13 million being reclassified from the audited annual consolidated statement of comprehensive income to the statement of income and included in Other income, representing the accumulated gain on the previously held indirect investment.The acquisition costs of $1 million were incurred and capitalized.

In October 2017, Brookfield Renewable entered into a voting agreement with the Brookfield subsidiary that ultimately controls TerraForm Power. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election for one of the four directors of the Brookfield subsidiary, thereby providing Brookfield Renewable with significant influence over this subsidiary.

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the date of acquisition.

European Wind

In February 2017, Brookfield Renewable entered into an agreement to acquire, along with its institutional partners, a 100% interest in a 16 MW wind facility in Northern Ireland (“European Wind”). 

In August 2017, Brookfield Renewable, along with its institutional partners, completed the acquisition of European Wind, which was commissioned in July of 2017. Accordingly, if the acquisition had taken place at the beginning of the year, the revenue from European Wind earned prior to the date of acquisition would have been immaterial. The total consideration was £24 million ($32 million). Brookfield Renewable retains an approximate 40% controlling interest in the asset. The total acquisition costs of less than $1 million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income.

TerraForm Global

In December 2017, along with its institutional partners, Brookfield Renewable closed the acquisition of a 100% interest in TerraForm Global, Inc. (“TerraForm Global”). TerraForm Global is 919 MW portfolio of diversified solar and wind assets located predominately in Brazil and Asia. The total consideration paid

F - 30

was $657 million and the fair value of the interest previously held was $100 million. Brookfield Renewable retains a 31% economic interest in TerraForm Global with its share of the fair value of previously held interest on the acquisition date totaling $30 million. Brookfield Renewable’s share of the consideration paid was $202 million.

Brookfield Renewable had previously accounted for its indirect interest in TerraForm Global as an available for sale investment. The change from available for sale accounting to consolidation accounting resulted in a gain of $2 million being reclassified from the audited annual consolidated statement of comprehensive income to the statement of income and included in Other income, representing the accumulated gain on the previously held indirect investment.

If the acquisition had taken place at the beginning of the year, the revenue from TerraForm Global for the year ended December 31, 2017 would have been $250 million.  The total acquisition costs of $1 million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income.

In December 2017, Brookfield Renewable entered into a voting agreement with an affiliate of Brookfield Renewable that ultimately controls TerraForm Global. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of the directors of the Brookfield subsidiary.

The provisional purchase price allocations, at fair value, with respect to the acquisitions are as follows:

	TerraForm		European
(MILLIONS)	Global		Wind		Total
Cash and cash equivalents	$	611	$	-	$	611
Restricted cash		90		-		90
Trade receivables and other current assets		62		1		63
Financial instruments		20		-		20
Property, plant and equipment, at fair value		1,208		37		1,245
Deferred tax assets		18		-		18
Other long-term assets		94		-		94
Current liabilities		(73)		(4)		(77)
Current portion of long-term debt		(1,183)		-		(1,183)
Financial instruments		(15)		-		(15)
Long-term debt		(5)		-		(5)
Deferred income tax liabilities		(15)		(2)		(17)
Other long-term liabilities		(54)		-		(54)
Non-controlling interests		(1)		-		(1)
Fair value of net assets acquired		757		32		789

F - 31

Completed in 2016

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the respective dates of acquisition.

Colombia Portfolio

On January 22, 2016, Brookfield Renewable and its institutional partners (the “consortium”) acquired a 57.6% interest in Isagen S.A. E.S.P (“Isagen”) from the Colombian government (the “Initial Investment”). Isagen was a listed entity in Colombia.  It is Colombia’s third-largest power generation company and owns and operates a 3,032 MW portfolio, consisting predominantly of a portfolio of largely reservoir-based, hydroelectric facilities. Annual generation is expected to approximate 15,000 GWh.

Following the closing of the Initial Investment, the consortium was required to conduct two mandatory tender offers (“MTOs”) for the Isagen public shareholders at the same price per share paid for its initial 57.6% controlling interest.

The consortium closed the First MTO and the Second MTO on May 13, 2016 and September 14, 2016, respectively. During 2017, the consortium acquired further shares from public shareholders and completed delisting of Isagen from the Colombia Stock Exchange. After giving effect to the MTOs and additional shares the consortium ownership stands at 99.5% as of December 31, 2017.

Brookfield Renewable is the general partner of and controls the entity that holds the consortium’s 99.5% interest in Isagen. Brookfield Renewable’s investment is equivalent to an approximate 24% economic interest.

The total acquisition costs of $13 million were expensed as incurred and have been classified under Other in theaudited annual consolidated statements of income in 2016.

If the acquisition had taken place at the beginning of the year, the revenue from Isagen for the year ended December 31, 2016 would have been $900 million.

Brazil Portfolio

In January 2016, Brookfield Renewable acquired a 51 MW hydroelectric portfolio in Brazil (“Brazil Portfolio”). Total consideration of R$417 million ($103 million) included cash paid of R$355 million ($88 million), deferred consideration of R$35 million ($9 million) and the impact of the foreign currency contracts of R$24 million ($6 million). Brookfield Renewable retains a 100% interest in the portfolio.

The total acquisition costs of less than $1 million were expensed as incurred and classified under Other in the audited annual consolidated statements of income in 2016.

North American Portfolio

In April 2016, Brookfield Renewable acquired a 296 MW portfolio of hydroelectric facilities in Pennsylvania that are expected to generate 1,109 GWh annually (“Pennsylvania Hydro”). The acquisition was completed with institutional partners, and Brookfield Renewable retains approximately 28.6% interest in the portfolio.

Total cash consideration was $859 million. The acquisition costs of $6 million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income in 2016.

If the acquisition had taken place at the beginning of the year, the revenue from Pennsylvania Hydro for the year ended December 31, 2016 would have been $46 million.

F - 32

In April 2016, Brookfield Renewable entered into a voting agreement with a Brookfield subsidiary that forms part of Brookfield Infrastructure Fund III. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of the directors of the entity that ultimately controls and operates the Pennsylvania Hydro assets.  

European Wind Development Project

In September 2016, Brookfield Renewable acquired a 19 MW wind development project in Ireland. The total consideration of €8 million ($9 million) included cash consideration of €7 million ($8 million) and deferred consideration and working capital adjustments of €1 million ($1 million). The acquisition was completed with institutional partners, and Brookfield Renewable retained an approximately 40% controlling interest in the asset. The total acquisition costs of less than $1 million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income.

Purchase price allocations

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Colombia		Brazil		Pennsylvania		Ireland		Total
Cash and cash equivalents	$	113	$	4	$	-	$	-	$	117
Trade receivables and other current assets		174		2		1		-		177
Property, plant and equipment, at fair value		4,772		100		859		10		5,741
Other long-term assets		15		-		-		-		15
Current liabilities		(463)		(3)		(1)		-		(467)
Long-term debt		(899)		-		-		-		(899)
Deferred income tax liabilities		(1,019)		-		-		(1)		(1,020)
Other long-term liabilities		(149)		-		-		-		(149)
Non-controlling interests		(1,417)		-		-		-		(1,417)
Fair value of net assets acquired		1,127		103		859		9		2,098
Goodwill (Note 17)		799		-		-		-		799
Purchase price	$	1,926	$	103	$	859	$	9	$	2,897

Completed in 2015

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the respective dates of acquisition.

European Wind Portfolio

In February 2015, Brookfield Renewable acquired two wind facilities in Portugal (“Portugal Wind Portfolio”) with an aggregate capacity of 123 MW, and expected to generate 260 GWh annually.

The acquisition was completed with institutional partners, and Brookfield Renewable retains an approximate 40% controlling interest. Total consideration of €65 million ($71 million) included cash paid on closing of €58 million ($63 million), post-closing adjustments, and deferred consideration.

The revenue for the year ended December 31, 2015 is $28 million.

In June 2015, Brookfield Renewable acquired an onshore wind development pipeline in Scotland (“Scotland Wind Pipeline”) totaling approximately 1,200 MW, including a mix of contracted, permitted and earlier stage development projects. Total consideration of £47 million ($72 million) included upfront cash paid of £40 million ($62 million), contingent consideration, and working capital adjustments. The

F - 33

acquisition costs of $1 million were expensed as incurred. The contingent consideration was recorded at its fair value of £6 million ($9 million), which represents the present value of a probability-weighted evaluation of Brookfield Renewable’s obligation to pay up to £63 million ($97 million) related to the build-out of the development pipeline. The contingent consideration was recognized in the Consolidated Statements of Financial Position within the Other long-term liabilities line item.

Brazil Portfolio

In November 2014, Brookfield Renewable entered into an agreement to acquire a 488 MW portfolio in Brazil comprising of hydroelectric, wind and biomass generating capacity (“Brazil Portfolio”). The acquisitions were completed in 2015 with institutional partners, and Brookfield Renewable retains an approximate 40% controlling interest.

Total consideration of R$1,867 million ($588 million) included cash paid of R$1,717 million ($541 million) and deferred consideration. The remaining non-controlling interests were subsequently acquired for R$50 million ($16 million). The total acquisition costs of $2 million were expensed as incurred.

If the acquisition had taken place at the beginning of 2015 the revenue from the acquisition would have been $93 million (unaudited) for the year ended December 31, 2015.

Voting Agreements

In March 2015, Brookfield Renewable entered into voting agreements with certain Brookfield subsidiaries (and their managing members) related to Brookfield Infrastructure Fund II (the “BIF II Entities”) which are co-investors along with a subsidiary of Brookfield Renewable in Brazilian entities (the “FIPs”) which hold the Brazil Portfolio power generating operations. Pursuant to these voting agreements, the BIF II Entities agreed to provide Brookfield Renewable, among other things, the authority to direct the election of the manager of the jointly-owned FIPs.  

Purchase price allocations

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Brazil		Portugal		Scotland		Total
Cash and cash equivalents	$	19	$	-	$	-	$	19
Restricted cash		16		5		-		21
Trade receivables and other current assets		16		3		1		20
Property, plant and equipment, at fair value		854		209		84		1,147
Current liabilities		(21)		(19)		(1)		(41)
Long-term debt		(280)		(111)		-		(391)
Other long-term liabilities		-		(16)		(12)		(28)
Non-controlling interests		(16)		-		-		(16)
Net assets acquired	$	588	$	71	$	72	$	731

During the years ended December 31, 2017 and 2016, the purchase price allocations for the acquisitions in 2016 and 2015, respectively, were finalized. No material changes to the provisional purchase price allocations disclosed in the audited annual consolidated financial statements for 2016 and 2015 had to be considered for acquisitions made in the respective years.

F - 34

4.  DISPOSAL OF ASSETS

In March 2017, along with its institutional partners, Brookfield Renewable sold its interest in two wind facilities in Ireland, with a combined capacity of 137 MW, to a third party. Gross cash consideration consisted of €147 million ($155 million), inclusive of working capital adjustments. The resulting loss on disposition of €5 million ($5 million), net of €5 million ($5 million) of transaction costs, was recognized in the audited annual consolidated statements of income within Other. Brookfield Renewable’s interest was approximately 40%.

As a result of the disposition, the post-tax accumulated revaluation surplus of €44 million ($47 million) was reclassified from other comprehensive income directly to equity. Further, other comprehensive loss of €3 million ($3 million) post-tax on interest rate swaps which had been designated as hedges was reclassified to the audited annual consolidated statements of income. 

Summarized financial information relating to the disposal of the facilities is shown below:

(MILLIONS)
Net proceeds, including working capital adjustments and transaction costs		$	150
Carrying value
	Assets		353
	Liabilities		(198)
			155
Loss on disposal		$	(5)

F - 35

5.  RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT

Brookfield Renewable’s activities expose it to a variety of financial risks, including market risk (i.e., commodity price risk, interest rate risk, and foreign currency risk), credit risk and liquidity risk. Brookfield Renewable uses financial instruments primarily to manage these risks.

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes. Therefore, the discussion below is not intended to fully reflect Brookfield Renewable’s risk exposure.

(a) Market risk

Market risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate because of changes in market prices.

Brookfield Renewable faces market risk from foreign currency assets and liabilities, the impact of changes in interest rates, and floating rate liabilities. Market risk is managed by funding assets with financial liabilities in the same currency and with similar interest rate characteristics and holding financial contracts, such as interest rate swaps and foreign exchange contracts, to minimize residual exposures. Financial instruments held by Brookfield Renewable that are subject to market risk include borrowings and financial instruments, such as interest rate, currency and commodity contracts. The categories of financial instruments that can give rise to significant variability are described below:

(i) Electricity price risk

Electricity price risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate because of changes in electricity prices.  Electricity price risk arises from the sale of Brookfield Renewable’s uncontracted generation. Brookfield Renewable aims to sell electricity under long-term contracts to secure stable prices and mitigate its exposure to wholesale markets.

The table below summarizes the impact of changes in the market price of electricity as at December 31.  The impact is expressed in terms of the effect on net income and OCI.  The sensitivities are based on the assumption that the market price changes by five percent with all other variables held constant.

Impact of a 5% change in the market price of electricity, on outstanding energy derivative contracts, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	(3)	$	(1)	$	(2)	$	(4)	$	(7)	$	(7)
5% decrease		3		1		2		4		7		7

⁽¹⁾Amounts represent the potential annual net pretax impact.

(ii) Foreign currency risk

Foreign currency risk is defined for these purposes as the risk that the fair value of a financial instrument held by Brookfield Renewable will fluctuate because of changes in foreign currency rates.

Brookfield Renewable has exposure to the Canadian dollar, Brazilian real, Euro, British pound sterling, Colombian peso, Indian rupee, South African rand, Malaysian ringgit, Thai baht and Chinese yuan through its investments in foreign operations. Consequently, fluctuations in the U.S. dollar exchange rate

F - 36

against these currencies increase the volatility of net income and other comprehensive income. Brookfield Renewable holds foreign currency contracts primarily to mitigate this exposure.

The table below summarizes the impact of changes in the exchange rate as at December 31. The impact is expressed in terms of the effect on income and OCI. The sensitivities are based on the assumption that the currency exchange rate changes by five percent with all other variables held constant.

Impact of a 5% change in U.S. dollar exchange rates, on outstanding foreign exchange swaps, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	4	$	1	$	2	$	79	$	51	$	10
5% decrease		(4)		(1)		(2)		(79)		(51)		(10)

⁽¹⁾Amounts represent the potential annual net pretax impact.

(iii) Interest rate risk

Interest rate risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate, because of changes in interest rates.

Brookfield Renewable’s assets largely consist of long duration physical assets. Brookfield Renewable’s financial liabilities consist primarily of long-term fixed rate debt or floating-rate debt that has been swapped to fixed rates with interest rate financial instruments. All non-derivative financial liabilities are recorded at their amortized cost. Brookfield Renewable also holds interest rate contracts to lock-in fixed rates on certain anticipated future debt issuances.

Brookfield Renewable will enter into interest rate swaps designed to minimize the exposure to interest rate fluctuations on its variable rate debt.  Fluctuations in interest rates could impact Brookfield Renewable’s cash flows, primarily with respect to the interest payable against Brookfield Renewable’s variable rate debt, which is limited to certain subsidiary borrowings with a total principal value of $4,176 million (2016: $4,194 million). Of this principal value, $824 million (2016: $966 million) has been hedged through the use of interest rate swaps. The fair values of the recognized liability for the interest rate swaps were calculated using a valuation model with observable interest rates. 

The table below summarizes the impact of changes in the interest rate as at December 31. The impact is expressed in terms of the effect on income and OCI. The sensitivities are based on the assumption that the interest rate changes by one percent with all other variables held constant.

Impact of a 1% change in interest rates, on outstanding interest rate swaps and variable rate debt, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
1% increase	$	17	$	(17)	$	(15)	$	54	$	115	$	125
1% decrease		(17)		17		15		(54)		(115)		(125)

⁽¹⁾Amounts represent the potential annual net pretax impact.

(b) Credit risk

Credit risk is the risk of loss due to the failure of a borrower or counterparty to fulfill its contractual obligations. Brookfield Renewable’s exposure to credit risk in respect of financial instruments relates primarily to counterparty obligations regarding energy contracts, interest rate swaps, forward foreign exchange contracts and physical electricity and gas transactions. 

F - 37

Brookfield Renewable minimizes credit risk with counterparties through the selection, monitoring and diversification of counterparties, and the use of standard trading contracts, and other credit risk mitigation techniques.  In addition, Brookfield Renewable’s power purchase agreements are reviewed regularly and are almost exclusively with customers having long standing credit histories or investment grade ratings, which limit the risk of non-collection. See Note 22 - Trade receivables and other current assets, for additional details regarding Brookfield Renewable’s trade receivables balance.

The maximum credit exposure at December 31 was as follows:

(MILLIONS)		2017		2016
Cash and cash equivalents	$	799	$	223
Restricted cash(1)		284		250
Trade receivables and other short-term receivables		442		365
Financial instrument assets(1)		185		200
Due from related parties		60		54
	$	1,770	$	1,092

⁽¹⁾Includes both the current and long-term amounts.  

(c) Liquidity risk

Liquidity risk is the risk that Brookfield Renewable cannot meet a demand for cash or fund an obligation when due.  Liquidity risk is mitigated by Brookfield Renewable’s cash and cash equivalent balances and its access to undrawn credit facilities. Details of the available portion of credit facilities are included in Note 13 – Long-term debt and credit facilities.  Brookfield Renewable also ensures that it has access to public capital markets and maintains a strong investment grade credit rating.

Brookfield Renewable is also subject to the risk associated with debt financing. This risk is mitigated by the long-term duration of debt instruments and the diversification in maturity dates over an extended period of time.

F - 38

CASH OBLIGATIONS

The table below classifies the cash obligations related to Brookfield Renewable’s liabilities into relevant maturity groupings based on the remaining period from the statement of financial position dates to the contractual maturity date.  As the amounts are the contractual undiscounted cash flows (gross of unamortized financing fees and accumulated amortization, where applicable), they may not agree with the amounts disclosed in the consolidated statements of financial position.

AS AT DECEMBER 31, 2017
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	542	$	-	$	-	$	542
Financial instrument liabilities(1)		184		62		24		270
Due to related parties		112		-		-		112
Other long-term liabilities - concession payments		1		3		10		14
Long-term debt and credit facilities(1)		1,676		4,587		5,579		11,842
Interest payable on long-term debt(2)		634		1,924		1,697		4,255
Total	$	3,149	$	6,576	$	7,310	$	17,035
AS AT DECEMBER 31, 2016
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	467	$	-	$	-	$	467
Financial instrument liabilities(1)		156		66		6		228
Due to related parties		76		-		-		76
Other long-term liabilities - concession payments		1		4		11		16
Long-term debt and credit facilities(1)		1,034		3,970		5,256		10,260
Interest payable on long-term debt(2)		589		1,821		1,449		3,859
Total	$	2,323	$	5,861	$	6,722	$	14,906

⁽¹⁾       Includes both the current and long-term amounts.  

⁽²⁾       Represents aggregate interest payable expected to be paid over the entire term of the obligations, if held to maturity. Variable rate interest payments have been calculated based on estimated interest rates.

F - 39

Brookfield Renewable classifies its assets and liabilities as outlined below:

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2017	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	799	$	-	$	-	$	-	$	-	$	799
Restricted cash		181	-	-		-		-		-		181
Trade and other receivables(2)		442		-		-		-		-		442
Other current assets		-		-		-		-		112		112
Due from related parties(2)		60		-		-		-		-		60
Financial instrument assets(3)		-		20		6		159		-		185
Equity-accounted investments		-		-		-		-		721		721
Property, plant and equipment, at fair value		-		-		-		-		27,096		27,096
Goodwill		-		-		-		-		901		901
Deferred income tax assets		-		-		-		-		177		177
Other long-term assets		103		-		-		-		127		230
Total assets	$	1,585	$	20	$	6	$	159	$	29,134	$	30,904
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	542	$	-	$	542
Financial instrument liabilities(3)		-		145		125		-		-		270
Due to related parties(2)		-		-		-		112		-		112
Long-term debt and credit facilities(2)(3)		-		-		-		11,766		-		11,766
Deferred income tax liabilities		-		-		-		-		3,588		3,588
Other long-term liabilities		-		-		-		344		-		344
Total liabilities	$	-	$	145	$	125	$	12,764	$	3,588	$	16,622

⁽¹⁾Measured at fair value with all gains and losses recorded in the consolidated statement of income.

⁽²⁾Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.

⁽³⁾Includes both the current and long-term amounts.

F - 40

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2016	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	223	$	-	$	-	$	-	$	-	$	223
Restricted cash		121		-		-		-		-		121
Trade and other receivables(2)		365		-		-		-		-		365
Other current assets		-		-		-		-		89		89
Due from related parties(2)		54		-		-		-		-		54
Financial instrument assets(3)		-		14		50		136		-		200
Equity-accounted investments		-		-		-		-		206		206
Property, plant and equipment, at fair value		-		-		-		-		25,257		25,257
Goodwill		-		-		-		-		896		896
Deferred income tax assets		-		-		-		-		150		150
Other long-term assets		129		-		-		-		47		176
Total assets	$	892	$	14	$	50	$	136	$	26,645	$	27,737
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	467	$	-	$	467
Financial instrument liabilities(3)		-		11		217		-		-		228
Due to related parties(2)		-		-		-		76		-		76
Long-term debt and credit facilities(2)(3)		-		-		-		10,182		-		10,182
Deferred income tax liabilities		-		-		-		-		3,802		3,802
Other long-term liabilities		-		-		-		310		-		310
Total liabilities	$	-	$	11	$	217	$	11,035	$	3,802	$	15,065

⁽¹⁾Measured at fair value with all gains and losses recorded in the consolidated statement of income.

⁽²⁾Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.

⁽³⁾Includes both the current and long-term amounts.

Fair value disclosures

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, management looks primarily to external readily observable market inputs such as interest rate yield curves, currency rates, commodity prices and, as applicable, credit spreads.

A fair value measurement of a non-financial asset is the consideration that would be received in an orderly transaction between market participants, considering the highest and best use of the asset.

Assets and liabilitiesmeasured at fair value are categorized into one of three hierarchy levels, described below. Each level is based on the transparency of the inputs used to measure the fair values of assets and liabilities.

Level 1 –inputs are based on unadjusted quoted prices in active markets for identical assets and liabilities;

Level 2 – inputs, other than quoted prices in Level 1, that are observable for the asset or liability, either directly or indirectly; and

Level 3 – inputs for the asset or liability that are not based on observable market data.

F - 41

The following table presents Brookfield Renewable’s assets and liabilities measured and disclosed at fair value classified by the fair value hierarchy as at December 31:

(MILLIONS)		Level 1		Level 2		Level 3		2017		2016
Assets measured at fair value:
Cash and cash equivalents		$	799	$	-	$	-	$	799	$	223
Restricted cash(1)			284		-		-		284		250
Financial instrument assets(2)
	Energy derivative contracts		-		-		-		-		8
	Interest rate swaps		-		6		-		6		7
	Foreign exchange swaps		-		20		-		20		49
	Available-for-sale investments(2)		79		80		-		159		136
Property, plant and equipment			-		-		27,096		27,096		25,257
Liabilities measured at fair value:
Financial instrument liabilities(3)
	Energy derivative contracts		-		(19)		-		(19)		(5)
	Interest rate swaps		-		(155)		-		(155)		(178)
	Foreign exchange swaps		-		(96)		-		(96)		(45)
Contingent consideration(4)			-		-		(18)		(18)		(16)
Liabilities for which fair value is disclosed:
	Long-term debt and credit facilities		-		(12,479)		-		(12,479)		(10,870)
Total		$	1,162	$	(12,643)	$	27,078	$	15,597	$	14,816

⁽¹⁾Includes both the current amount and long-term amount included in Other long-term assets.

⁽²⁾Includes amounts in Level 2 that relate to the Brookfield Infrastructure Debt Fund holdings.

⁽³⁾Includes both current and long-term amounts.

⁽⁴⁾Amount relates to 2015 and 2014 business combinations with obligations lapsing in 2021 and 2024 respectively.

There were no transfers between levels during the year ended December 31, 2017.

Financial instruments disclosures

The aggregate amount of Brookfield Renewable’s net financial instrument positions as at December 31 are as follows:

				2017				2016
					Net Liabilities		Net Liabilities
(MILLIONS)	Assets		Liabilities		(Assets)		(Assets)
Energy derivative contracts	$	-	$	19	$	19	$	(3)
Interest rate swaps		6		155		149		171
Foreign exchange swaps		20		96		76		(4)
Available-for-sale securities		159		-		(159)		(136)
Total		185		270		85		28
Less: current portion		72		184		112		101
Long-term portion	$	113	$	86	$	(27)	$	(73)

F - 42

The following table presents the change in Brookfield Renewable’s total net financial instrument liability position as at and for the year ended December 31:

(MILLIONS)		Note		2017		2016		2015
Balance, beginning of year			$	28	$	145	$	77
Increases (decreases) in the net financial instrument liability position:
	Unrealized loss (gain) through income on energy derivative contracts	(a)		5		-		(2)
	Unrealized loss through OCI on energy derivative contracts	(a)		17		28		3
	Unrealized (gain) loss through income on interest rate swaps	(b)		(1)		7		(2)
	Unrealized (gain) loss through OCI on interest rate swaps	(b)		(18)		1		20
	Unrealized loss (gain) through income on foreign exchange swaps	(c)		29		(3)		13
	Unrealized loss (gain) through OCI on foreign exchange swaps	(c)		94		61		(57)
	Unrealized loss through income on available-for-sale investments	(d)		-		-		25
	Unrealized loss (gain) through OCI on available-for-sale investments	(d)		20		(52)		-
	Acquisitions, settlements and other			(89)		(159)		68
Balance, end of year			$	85	$	28	$	145
Financial instrument liabilities not designated as hedging instruments:
Energy derivative contracts		(a)	$	5	$	3	$	-
Interest rate swaps		(b)		107		2		-
Foreign exchange swaps		(c)		33		6		-
Net positions			$	145	$	11	$	-
Financial instrument liabilities designated as hedging instruments:
Energy derivative contracts		(a)	$	14	$	2	$	1
Interest rate swaps		(b)		48		176		178
Foreign exchange swaps		(c)		63		39		12
Net positions			$	125	$	217	$	191
Financial instrument assets not designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(3)	$	-
Interest rate swaps		(b)		(1)		(1)		-
Foreign exchange swaps		(c)		(19)		(10)		(1)
Available-for-sale investments		(d)		(159)		(136)		(14)
Net positions			$	(179)	$	(150)	$	(15)
Financial instrument assets designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(5)	$	(31)
Interest rate swaps		(b)		(5)		(6)		-
Foreign exchange swaps		(c)		(1)		(39)		-
Net positions			$	(6)	$	(50)	$	(31)
Total net positions			$	85	$	28	$	145

(a)  Energy derivative contracts

Brookfield Renewable has entered into long-term energy derivative contracts primarily to stabilize or eliminate the price risk on the sale of certain future power generation. Certain energy contracts are

F - 43

recorded in Brookfield Renewable’s consolidated financial statements at an amount equal to fair value, using quoted market prices or, in their absence, a valuation model using both internal and third-party evidence and forecasts.

For the year ended December 31, 2017, gains of $23 million relating to energy derivative contracts were realized and reclassified from OCI to revenues in the consolidated statements of income (loss) (2016: $48 million and 2015: $32 million).

Based on market prices as of December 31, 2017, unrealized losses of $9 million (2016: $6 million gains and 2015: $25 million gains) recorded in accumulated other comprehensive income (“AOCI”) on energy derivative contracts are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market prices.

(b)  Interest rate hedges

Brookfield Renewable has entered into interest rate hedge contracts primarily to minimize exposure to interest rate fluctuations on its variable rate debt or to lock in interest rates on future debt refinancing.  All interest rate hedge contracts are recorded in the consolidated financial statements at fair value.

At December 31, 2017, agreements with a total notional exposure of $1,704 million were outstanding (2016: $2,397 million) including $780 million (2016: $871 million) associated with agreements that are not formally designated as hedging instruments. The weighted-average fixed interest rate resulting from these agreements is 4.5% (2016: 2.5%).

For the year ended December 31, 2017, net movements relating to cash flow hedges realized and reclassified from OCI to interest expense – borrowings in the consolidated statements of income (loss) were $20 million losses (2016: $16 million and 2015: $nil).

Based on market prices as of December 31, 2017, unrealized losses of $18 million (2016: $110 million and 2015: $114 million) recorded in AOCI on interest rate swaps are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market rates.

(c)  Foreign exchange swaps

Brookfield Renewable has entered into foreign exchange swaps to minimize its exposure to currency fluctuations impacting its investments and earnings in foreign operations, and to fix the exchange rate on certain anticipated transactions denominated in foreign currencies.

At December 31, 2017, agreements with a total notional exposure of $2,306 million were outstanding (2016: $1,325 million) including $718 million (2016: $283 million) associated with agreements that are not formally designated as hedging instruments.

Based on market prices as of December 31, 2017, unrealized losses of $48 million (2016: $1 million and 2015: $12 million) recorded in AOCI on foreign exchange swaps are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market rates.

(d)  Available-for-sale

Brookfield Renewable’s available for sale assets consist of investments in liquid equity and debt securities.

Available-for-sale securities are recorded on the statement of financial position at fair value, and are assessed for impairment at each reporting date. For the year ended December 31, 2017, net movements

F - 44

relating to available-for-sale securities realized and reclassified from OCI to net income were $2 million gains (2016: $9 million gains and 2015: $nil).

Unrealized loss through OCI on available-for-sale investments of $20million relate to the impact of our acquisition of TerraForm Power.

6.  SEGMENTED INFORMATION

Brookfield Renewable’s Chief Executive Officer and Chief Financial Officer (collectively, the chief operating decision maker or “CODM”) review the results of the business, manage operations, and allocate resources based on the type of technology.

With effect from the fourth quarter of 2017, operations are segmented by technology – 1) hydroelectric, 2) wind, 3) solar, storage, and other (Co-gen and biomass), and 4) corporate – with hydroelectric and wind further segmented by geography (North America, Colombia, Brazil, Europe and Other). To reflect the way in which the CODM now reviews results, manage operations and allocate resources, following the investments in European Storage, TerraForm Power and TerraForm Global and as Brookfield Renewable continues to build out its solar and storage businesses, the CODM has commenced reviewing these businesses along with its Co-gen and biomass businesses on an aggregate basis.  The Colombia segment aggregates the financial results of its hydroelectric and Co-gen facilities. A pumped storage facility in North America, that was previously included in the hydroelectric segment, is now included in the “Solar, storage and other” segment. The corporate segment represents all activity performed above the individual segments for the business.

In addition, with the effect from the fourth quarter of 2017, the reporting to the CODM such that the measures utilized by the CODM to assess performance and allocate resources are on a proportionate basis. Information on a proportionate basis reflects Brookfield Renewable’s share from facilities which it accounts for using consolidation and the equity method whereby Brookfield Renewable either controls or exercises significant influence or joint control over the investment, respectively. Proportionate information provides a Unitholder (holders of the GP interest, Redeemable/Exchangeable partnership units, and LP Units) perspective that the CODM considers important when performing internal analyses and making strategic and operating decisions. The CODM also believes that providing proportionate information helps investors understand the impacts of decisions made by management and financial results allocable to Brookfield Renewable’s Unitholders.

Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Tables reconciling IFRS data with data presented on a proportionate consolidation basis have been disclosed. Segment revenues, other income, direct operating costs, interest expense, depreciation, current and deferred income taxes, and other are items that will differ from results presented in accordance with IFRS as these items (1) include Brookfield Renewable’s proportionate share of earnings from equity-accounted investments attributable to each of the above-noted items, and (2) exclude the proportionate share of earnings (loss) of consolidated investments not held by us apportioned to each of the above-noted items.

Segmented net income (loss) is not a measure the CODM uses to review the results of business and allocate resources. Brookfield Renewable does not control those entities that have not been consolidated and as such, have been presented as equity-accounted investments in its financial statements. The presentation of the assets and liabilities and revenues and expenses do not represent Brookfield Renewable’s legal claim to such items, and the removal of financial statement amounts that are attributable to non-controlling interests does not extinguish Brookfield Renewable’s legal claims or exposures to such items.

F - 45

Brookfield Renewable reports its results in accordance with these segments and presents prior period segmented information in a consistent manner.

In accordance with IFRS 8, Operating Segments, Brookfield Renewable discloses information about its reportable segments based upon the measures used by the CODM in assessing performance. The accounting policies of the reportable segments are the same as those described in Note 1 – Basis of preparation and significant accounting policies. Brookfield Renewable analyzes the performance of its operating segments based on revenues, Adjusted EBITDA, and Funds From Operations.

Brookfield Renewable uses Adjusted EBITDA to assess the performance of its operations before the effects of interest expense, income taxes, depreciation, management service costs, non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments, distributions to preferred shareholders and preferred limited partners and other typical non-recurring items. As compared to the preceding years, Brookfield Renewable revised its definition of Adjusted EBITDA to include its proportionate share of Adjusted EBITDA from equity-accounted investments. In preceding years, Brookfield Renewable included its proportionate shares of Funds From Operations from equity-accounted investments. Brookfield Renewable revised its definition as it believes it provides a more meaningful measure for investors to evaluate financial and operating performance on an allocable basis to Unitholders.

Brookfield Renewable uses Funds From Operations to assess the performance of its business and is defined as Adjusted EBITDA less management service costs, interest and current income taxes, which is then adjusted for the cash portion of non-controlling interests and distributions to preferred shareholders and preferred limited partners.

The following segmented information is regularly reported to the CODM.

F - 46

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’s investments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2017:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Solar,		Corporate		Total	equity		to non-		As per
		North						North						Storage and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			945		191		243		161		46		26		67		-	1,679		(74)		1,020		2,625
Other income			1		2		12		-		-		-		6		19	40		(11)		18		47
Direct operating costs			(281)		(94)		(77)		(42)		(20)		(4)		(34)		(25)	(577)		28		(429)		(978)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		57		-		57
Adjusted EBITDA			665		99		178		119		26		22		39		(6)	1,142		-		609		-
Management service costs			-		-		-		-		-		-		-		(82)	(82)		-		-		(82)
Interest expense - borrowings			(180)		(42)		(18)		(45)		(10)		(6)		(17)		(89)	(407)		21		(246)		(632)
Current income taxes			1		(5)		(12)		-		(1)		-		(1)		-	(18)		1		(22)		(39)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(28)	(28)		-		-		(28)
	Preferred equity		-		-		-		-		-		-		-		(26)	(26)		-		-		(26)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(22)		-		(22)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(341)		(341)
Funds From Operations			486		52		148		74		15		16		21		(231)	581		-		-		-
Depreciation			(222)		(26)		(141)		(89)		(24)		(8)		(29)		-	(539)		22		(265)		(782)
Unrealized financial instrument loss			(3)		(3)		-		(1)		(12)		-		-		(10)	(29)		1		(5)		(33)
Deferred income tax expense			(67)		(10)		2		45		6		-		1		(3)	(26)		(3)		(20)		(49)
Other			(20)		6		(8)		(3)		(5)		2		(6)		(9)	(43)		13		2		(28)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(33)		-		(33)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		288		288
Net income (loss) attributable to Unitholders(2)			174		19		1		26		(20)		10		(13)		(253)	(56)		-		-		(56)

⁽¹⁾Share of earnings from equity-accounted investments of $2 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $53 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

F - 47

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’s investments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2016:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		192		187		151		56		17		58		1	1,481		(37)		1,008		2,452
Other income			24		3		13		-		-		-		(1)		8	47		-		17		64
Direct operating costs			(295)		(107)		(70)		(36)		(24)		(4)		(26)		(24)	(586)		16		(468)		(1,038)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		21		-		21
Adjusted EBITDA			548		88		130		115		32		13		31		(15)	942		-		557		-
Management service costs			-		-		-		-		-		-		-		(62)	(62)		-		-		(62)
Interest expense - borrowings			(177)		(36)		(24)		(41)		(14)		(7)		(12)		(91)	(402)		12		(216)		(606)
Current income taxes			(4)		(6)		(9)		-		-		-		-		-	(19)		-		(25)		(44)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(15)	(15)		-		-		(15)
	Preferred equity		-		-		-		-		-		-		-		(25)	(25)		-		-		(25)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(12)		-		(12)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(316)		(316)
Funds From Operations			367		46		97		74		18		6		19		(208)	419		-		-		-
Depreciation			(244)		(31)		(125)		(80)		(38)		(4)		(18)		-	(540)		11		(252)		(781)
Unrealized financial instrument loss			1		-		-		-		-		-		2		(6)	(3)		(2)		1		(4)
Deferred income tax expense			31		6		7		49		6		-		-		(21)	78		-		19		97
Other			(27)		4		(5)		4		6		(1)		(2)		2	(19)		-		(19)		(38)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(9)		-		(9)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		251		251
Net income (loss) attributable to Unitholders(2)			128		25		(26)		47		(8)		1		1		(233)	(65)		-		-		(65)

⁽¹⁾Share of earnings from equity-accounted investments of $nil is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $65 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

F - !Unexpected End of Formula

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’s investments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2015:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		-		203		150		56		9		59		-	1,296		(44)		376		1,628
Other income			23		-		28		12		8		-		-		5	76		-		46		122
Direct operating costs			(285)		-		(67)		(38)		(20)		(1)		(31)		(23)	(465)		18		(105)		(552)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		26		-		26
Adjusted EBITDA			557		-		164		124		44		8		28		(18)	907		-		317		-
Management service costs			-		-		-		-		-		-		-		(48)	(48)		-		-		(48)
Interest expense - borrowings			(179)		-		(18)		(48)		(12)		(3)		(5)		(81)	(346)		6		(89)		(429)
Current income taxes			(5)		-		(10)		-		-		-		-		-	(15)		-		(3)		(18)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(1)	(1)		-		-		(1)
	Preferred equity		-		-		-		-		-		-		-		(30)	(30)		-		-		(30)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(6)		-		(6)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(225)		(225)
Funds From Operations			373		-		136		76		32		5		23		(178)	467		-		-		-
Depreciation			(218)		-		(113)		(83)		(32)		(4)		(12)		-	(462)		9		(161)		(614)
Unrealized financial instrument loss			1		-		-		2		-		-		(1)		(15)	(13)		1		3		(9)
Deferred income tax recovery			36		-		4		16		2		-		-		20	78		-		2		80
Other			14		-		(8)		(30)		(1)		-		(4)		(39)	(68)		-		-		(68)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(10)		-		(10)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		156		156
Net income (loss) attributable to Unitholders(2)			206		-		19		(19)		1		1		6		(212)	2		-		-		2

⁽¹⁾Share of earnings from equity-accounted investments of $10 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $69 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.

⁽²⁾Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

F - 49

The following table presents information on a segmented basis about certain items in Brookfield Renewable’s statement of financial position:

																						Contribution
		Attributable to Unitholders																				from		Attributable
		Hydroelectric						Wind								Solar		Corporate		Total		equity		to non-		Total
		North						North								Storage and						accounted		controlling
(MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other		Other						investments		interests
As at December 31, 2017:
Property, plant and equipment, at fair value		$	11,396	$	1,303	$	1,908	$	1,798	$	482	$	304	$	11	$	1,227	$	-	$	18,429	$	(1,451)	$	10,118	$	27,096
Total assets			11,709		1,574		2,149		1,888		532		443		31		1,456		180		19,962		(1,040)		11,982		30,904
Total borrowings			3,049		447		200		1,005		233		192		9		752		2,552		8,439		(848)		4,175		11,766
Total liabilities			5,237		801		380		1,338		334		208		18		877		2,786		11,979		(1,039)		5,682		16,622
For the year ended December 31, 2017:
	Additions to property, plant and equipment		90		8		59		6		34		-		-		13		10		220		(10)		144		354
As at December 31, 2016:
Property, plant and equipment, at fair value		$	10,922	$	1,273	$	1,895	$	1,327	$	545	$	139	$	-	$	491	$	-		16,592	$	(428)	$	9,093	$	25,257
Total assets			11,219		1,577		2,059		1,389		587		153		-		561		182		17,727		(280)		10,290		27,737
Total borrowings			2,946		467		194		727		249		50		-		215		2,229		7,077		(232)		3,337		10,182
Total liabilities			5,414		824		340		990		337		51		-		268		2,418		10,642		(280)		4,703		15,065
For the year ended December 31, 2016:
	Additions to property, plant and equipment		86		9		79		3		18		1		-		18		8		222		(10)		146		358

F - !Unexpected End of Formula

Geographical Information

The following table presents consolidated revenue split by geographical region:

(MILLIONS)		2017		2016		2015
United States	$	871	$	786	$	799
Colombia		797		819		-
Canada		480		442		426
Brazil		366		269		265
Europe		111		136		138
		2,625		2,452		1,628

The following table presents consolidated property, plant and equipment and equity-accounted investments split by geographical region:

(MILLIONS)		2017		2016
United States	$	11,131	$	10,163
Colombia		5,401		5,275
Canada		5,810		5,845
Brazil		3,479		2,922
Europe		1,332		1,258
Other		664		-
		27,817		25,463

7.  OTHER INCOME

Brookfield Renewable’s other income for the year ended December 31 is comprised of the following:

(MILLIONS)			2017		2016		2015
Interest income and other		$	32	$	41	$	21
Gain on available for sale investments (Note 3)			15		-		-
Gains on settlement of foreign currency contracts			-		23		31
Gain on disposal(1)			-		-		53
Compensation related to expired Brazilian
	concession agreements(2)		-		-		17
		$	47	$	64	$	122

⁽¹⁾In 2015, the sale of the 102 MW wind facility in California resulted in a gain of $53 million.  Brookfield Renewable’s share of the gain was $12 million, representing the 22% interest in the facility, and is net of the cash portion of non-controlling interests. 

⁽²⁾In 2015, concession agreements relating to two Brazilian hydroelectric facilities expired. Brookfield Renewable elected not to renew these agreements in exchange for compensation of $17 million.

8.DIRECT OPERATING COSTS

Brookfield Renewable’s direct operating costs for the year ended December 31 are comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Operations, maintenance and administration		$	567	$	553	$	396
Water royalties, property taxes and other			161		149		119
Fuel and power purchases(1)			226		313		15
Energy marketing fees	27		24		23		22
		$	978	$	1,038	$	552

⁽¹⁾Fuel and power purchases are primarily attributable to our portfolio in Colombia.

F - !Unexpected End of Formula

9.  OTHER

Brookfield Renewable’s other for the year ended December 31 is comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Transaction costs		$	(9)	$	(22)	$	(6)
Change in fair value of property, plant and equipment	12		(33)		(36)		(45)
Unrealized loss on available-for-sale securities			-		-		(25)
Other			14		20		13
		$	(28)	$	(38)	$	(63)

10. FOREIGN CURRENCY TRANSLATION

Brookfield Renewable’s foreign currency translation for the year ended December 31 shown in the consolidated statements of comprehensive income (loss) is comprised of the following:

(MILLIONS)		Notes		2017		2016		2015
Foreign currency translation on
	Property, plant and equipment, at fair value	12	$	506	$	1,186	$	(1,975)
	Long-term debt and credit facilities			(282)		(244)		697
	Deferred income tax liabilities and assets			(82)		(157)		202
	Other assets and liabilities			48		201		(62)
			$	190	$	986	$	(1,138)

F - 52

11.  INCOME TAXES

The major components of income tax recovery (expense) for the year ended December 31 are as follows:

(MILLIONS)		2017		2016		2015
Income tax (expense) recovery applicable to:
Current taxes
Attributed to the current period	$	(39)	$	(44)	$	(18)
Deferred taxes
Income taxes - origination and reversal of temporary differences	$	8	$	71	$	87
Relating to change in tax rates / imposition of new tax laws		(42)		35		6
Relating to unrecognized temporary differences and tax losses		(15)		(9)		(15)
	$	(49)	$	97	$	78
Total income tax (expense) recovery	$	(88)	$	53	$	60

The major components of deferred income tax recovery (expense) for the year ended December 31 recorded directly to OCI are as follows:

(MILLIONS)		2017		2016		2015
Deferred income taxes attributed to:
Financial instruments designated as cash flow hedges	$	(4)	$	2	$	8
Other		15		(7)		(17)
Revaluation surplus
Origination and reversal of temporary differences		(248)		(55)		(263)
Relating to changes in tax rates / imposition of new tax laws		586		19		(19)
	$	349	$	(41)	$	(291)

Brookfield Renewable’s effective income tax (expense) recovery for the year ended December 31 is different from its recovery at its statutory income tax rate due to the differences below:

(MILLIONS)			2017		2016		2015
Statutory income tax (expense) recovery(1)		$	(50)	$	5	$	(15)
(Reduction) increase resulting from:
	Increase in tax assets not recognized		(15)		(9)		(15)
	Deemed profit method differences in Brazil		1		(11)		10
	Differences between statutory rate and future tax rate		(38)		54		68
	Income or losses recorded not taxable to Brookfield Renewable		14		14		14
	Other		-		-		(2)
Effective income tax (expense) recovery		$	(88)	$	53	$	60

·Statutory income tax expense is calculated at the domestic rates applicable to the profits in the country concerned.

The above reconciliation has been prepared by aggregating the information for all of Brookfield Renewable’s subsidiaries using the domestic rate in each tax jurisdiction.

Brookfield Renewable’s effective income tax rate was 63.31% for the year ended December 31, 2017 (2016: 384.03%). The effective tax rate is more than the statutory rate primarily due to rate differentials, legislative changes in tax rates during the year, and non-controlling interests’ income not subject to tax.

F - 53

The following table details the expiry date, if applicable, of the unrecognized deferred tax assets as at December 31:

(MILLIONS)		2017		2016
2018 to 2022	$	8	$	-
2023 and thereafter		108		98

The deferred tax assets and liabilities of the following temporary differences have been recognized in the consolidated financial statements for the year ended December 31:

			Amount available		Difference		Net deferred
	Non-capital		for future		between tax and		tax (liabilities)
(MILLIONS)	losses		deductions		carrying value		assets
As at January 1, 2015	$	403	$	88	$	(2,986)	$	(2,495)
Recognized in Net income (loss)		73		(11)		16		78
Recognized in equity		(1)		-		(279)		(280)
Business combination		5		-		(35)		(30)
Foreign exchange		(22)		(12)		223		189
As at December 31, 2015		458		65		(3,061)		(2,538)
Recognized in Net income (loss)		24		(10)		83		97
Recognized in equity		17		-		(48)		(31)
Business combination		-		-		(1,020)		(1,020)
Foreign exchange		-		1		(161)		(160)
As at December 31, 2016		499		56		(4,207)		(3,652)
Recognized in Net income (loss)		(97)		(5)		53		(49)
Recognized in equity		13		-		341		354
Business combination		79		-		(63)		16
Foreign exchange		14		4		(98)		(80)
As at December 31, 2017	$	508	$	55	$	(3,974)	$	(3,411)

The deferred income tax liabilities include $2,561 million (2016: $2,948 million) of liabilities which relate to property, plant and equipment revaluations included in equity.

The taxable temporary difference attributable to Brookfield Renewable’s interest in its subsidiaries, branches, associates, and joint ventures is $1,549 million (2016: $1,380 million).

As a result of the recent U.S. income tax reform, Brookfield Renewable's net deferred tax liability decreased by $546 million, of which $41 million was recorded as a tax expense in net income and $587 million was recorded as a tax recovery in other comprehensive income. Over the long term, it is expected that the decrease in the U.S. federal income tax rate to reduce our overall effective tax rate.

F - 54

12.PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE

The following table presents a reconciliation of property, plant and equipment at fair value:

							Solar and
(MILLIONS)		Notes	Hydroelectric		Wind		Other(1)		Total(2)
As at December 31, 2014			$	15,210	$	3,315	$	41	$	18,566
Additions				183		51		55		289
Acquisitions through business combinations		3		307		624		229		1,160
Disposal				-		(230)		-		(230)
Items recognized through OCI
	Change in fair value			1,141		52		16		1,209
	Foreign exchange			(1,585)		(336)		(54)		(1,975)
Items recognized through net income
	Change in fair value			(2)		(43)		-		(45)
	Depreciation			(407)		(200)		(9)		(616)
As at December 31, 2015			$	14,847	$	3,233	$	278	$	18,358
Additions				269		71		18		358
Acquisitions through business combinations		3		5,731		10		-		5,741
Items recognized through OCI
	Change in fair value			190		187		54		431
	Foreign exchange			1,114		21		51		1,186
Items recognized through net income
	Change in fair value			(17)		(10)		(9)		(36)
	Depreciation			(565)		(199)		(17)		(781)
As at December 31, 2016			$	21,569	$	3,313	$	375	$	25,257
Additions				253		95		6		354
Acquisitions through business combinations		3		-		618		627		1,245
Disposal		4		-		(338)		-		(338)
Items recognized through OCI
	Change in fair value			828		91		(32)		887
	Foreign exchange			332		177		(3)		506
Items recognized through net income
	Change in fair value			(20)		(8)		(5)		(33)
	Depreciation			(563)		(197)		(22)		(782)
As at December 31, 2017			$	22,399	$	3,751	$	946	$	27,096

⁽¹⁾Includes solar, storage, biomass and Co-gen.

⁽²⁾Includes intangible assets of $13 million (2016: $14 million and 2015: $13 million) and construction work in process (“CWIP”) of $601 million (2016: $663 million and 2015: $405 million).  

The fair value of Brookfield Renewable’s property, plant and equipment is calculated as described in Notes 1(f) - Property, plant and equipment and revaluation method and 1(n) - Critical estimates. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies – Property, plant and equipment.Brookfield Renewable has classified its property, plant and equipment under level 3 of the fair value hierarchy. 

F - 55

Discount rates, terminal capitalization rates and exit dates used in the valuation methodology, are provided in the following table:

		North America						Colombia		Brazil		Europe
		2017			2016			2017	2016	2017	2016	2017			2016
Discount rate(1)
	Contracted	4.9%	-	6.0%	4.8%	-	5.5%	11.3%	N/A	8.9%	9.2%	4.1%	-	4.5%	4.1%	-	5.0%
	Uncontracted	6.5%	-	7.6%	6.6%	-	7.2%	12.6%	N/A	10.2%	10.5%	5.9%	-	6.3%	5.9%	-	6.8%
Terminal
	capitalization rate(2)	6.2%	-	7.5%	6.3%	-	6.9%	12.6%	N/A	N/A	N/A	N/A			N/A
Exit date		2037			2036			2037	N/A	2032	2031	2031			2031

⁽¹⁾Discount rates are not adjusted for asset specific risks.

⁽²⁾The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

The following table summarizes the impact of a change in discount rates, electricity prices and terminal capitalization rates on the fair value of property, plant and equipment:

	2017
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(710)	$	(130)	$	(50)	$	(20)	$	(910)
25 bps decrease in discount rates		770		130		50		20		970
5% increase in future electricity prices		620		310		70		20		1,020
5% decrease in future electricity prices		(620)		(310)		(70)		(20)		(1,020)
25 bps increase in terminal capitalization rate(1)		(180)		(50)		-		-		(230)
25 bps decrease in terminal capitalization rate(1)		190		50		-		-		240
	2016
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(670)	$	N/A	$	(50)	$	(20)	$	(740)
25 bps decrease in discount rates		730		N/A		50		20		800
5% increase in future electricity prices		540		N/A		70		20		630
5% decrease in future electricity prices		(540)		N/A		(70)		(20)		(630)
25 bps increase in terminal capitalization rate(1)		(180)		N/A		-		-		(180)
25 bps decrease in terminal capitalization rate(1)		190		N/A		-		-		190

⁽¹⁾The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

Terminal values are included in the valuation of hydroelectric assets in the United States, Canada and Colombia.  For the hydroelectric assets in Brazil, cash flows have been included based on the duration of the authorization or useful life of a concession asset without consideration of potential renewal value. The weighted-average remaining duration of the authorization or useful life of a concession asset at December 31, 2017, is 15 years (2016: 15 years). Consequently, there is no terminal value attributed to the hydroelectric assets in Brazil. If an additional 20 years of cash flows were included in Brazil, the fair value of property, plant and equipment would increase by approximately $1,500 million.

F - 56

The following table summarizes the percentage of total generation contracted under power purchase agreements as at December 31, 2017:

	North America		Colombia		Brazil		Europe
1 - 10 years		58%		17%		66%		78%
11 - 20 years		42%		-		57%		35%

The following table summarizes power prices from long-term power purchase agreements that are linked specifically to the related power generating assets:

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	84	COP	211,000	R$	274	€	90
11 - 20 years		88		-		407		107

⁽¹⁾Assumes nominal prices based on weighted-average generation.

The following table summarizes the estimates of future electricity prices:

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	63	COP	238,000	R$	309	€	78
11 - 20 years		112		339,000		458		95

⁽¹⁾Assumes nominal prices based on weighted-average generation.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth between 2021 and 2025. A further one year change would increase or decrease the fair value of property, plant and equipment by approximately $160 million (2016: $130 million). 

Had Brookfield Renewable’s revalued property, plant and equipment been measured on a historical cost basis, the carrying amounts, net of accumulated depreciation would have been as follows at December 31:

(MILLIONS)		2017		2016
Hydroelectric	$	12,740	$	12,761
Wind		3,030		2,688
Solar and other(1)		933		319
	$	16,703	$	15,768

⁽¹⁾Includes biomass and Co-gen.

F - 57

13.  LONG-TERM DEBT AND CREDIT FACILITIES

The composition of debt obligations as at December 31 is presented in the following table:

		2017						2016
		Weighted-average				Estimated		Weighted-average				Estimated
		Interest	Term	Carrying		Fair		Interest	Term	Carrying		Fair
(MILLIONS EXCEPT AS NOTED)		rate (%)	(years)	value		value		rate (%)	(years)	value		value
Corporate borrowings
	Series 3 (C$200)	5.3	0.8	$	159	$	163	5.3	1.8	$	149	$	158
	Series 4 (C$150)	5.8	18.9		119		144	5.8	19.9		111		132
	Series 7 (C$450)	5.1	2.8		358		382	5.1	3.8		334		368
	Series 8 (C$400)	4.8	4.1		318		344	4.8	5.1		298		331
	Series 9 (C$400)	3.8	7.4		318		321	3.8	8.4		298		308
	Series 10 (C$500)	3.6	9.0		398		400	3.6	10.0		372		380
		4.5	6.4	$	1,670	$	1,754	4.5	7.4	$	1,562	$	1,677
Credit facilities		2.6	4.5	$	887	$	887	1.9	4.5	$	673	$	673
Subsidiary borrowings
	Hydroelectric	6.3	8.8	$	6,392		6,813	6.9	7.8	$	6,249		6,600
	Wind	5.8	9.7		2,211		2,343	4.6	13.1		1,735		1,879
	Solar and other	11.0	8.2		682		682	8.9	18.8		41		41
		6.5	9.0	$	9,285	$	9,838	6.4	9.0	$	8,025	$	8,520
Total debt					11,842		12,479				10,260		10,870
Add: Unamortized premiums(1)					1						2
Less: Unamortized financing fees(1)					(77)						(80)
Less: Current portion(2)(3)					(1,676)						(1,034)
				$	10,090					$	9,148

⁽¹⁾Unamortized premiums and unamortized financing fees are amortized to interest expense over the terms of the borrowing

⁽²⁾As part of the TerraForm Global transaction, Brookfield Renewable acquired $841 million of borrowings that were immediately classified as current due to the change of control provision allowing the holders to direct TerraForm Global to redeem the bonds at 101% of par value in the first quarter of 2018. Brookfield Renewable redeemed these borrowings at approximately 107% of par value in the first quarter of 2018 with a combination of available cash on hand and proceeds from note offering that closed on February 22, 2018. See Note 20 – Cash and Cash Equivalents and Note 31 – Subsequent Events.

⁽³⁾As part of the TerraForm Global transaction, Brookfield Renewable acquired project level financings that were in default prior to the acquisition, had outstanding principal amounts totaling $342 million and mature in 2031.  See Note 18 – Capital Management..

The following table outlines changes in Brookfield Renewable’s borrowings for the year ended December 31:

			Cash flows from		Non-cash
(MILLIONS)	Jan 1		financing activities		Acquisition		Disposal		Other(1)		Dec 31
2017	$	10,182	$	267	$	1,188	$	(173)	$	302	$	11,766
2016	$	7,338	$	1,502	$	1,104	$	-	$	238	$	10,182

⁽¹⁾Includes foreign exchange and amortization of unamortized premium and financing fees.

F - 58

Future repayments of Brookfield Renewable’s debt obligations, for each of the next five years and thereafter are as follows:

(MILLIONS)		2018		2019		2020		2021		2022		Thereafter		Total
Corporate borrowings and
	credit facilities	$	159	$	202	$	377	$	-	$	984	$	835	$	2,557
Subsidiary borrowings
	Hydro		206		366		1,013		822		317		3,668		6,392
	Wind		665		115		122		125		132		1,052		2,211
	Solar and other		646		3		3		2		4		24		682
		$	1,676	$	686	$	1,515	$	949	$	1,437	$	5,579		11,842
Equity-accounted investments		$	110	$	116	$	112	$	716	$	602	$	3,003	$	4,659
														$	16,501

⁽¹⁾Subsidiary borrowings and corporate borrowings and credit facilities include $1 million and $77 million of unamortized premiums and deferred financing fees, respectively.

The following table outlines change in financing fees for the year ended December 31:

(MILLIONS)			2017		2016		2015
Corporate borrowings
	Unamortized financing fees, beginning of year	$	6	$	5	$	5
	Additional financing fees		-		2		1
	Amortization of financing fees		(1)		(1)		(1)
	Unamortized financing fees, end of year	$	5	$	6	$	5
Subsidiary borrowings
	Unamortized financing fees, beginning of year	$	74	$	54	$	66
	Additional financing fees		16		41		7
	Amortization of financing fees		(14)		(17)		(15)
	Foreign exchange translation and other		(4)		(4)		(4)
	Unamortized financing fees, end of year	$	72	$	74	$	54
Total		$	77	$	80	$	59

Corporate borrowings

Corporate borrowings are obligations of a finance subsidiary of Brookfield Renewable, Brookfield Renewable Partners ULC (“Finco”) (Note 30  - Subsidiary Public Issuers). Finco may redeem some or all of the borrowings from time to time, pursuant to the terms of the indenture. The balance is payable upon maturity, and interest on corporate borrowings is paid semi-annually. The term notes payable by Finco are unconditionally guaranteed by Brookfield Renewable, Brookfield Renewable Energy L.P. (“BRELP”) and certain other subsidiaries.

Our sole near time maturity is our C$200 million ($159 million) Series 3 medium-term notes which mature in November 2018.

Subsidiary borrowings

Subsidiary borrowings are typically asset-specific, long-term, non-recourse borrowings denominated in the domestic currency of the subsidiary. Subsidiary borrowings in North America, Europe and South Africa consist of both fixed and floating interest rate debt. Subsidiary borrowings in South Africa consist of floating interest rate debt indexed to the Johannesburg Interbank Agreed Rate (“JIBAR”) and U.S. dollar

F - 59

denominated debt indexed to the London Interbank Offered Rate (“LIBOR”). Brookfield Renewable uses interest rate swap agreements in North America, Europe and South Africa to minimize its exposure to floating interest rates. Subsidiary borrowings in Brazil consist of floating interest rates of Taxa de Juros de Longo Prazo (“TJLP”), the Brazil National Bank for Economic Development’s long-term interest rate, or Interbank Deposit Certificate rate (“CDI”), plus a margin. Subsidiary borrowings in Colombia include floating interest rates of Indicador Bancario de Referencia rate (“IBR”), the Banco Central de Colombia short-term interest rate, or Colombian Consumer Price Index (“IPC”), the Banco Central de Colombia inflation rate, plus a margin. Subsidiary borrowings in Malaysia consist of floating interest rate debt indexed to the Kuala Lumpur Interbank Offering Rate (“KLIBOR”). Subsidiary borrowings in India consist of fixed interest rate U.S. dollar denominated debt.

In March 2017, Brookfield Renewable completed the refinancing of a $60 million bank loan associated with a 417 MW hydroelectric facility in Pennsylvania. The loan bears interest at LIBOR plus a margin of 3.75% and matures in March 2022.

In May 2017, Brookfield Renewable completed the refinancing associated with a 44 MW hydroelectric portfolio in New England by issuing notes for $65 million. The notes carry a 4.86% coupon rate and mature in May 2027.

In June 2017, Brookfield Renewable completed the refinancing associated with a 11 MW wind asset in Arizona by securing a $11 million bank loan. The loan has been fully hedged for an all-in rate of 5.28% and matures in June 2024.

In June 2017, Brookfield Renewable completed the financing associated with a 17 MW hydroelectric facility in Quebec by issuing notes for C$55 million ($43 million). The notes bear an all-in rate of 4.49% and mature in May 2044.

In July 2017, Brookfield Renewable completed the refinancing of a 360 MW hydroelectric portfolio in New England. The financing was a $475 million green bond bearing interest at 4.4% with a maturity in July 2032.

In October 2017, Brookfield Renewable completed financing associated with a 47 MW portfolio of wind farms in Ireland by securing €78 million ($92 million) of long-term debt, €6 million ($8 million) working capital facility and €4 million ($4 million) debt reserve facility. The long-term debt matures in 2032 and bears interest at EURIBOR plus a margin of 1.5%.

In December 2017, Brookfield Renewable completed a $305 million refinancing, associated with an 872 MW portfolio of hydroelectric facilities in New York at an all-in interest rate of 4.29% and with a maturity in December 2030.

In December 2017, Brookfield Renewable completed a £17 million ($22 million) non-recourse financing associated with a 16 MW wind asset in Northern Ireland. The long-term debt matures in 2035 and bears interest at GBP LIBOR plus a margin of 2.20%.

In December 2017, Brookfield Renewable completed R$166 million ($50 million) of financing with respect to a 28 MW hydroelectric facility currently under construction in Brazil. The loan bears interest at a rate of TJLP plus 2.12% and matures in 2038.

Credit facilities

In June 2017, Brookfield Renewable extended the maturity of $1,600 million of its corporate credit facilities by one year to June 30, 2022. The applicable margin is 1.20%. The credit facilities are used for general working capital purposes and issuing letters of credit. The credit facilities bear interest at the applicable banker’s acceptance rate, LIBOR or EURIBOR plus an applicable margin. The applicable margin is tiered on the basis of Brookfield Renewable’s unsecured long-term debt rating.

F - 60

During the first quarter of 2017, the committed unsecured revolving credit facility provided by Brookfield Asset Management was increased to $400 million. During the fourth quarter of 2017, Brookfield Renewable extended the maturity by one year to December 2018. Interest rate applicable on the draws is LIBOR plus 2%.

Brookfield Renewable and its subsidiaries issue letters of credit from some of their credit facilities for general corporate purposes which include, but are not limited to, security deposits, performance bonds and guarantees for debt service reserve accounts.

The following table summarizes the available portion of credit facilities as at December 31:

(MILLIONS)		2017		2016
Authorized credit facilities	$	2,090	$	1,890
Draws on credit facilities(1)		(685)		(673)
Issued letters of credit		(193)		(250)
Available portion of credit facilities	$	1,212	$	967

(1)Comprised of $685 million borrowed under unsecured corporate credit facilities guaranteed by Brookfield Renewable.  Excludes $202 million borrowed under a subscription credit facility made available to a Brookfield sponsored private fund.

As at December 31, 2017, a subsidiary of Brookfield Renewable, as a qualified borrower, had received $202 million under a credit facility of a private fund sponsored by Brookfield Asset Management. The facility has an interest rate of LIBOR plus 1.5%, a maturity date of June 2019 and is unsecured.

14. NON-CONTROLLING INTERESTS

Brookfield Renewable’s non-controlling interests are comprised of the following as at December 31:

(MILLIONS)			2017		2016
Participating non-controlling interests - in operating subsidiaries		$	6,298	$	5,589
General partnership interest in a holding subsidiary held by Brookfield			58		55
Participating non-controlling interests - in a holding subsidiary -
	Redeemable/Exchangeable units held by Brookfield		2,843		2,680
Preferred equity			616		576
		$	9,815	$	8,900

F - 61

Participating non-controlling interests – in operating subsidiaries

The net change in participating non-controlling interests – in operating subsidiaries is as follows:

												Isagen
		Brookfield								Isagen		public
		Americas		Brookfield		Brookfield			The	institu-		non-con
	Infrastructure			Infrastructure		Infrastructure		Catalyst		tional		-trolling
(MILLIONS)		Fund		Fund II		Fund III		Group		investors		interests		Other		Total
As at December 31, 2014		$	914	$	937	$	-	$	126	$	-	$	-	$	85	$	2,062
Net income			26		27		-		14		-		-		2		69
OCI			89		144		-		(12)		-		-		(17)		204
Capital contributions			-		460		-		-		-		-		-		460
Distributions			(70)		(126)		-		(7)		-		-		(5)		(208)
Other			(1)		(1)		-		-		-		-		2		-
As at December 31, 2015		$	958	$	1,441	$	-	$	121	$	-	$	-	$	67	$	2,587
Net (loss) income			(18)		(16)		15		16		47		19		2		65
OCI			46		228		-		2		148		205		6		635
Capital contributions			-		74		1,074		-		1,473		-		-		2,621
Acquisition			-		-		-		-		-		1,417		-		1,417
Distributions			(23)		(73)		(7)		(12)		-		-		(4)		(119)
MTO adjustments			-		-		3		-		7		(1,627)		-		(1,617)
As at December 31, 2016		$	963	$	1,654	$	1,085	$	127	$	1,675	$	14	$	71	$	5,589
Net (loss) income			(29)		(13)		33		12		47		-		3		53
OCI			(76)		269		111		2		78		(1)		-		383
Capital contributions			-		89		186		-		19		-		-		294
Acquisition			-		-		525		-		-		-		-		525
Distributions			(8)		(317)		(88)		(7)		(115)		-		(4)		(539)
Purchase of Isagen shares			-		-		(1)		-		(5)		5		-		(1)
Other			-		-		1		-		2		(9)		-		(6)
As at December 31, 2017		$	850	$	1,682	$	1,852	$	134	$	1,701	$	9	$	70	$	6,298
Interests held by third parties			75-80%		50-60%		23-71%		25%		53%		0.5%	21-50%

The privatization of the Isagen portfolio was completed on March 31, 2017 and its shares were delisted from the Colombia Stock Exchange. During the year ended December 31, 2017, Brookfield Renewable, together with its co-investors, acquired an additional 3,358,523 shares in Isagen. In accordance with IFRS 10, Consolidated Financial Statements, Brookfield Renewable is accounting for the additional interests in Isagen purchased subsequent to the initial investments as equity transactions related to the acquisition of non-controlling interest. As at December 31, 2017 Brookfield Renewable together with its co-investors owns approximately 99.5% interest in Isagen. The remaining approximately 0.5% ownership interest not held by Brookfield Renewable and its co-investors remains as non-controlling interest. 

F - 62

The following tables summarize certain financial information of operating subsidiaries that have non-controlling interests that are material to Brookfield Renewable:

		Brookfield
		Americas		Brookfield		Brookfield
		Infrastructure		Infrastructure		Infrastructure		The Catalyst
(MILLIONS)		Fund		Fund II		Fund III(1)		Group		Isagen(2)		Other		Total
Interests held by third parties			75-80%		50-60%		69-71%		25%		76%		21-50%
Place of business		United States, Brazil		United States, Brazil, Europe		United States, Brazil, India, China, South Africa		United States		Colombia		United States, Brazil, Canada
For the year ended
	December 31, 2015:
Revenue		$	136	$	402	$	-	$	160	$	-	$	30	$	728
Net income			34		49		-		56		-		8		147
Total comprehensive
	income (loss)		144		247		-		8		-		(51)		348
Net income allocated to
	non-controlling interests		26		27		-		14		-		2		69
For the year ended
	December 31, 2016:
Revenue		$	118	$	394	$	28	$	164	$	819	$	27	$	1,550
Net (loss) income			(22)		(23)		(8)		62		110		5		124
Total comprehensive
	income (loss)		37		356		(8)		70		502		31		988
Net (loss) income allocated to
	non-controlling interests		(18)		(16)		(5)		16		86		2		65
As at December 31, 2016:
Property, plant and
	equipment, at fair value	$	1,807	$	4,816	$	848	$	970	$	5,275	$	417	$	14,133
Total assets			1,865		5,125		855		1,072		6,539		428		15,884
Total borrowings			571		1,881		313		450		1,924		41		5,180
Total liabilities			631		2,235		319		466		3,396		60		7,107
Carrying value of non-
	controlling interests	$	963	$	1,654	$	383	$	127	$	2,391	$	71	$	5,589
For the year ended
	December 31, 2017:
Revenue		$	123	$	430	$	53	$	135	$	797	$	32	$	1,570
Net (loss) income			(34)		(20)		18		47		89		7		107
Total comprehensive
	(loss) income		(133)		529		126		57		236		-		815
Net (loss) income allocated
	to non-controlling interests		(29)		(13)		13		12		67		3		53
As at December 31, 2017:
Property, plant and
	equipment, at fair value	$	1,667	$	5,153	$	2,149	$	964	$	5,401	$	411	$	15,745
Total assets			1,718		5,430		3,294		1,066		6,526		426		18,460
Total borrowings			556		2,040		1,502		413		1,858		42		6,411
Total liabilities			628		2,422		1,678		432		3,336		63		8,559
Carrying value of non-
	controlling interests	$	850	$	1,682	$	1,138	$	134	$	2,424	$	70	$	6,298

⁽¹⁾Excludes information relating to Isagen which is presented separately.

⁽²⁾The total third parties ownership interest in Isagen as of December 31, 2017 was 75.9% and comprised of Brookfield Infrastructure Fund III: 22.9%, Isagen Institutional investors 52.5% and Isagen public non-controlling interests: 0.5%.

F - 63

General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests – in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield

Brookfield, as the owner of the 1% general partnership interest in BRELP held by Brookfield (“GP interest”), is entitled to regular distributions plus an incentive distribution based on the amount by which quarterly distributions exceed specified target levels. To the extent that LP Unit distributions exceed $0.375 per LP Unit per quarter, the incentive is 15% of distributions above this threshold. To the extent that quarterly LP Unit distributions exceed $0.4225 per LP Unit, the incentive distribution is equal to 25% of distributions above this threshold.

Consolidated equity includes Redeemable/Exchangeable partnership units and the GP interest. The Redeemable/Exchangeable partnership units are held 100% by Brookfield, which at its discretion has the right to redeem these units for cash consideration. No Redeemable/Exchangeable partnership units have been redeemed for cash consideration. Since this redemption right is subject to Brookfield Renewable’s right, at its sole discretion, to satisfy the redemption request with LP Units of Brookfield Renewable on a one for one basis, the Redeemable/Exchangeable partnership units are classified as equity in accordance with IAS 32, Financial Instruments: Presentation. The Redeemable/Exchangeable partnership units and GP interest are presented as non-controlling interests since they provide Brookfield the direct economic benefits and exposures to the underlying performance of BRELP. The LP Units issued by Brookfield Renewable and the Redeemable/Exchangeable partnership units issued by its subsidiary BRELP have the same economic attributes in all respects, except for the redemption right described above. The Redeemable/Exchangeable partnership units and the GP interest participate in earnings and distributions on a per unit basis equivalent to the per unit participation of the LP Units of Brookfield Renewable.

As at December 31, 2017, general partnership units, and Redeemable/Exchangeable partnership units outstanding were 2,651,506 (December 31, 2016: 2,651,506) and 129,658,623 (December 31, 2016: 129,658,623), respectively.

Distributions

The composition of the distributions for the year ended December 31 is presented in the following table:

(MILLIONS)			2017		2016
General partnership interest in a holding
	subsidiary held by Brookfield	$	5	$	5
Incentive distribution			30		19
		$	35	$	24
Participating non-controlling interests - in a
	holding subsidiary - Redeemable/
	Exchangeable units held by Brookfield	$	243	$	232
		$	278	$	256

F - 64

The following table summarizes certain financial information regarding General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests – in a holding subsidiary – Redeemable/Exchangeable units held by Brookfield:

(MILLIONS)		2017		2016		2015
For the year ended December 31:
Revenue		$	2,625	$	2,452	$	1,628
Net income			51		40		103
Comprehensive income			1,401		1,369		5
Net income allocated to(1):
	GP interest		(1)		-		-
	Redeemable/Exchangeable partnership units		(23)		(29)		1
As at December 31:
Property, plant and equipment, at fair value		$	27,096	$	25,257
Total assets			30,904		27,737
Total borrowings			11,766		10,182
Total liabilities			16,622		15,065
Carrying value of(2):
	GP interest		58		55
	Redeemable/Exchangeable partnership units		2,843		2,680

⁽¹⁾Allocated based on weighted-average GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 173.5 million, respectively (2016: 2.7 million, 129.7 million, and 156.4 million, respectively and 2015: 2.7 million, 129.7 million, and 143.3 million, respectively).

⁽²⁾Allocated based on outstanding GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 180.4 million, respectively (2016: 2.7 million, 129.7 million, and 166.8 million, respectively).

Preferred equity

Brookfield Renewable’s preferred equity as at December 31 consists of Class A Preference Shares of Brookfield Renewable Power Preferred Equity Inc. (“BRP Equity”) as follows:

			Earliest	Dividends declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	dividend	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 1 (C$136)	5.45	3.36	Apr 30, 2020	$	4	$	3	$	108	$	101
Series 2 (C$113)(1)	4.51	3.63	Apr 30, 2020		3		3		90		84
Series 3 (C$249)	9.96	4.40	Jul 31, 2019		8		8		197		185
Series 5 (C$103)	4.11	5.00	Apr 30, 2018		4		4		82		76
Series 6 (C$175)	7.00	5.00	Jul 31, 2018		7		7		139		130
	31.03			$	26	$	25	$	616	$	576

⁽¹⁾Dividend rate represents annualized distribution based on the most recent quarterly floating rate.

The Class A Preference Shares do not have a fixed maturity date and are not redeemable at the option of the holders. As at December 31, 2017, none of the issued Class A Preference Shares have been redeemed by BRP Equity.

Class A Preference Shares – Normal Course Issuer Bid

In June 2017, the TSX accepted notice of BRP Equity’s intention to renew the normal course issuer bid in connection with its outstanding Class A Preference Shares for another year to June 26, 2018, or earlier should the repurchases be completed prior to such date. Under this normal course issuer bid, it is permitted to repurchase up to 10% of the total public float for each respective series of our Class A Preference Shares.

F - 65

15. PREFERRED LIMITED PARTNERS’ EQUITY

Brookfield Renewable’s preferred limited partners’ equity comprises of Class A Preferred LP Units as follows:

			Earliest	Distributions declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	distribution	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 5 (C$72)	2.89	5.59	Apr 30, 2018	$	4	$	3	$	49	$	49
Series 7 (C$175)	7.00	5.50	Jan 31, 2021		8		7		128		128
Series 9 (C$200)	8.00	5.75	Jul 31, 2021		8		5		147		147
Series 11 (C$250)	10.00	5.00	Apr 30, 2022		8		-		187		-
	27.89			$	28	$	15	$	511	$	324

On February 14, 2017, Brookfield Renewable issued 10,000,000 Class A, Series 11 Preferred Limited Partnership Units (the “Series 11 Preferred Units”) at a price of C$25 per unit for gross proceeds of C$250 million ($190 million). The holders of the Series 11 Preferred Units are entitled to receive a cumulative quarterly fixed distribution yielding 5.0% for the initial period ending April 30, 2022. Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5-year Government of Canada bond yield plus 3.82%, and (ii) 5.00%.

The holders of Series 11 Preferred Units will have the right, at their option, to convert their Series 11 Preferred Units into Class A Preferred Limited Partnership Units, Series 12 (the “Series 12 Preferred Units”), subject to certain conditions, on April 30, 2022 and on April 30 every five years thereafter. The holders of Series 12 Preferred Units will be entitled to receive floating rate cumulative preferential cash distributions equal to the sum of the 90-day Canadian Treasury Bill Rate plus 3.82%.

16. LIMITED PARTNERS’ EQUITY

Limited partners’ equity

As at December 31, 2017, 180,388,361 LP Units were outstanding (December 31, 2016: 166,839,324) including 56,068,944 (December 31, 2016: 51,125,944) held by Brookfield. Brookfield owns all general partnership interests in Brookfield Renewable representing a 0.01% interest.

During the year ended December 31, 2017, 302,037 LP Units (2016: 298,946 LP Units) were issued under the distribution reinvestment plan.

As at December 31, 2017, Brookfield Asset Management’s direct and indirect interest of 185,727,567 LP Units and Redeemable/Exchangeable partnership units represents approximately 60% of Brookfield Renewable on a fully-exchanged basis and the remaining approximate 40% is held by public investors.

On an unexchanged basis, Brookfield holds a 31% direct limited partnership interest in Brookfield Renewable, a 42% direct interest in BRELP through the ownership of Redeemable/Exchangeable partnership units and a direct 1% GP interest in BRELP as at December 31, 2017.

In December 2017, Brookfield Renewable renewed its normal course issuer bid in connection with its LP Units. Under this normal course issuer bid Brookfield Renewable is permitted to repurchase up to 9  million LP Units, representing approximately 5% of the issued and outstanding LP Units, for capital management purposes. The bid will expire on December 28, 2018, or earlier should Brookfield Renewable complete its repurchases prior to such date.

F - 66

Issuance of LP Units

On July 6, 2017, Brookfield Renewable completed the issuance of 8,304,000 non-voting LP Units on a bought deal basis at a price of C$42.15 per LP Unit for gross proceeds of C$350 million ($271 million). Concurrently, Brookfield Asset Management purchased 4,943,000 LP Units at the offering price (net of underwriting commission). The aggregate gross proceeds of the offering and the concurrent private placement was C$550 million ($422 million). Brookfield Renewable incurred C$15 million ($11 million) in related transaction costs inclusive of fees paid to underwriters.

The excess of the price received over the carrying value of the additional limited partnership units of BRELP purchased by Brookfield Renewable resulted in adjustments to the General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests – in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield of $1 million and $62 million, respectively. BRELP ultimately used the net proceeds to repay outstanding indebtedness and for general corporate purposes.

Distributions

The composition of the distribution for the year ended December 31 is presented in the following table:

(MILLIONS)		2017		2016
Brookfield	$	101	$	83
External LP Unitholders		227		198
	$	328	$	281

In February 2017, unitholder distributions were increased to $1.87 per LP Unit on an annualized basis, an increase of nine cents per LP Unit, which took effect with the distribution payable in March 2017.

17. GOODWILL

The following table provides a reconciliation of goodwill:

(MILLIONS)	2017		2016
Balance, beginning of year	$	896	$	-
Acquired through business acquisition		-		799
Foreign exchange		5		97
Balance, end of year	$	901	$	896

18. CAPITAL MANAGEMENT

Brookfield Renewable’s primary capital management objectives are to ensure the sustainability of its capital to support continuing operations, meet its financial obligations, allow for growth opportunities and provide stable distributions to its LP Unitholders. Brookfield Renewable’s capital is monitored through debt to total capitalization ratio which is calculated as total debt plus deferred income tax liabilities, net of deferred income tax assets, and equity. The ratio as at December 31, 2017 was 40% (2016: 38%).

Brookfield Renewable has provided covenants to certain of its lenders for its corporate borrowings and credit facilities. The covenants require Brookfield Renewable to meet minimum debt to capitalization ratios.  Subsidiaries of Brookfield Renewable have provided covenants to certain of their lenders for their property-specific borrowings. These covenants vary from one credit agreement to another and include ratios that address debt service coverage. Certain lenders have also put in place requirements that oblige Brookfield Renewable and its subsidiaries to maintain debt and capital expenditure reserve accounts. The consequences to the subsidiaries as a result of failure to comply with their covenants could include a limitation of distributions from the subsidiaries to Brookfield Renewable, as well as repayment of

F - 67

outstanding debt. Brookfield Renewable is dependent on the distributions made by its subsidiaries to service its debt.

As part of the TerraForm Global transaction, Brookfield Renewable acquired assets with project level financings that were in default prior to the acquisition, had outstanding principal amounts totaling $342 million and mature in 2031.   As at December 31, 2017, the loans were not in compliance with certain covenants due to the SunEdison Bankruptcy, as well as issues with contractors under the engineering, procurement and construction contract. The loan balances have been classified as current as at December 31, 2017. Brookfield Renewable is currently working with all the lenders to cure such defaults and release the restrictions placed on the projects.  Except for the aforementioned defaults, Brookfield Renewable complied with all material financial covenants as of December 31, 2017.

Brookfield Renewable’s strategy during 2017, which was unchanged from 2016, was to maintain the measure set out in the following schedule as at December 31:

(MILLIONS)			2017		2016
Total debt
	Current portion of long-term debt(1)	$	1,676	$	1,034
	Long-term debt and credit facilities		10,090		9,148
			11,766		10,182
Deferred income tax liabilities, net(2)			3,411		3,652
Equity			14,282		12,672
Total capitalization		$	29,459	$	26,506
Debt to total capitalization			40%		38%

⁽¹⁾As part of the TerraForm Global transaction, Brookfield Renewable acquired $841 million of borrowings that were immediately classified as current due to the change of control provision allowing the holders to direct TerraForm Global to redeem the bonds at 101% of par value in the first quarter of 2018. Brookfield Renewable redeemed these borrowings at approximately 107% of par value in the first quarter of 2018 with a combination of available cash on hand and proceeds from note offering that closed on February 22, 2018. See Note 20 – Cash and Cash Equivalents and Note 31 – Subsequent Events

⁽²⁾Deferred income tax liabilities less deferred income tax assets.

19. EQUITY-ACCOUNTED INVESTMENTS

The following are Brookfield Renewable’s equity-accounted investments as at December 31: 

	Principal place	Ownership	Carrying value
	of business	interest
(MILLIONS)		%		2017		2016
FHH (Guernsey) Limited	Europe	25	$	245	$	-
TerraForm Power Inc.(1)	United States, Canada	16		212		-
Bear Swamp Power Co. L.L.C.	United States	50		173		114
Galera Centrais Eletricas S.A.	Brazil	50		28		29
Pingston Power Inc.	Canada	50		57		58
Brookfield Infrastructure Fund II Investees	United States, Europe	14 - 50		6		5
			$	721	$	206

⁽¹⁾The fair value of the investment based on quoted market price of the shares as of December 31, 2017  was $278 million.

F - 68

The following table outlines the changes in Brookfield Renewable’s equity-accounted investments for the year ended December 31:

(MILLIONS)		2017		2016		2015
Balance, beginning of year		$	206	$	197	$	273
Share of net income			2		-		10
Share of OCI
	Revaluation of property, plant and equipment		54		7		96
	Other		2		1		-
Dividends declared			(31)		(6)		(19)
Capital distributions, net			-		-		(144)
Acquisition of European Storage (Note 3)			248		-		-
Acquisition of TerraForm Power (Note 3)			221		-		-
Foreign exchange translation			19		7		(19)
Balance, end of year		$	721	$	206	$	197

The following tables summarize certain financial information of equity-accounted investments:

(MILLIONS)					2017		2016
As at December 31:
Current assets				$	477	$	45
Property, plant and equipment, at fair value					8,098		864
Other assets					213		70
Current liabilities					687		42
Long-term debt					4,294		463
Other liabilities					958		71
(MILLIONS)			2017		2016		2015
For the year ended December 31
Revenue		$	310	$	74	$	89
Net (loss) income			(24)		-		19
Share of net income (loss)
	Cash earnings		29		9		20
	Non-cash loss		(27)		(9)		(10)

20. CASH AND CASH EQUIVALENTS

Brookfield Renewable’s cash and cash equivalents as at December 31 are as follows:

(MILLIONS)		2017		2016
Cash(1)	$	790	$	210
Short-term deposits		9		13
	$	799	$	223

⁽¹⁾As part of the TerraForm Global transaction, Brookfield Renewable acquired $611 million of cash and cash equivalents, which under the indenture for TerraForm Global’s senior notes, is not available for distribution. In the first quarter of 2018, Brookfield Renewable used a portion of this cash as well as proceeds from a note offering that closed on February 22, 2018 to redeem these borrowings. See Note 13 – Long-term Debt and Credit Facilities and Note 31 – Subsequent Events.

F - 69

21. RESTRICTED CASH

Brookfield Renewable’s restricted cash as at December 31 is as follows:

(MILLIONS)	Note		2017		2016
Operations		$	195	$	135
Credit obligations			85		104
Development projects			4		11
Total			284		250
Less: non-current	23		(103)		(129)
Current		$	181	$	121

22. TRADE RECEIVABLES AND OTHER CURRENT ASSETS

Brookfield Renewable’s trade receivables and other current assets as at December 31 are as follows:

(MILLIONS)		2017		2016
Trade receivables	$	360	$	262
Other short-term receivables		82		103
Prepaids and others		112		89
	$	554	$	454

As at December 31, 2017, 99% (2016: 95%) of trade receivables were current. Trade receivables are generally on 30-day terms and credit limits are assigned and monitored for all counterparties. In determining the recoverability of trade receivables, management performs a risk analysis considering the type and age of the outstanding receivables and the credit worthiness of the counterparties. Management also reviews trade receivable balances on an ongoing basis. Bad debt expense related to trade receivables is recognized at the time an account is deemed uncollectible. Accordingly, as at December 31, 2017 and 2016 an allowance for doubtful accounts for trade receivables was not deemed necessary.

23.  OTHER LONG-TERM ASSETS

The composition of Brookfield Renewable’s other long-term assets as at December 31 is presented in the following table:

			Accumulated
		Cost	Amortization		Net Book Value		Net book value
(MILLIONS)	2017							2016
Restricted cash	$	103	$	-	$	103	$	129
Unamortized financing fees		32		(27)		5		6
Acquisition downpayment		46		-		46		-
Other		82		(6)		76		41
	$	263	$	(33)	$	230	$	176

At December 31, 2017 and 2016, restricted cash was held primarily to satisfy lease payments and credit agreements.

F - 70

24.  ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Brookfield Renewable’s accounts payable and accrued liabilities as at December 31 are as follows:

(MILLIONS)			2017		2016
Operating accrued liabilities		$	271	$	147
Accounts payable			117		87
Interest payable on corporate and subsidiary borrowings			64		68
Deferred consideration			35		55
Acquisition related provisions			-		54
LP Unitholders’ distributions, preferred limited partnership unit
	distributions and preferred dividends payable(1)		29		24
Other			26		32
		$	542	$	467

(1)Includes amounts payable only to external LP Unitholders. Amounts payable to Brookfield are included in due to related parties.

25.  OTHER LONG-TERM LIABILITIES

Brookfield Renewable’s other long-term liabilities as at December 31 are comprised of the following:

(MILLIONS)	Notes	2017			2016
Acquisition related provisions		$	80	$	111
Pension obligations	29		89		87
Decommissioning retirement obligations			85		47
Contingent consideration	3		18		16
Commitments for power purchase agreements			13		-
Concession payment liability			9		10
Deferred revenue			9		7
Other			41		32
		$	344	$	310

Brookfield Renewable has recorded decommissioning retirement obligations associated with certain power generating assets. The decommissioning retirement obligation has been established for hydroelectric and wind operation sites in North America that are expected to be restored between the years 2031 to 2138. The estimated cost of decommissioning activities is based on a third party assessment.

F - 71

26.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

In the course of its operations, Brookfield Renewable and its subsidiaries have entered into agreements for the use of water, land and dams. Payment under those agreements varies with the amount of power generated. The various agreements can be renewed and are extendable up to 2091.

The remaining development project costs on two Brazilian hydroelectric projects totaling 47 MW and one 28 MW wind project in Europe are expected to be $44 million. All three projects are expected to be fully operational in 2018.

As at December 31, 2017, Brookfield Renewable had commitments for future minimum lease payments under non-cancellable leases which fall due as follows:

(MILLIONS)
2018	$	33
2019		32
2020		31
2021		30
2022		27
Thereafter		262
Total	$	415

Contingencies

Brookfield Renewable and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on Brookfield Renewable’s consolidated financial position or results of operations.

Brookfield Renewable, on behalf of Brookfield Renewable’s subsidiaries, and the subsidiaries themselves have provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance. The activity on the issued letters of credit by Brookfield Renewable can be found in Note 13 – Long-term debt and credit facilities.

Brookfield Renewable along with institutional investors has provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance as it relates to interests in the Brookfield Americas Infrastructure Fund and the Brookfield Infrastructure Fund II. Brookfield Renewable’s subsidiaries have similarly provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance.

As at December 31, letters of credit issued by Brookfield Renewable along with institutional investors and  its subsidiaries were as follows:

(MILLIONS)		2017	2016
Brookfield Renewable along with institutional investors	$	76	$	66
Brookfield Renewable's subsidiaries		468		483
	$	544	$	549

F - 72

Guarantees

In the normal course of operations, Brookfield Renewable and its subsidiaries execute agreements that provide for indemnification and guarantees to third parties of transactions such as business dispositions, capital project purchases, business acquisitions, and sales and purchases of assets and services. Brookfield Renewable has also agreed to indemnify its directors and certain of its officers and employees. The nature of substantially all of the indemnification undertakings prevents Brookfield Renewable from making a reasonable estimate of the maximum potential amount that Brookfield Renewable could be required to pay third parties as the agreements do not always specify a maximum amount and the amounts are dependent upon the outcome of future contingent events, the nature and likelihood of which cannot be determined at this time. Historically, neither Brookfield Renewable nor its subsidiaries have made material payments under such indemnification agreements.

27.  RELATED PARTY TRANSACTIONS

Brookfield Renewable’s related party transactions are recorded at the exchange amount. Brookfield Renewable’s related party transactions are primarily with Brookfield.

Brookfield Renewable and Brookfield have entered into, or amended, the following material agreements:

Principal Agreements

Limited Partnership Agreements

Each of the amended and restated limited partnership agreements of Brookfield Renewable and BRELP outline the key terms of the partnerships, including provisions relating to management, protections for limited partners, capital contributions, distributions and allocation of income and losses. BRELP’s general partner is entitled to receive incentive distributions from BRELP as a result of its ownership of the general partnership interest in BRELP. The incentive distributions are to be calculated in increments based on the amount by which quarterly distributions on the limited partnership units of BRELP exceed specified target levels as set forth in the amended and restated partnership agreement.

Master Services Agreement

Brookfield Renewable entered into an agreement with Brookfield Asset Management pursuant to which Brookfield Asset Management has agreed to provide oversight of the business and provide the services of senior officers to Brookfield Renewable for a management service fee.  The fee is paid on a quarterly basis and has a fixed quarterly component of $5 million and a variable component calculated as a percentage of the increase in the total capitalization value of Brookfield Renewable over an initial reference value (subject to an annual escalation by a specified inflation factor beginning on January 1, 2013). Total capitalization value as of December 31, 2017 is $14 billion, which against the initial reference value of $8 billion and factoring in the annual amount of $21 million (as adjusted for inflation), resulted in a management service fee payment for the year ended December 31, 2017 of $82 million (2016: $62 million and 2015: $48 million).

BRELP Voting Agreement

In 2011, Brookfield Renewable entered into a voting agreement with Brookfield pursuant to which Brookfield Renewable, through BRPL, has a number of voting rights, including the right to direct all eligible votes in the election of the directors of BRELP’s general partner.

F - 73

Revenue Agreements

Contract Amendments

In 2011, two long-term power purchase agreements associated with the generating assets in Ontario held by Great Lakes Power Limited (“GLPL”) and Mississagi Power Trust (“MPT”), were amended.

The amended GLPL power purchase agreement requires Brookfield to support the price that GLPL receives for energy generated by certain facilities in Canada at a price of C$82 per MWh subject to an annual adjustment equal to 40% of the Consumer Price Index (“CPI”) in the previous year.  The GLPL agreement has an initial term to 2029, and the contract automatically renews for successive 20-year periods with certain termination provisions.  If the contract is not terminated prior to 2029, the price under this agreement reverts back to the original C$68 per MWh subject to an annual adjustment equal to 40% of the CPI for each year.

The amended MPT power purchase agreement requires Brookfield to purchase the energy generated at a price of C$103 per MWh subject to an annual adjustment equal to 20% of the CPI in the previous year.  The MPT contract terminates on December 1, 2029 and MPT has been granted the unilateral option to terminate the agreement, on 120 days written notice, at certain times between 2017 and 2024.

Energy Revenue Agreement

In 2011, an agreement was entered into between Brookfield and Brookfield Power U.S. Holdings America Co. (“BPUSHA”) that indirectly owns substantially all of the U.S. facilities of Brookfield Renewable. Brookfield will support the price that BPUSHA receives for energy generated by certain facilities in the United States at a price $75 per MWh. This price is to be increased annually on January 1 by an amount equal to 40% of the increase in the CPI during the previous calendar year, but not exceeding an increase of 3% in any calendar year. This agreement will have an initial term of 20 years, with automatic renewals for successive 20-year periods with certain termination provisions.

Other Revenue Agreements

Pursuant to a 20-year power purchase agreement, Brookfield purchases all energy from several power facilities in Maine and New Hampshire held by Great Lakes Holding America (“GLHA”) at $37 per MWh.  The energy rates are subject to an annual adjustment equal to 20% of the increase in the CPI during the previous year.

Pursuant to a 20-year power purchase agreement, Brookfield purchases all energy from Lievre Power in Quebec at C$68 per MWh. The energy rates are subject to an annual adjustment equal to the lesser of 40% of the increase in the CPI during the previous calendar year or 3%.

Pursuant to a power guarantee agreement, Brookfield will purchase all energy from the two facilities of Hydro Pontiac Inc. at a price of C$68 per MWh, to be increased annually each calendar year beginning in 2010 by an amount equal to 40% of the increase in the CPI during the previous calendar year. This power guarantee agreement is scheduled to commence in 2019 for one facility and in 2020 for the other, upon the expiration of existing third-party power agreements. The agreement with Brookfield has an initial term to 2029 and automatically renews for successive 20-year period with certain termination provisions.

Pursuant to a 10-year Wind Levelization agreement expiring in 2019, Brookfield mitigates any potential wind variation from the expected annual generation of 506 GWh with regards to the Prince Wind assets in Ontario. Any excess generation compared to the expected generation results in a payment from Brookfield Renewable to Brookfield, while a shortfall would result in a payment from Brookfield to Brookfield Renewable.

F - 74

Power Services Agreements

Power Agency Agreements

Certain Brookfield Renewable subsidiaries have entered into Power Agency Agreements appointing Brookfield as their exclusive agent in respect of the sales of electricity, including the procurement of transmission and other additional services.  In addition, Brookfield will schedule, dispatch and arrange for transmission of the power produced and the power supplied to third-parties in accordance with prudent industry practice. Pursuant to each Agreement, Brookfield will be entitled to be reimbursed for any third-party costs incurred, and, in certain cases, receives an additional fee for its services in connection with the sale of power and for providing the other services.

Energy Marketing Agreement

Brookfield has agreed to provide energy marketing services to Brookfield Renewable’s North American businesses. Under this Agreement, Brookfield Renewable pays an annual energy marketing fee of $18 million per year (subject to increase by a specified inflation factor beginning on January 1, 2013). See Note 8 - Direct operating costs. 

Voting Agreements

Brookfield Renewable entered into voting agreements with Brookfield whereby Brookfield, as managing member of entities related to the Brookfield Americas Infrastructure Fund (the “BAIF Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, agreed to assign to Brookfield Renewable their voting rights to elect the Boards of Directors of the BAIF Entities. Brookfield Renewable’s economic interests in the BAIF Entities in the United States and Brazil are 22% and 25%, respectively.

Brookfield Renewable entered into voting agreements with certain Brookfield subsidiaries whereby these subsidiaries, as managing members of entities related to Brookfield Infrastructure Fund II (the “BIF II Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, agreed to provide to Brookfield Renewable the authority to direct the election of the Boards of Directors of the BIF II Entities. Brookfield Renewable’s economic interests in the BIF II Entities are between 40% and 50.1%.

Except as set out below in respect to TerraForm Power and Isagen, Brookfield Renewable entered into a voting agreement with certain Brookfield subsidiaries that form part of Brookfield Infrastructure Fund III (the “BIF III Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, Brookfield agreed to provide to Brookfield Renewable the authority to direct the election of the Boards of Directors of the BIF III Entities. Brookfield Renewable’s economic interests in the BIF III Entities are between 24% and 31%.

The consortium holds its interest in Isagen through an entity (“Hydro Holdings”) which is entitled to appoint a majority of the board of directors of Isagen.  The general partner of Hydro Holdings is a controlled subsidiary of Brookfield Renewable.  Brookfield Renewable is entitled to appoint a majority of Hydro Holdings’ board of directors, provided that Brookfield Asset Management and its subsidiaries (including Brookfield Renewable) collectively are (i) the largest holder of Hydro Holdings’ limited partnership interests, and (ii) hold over 30% of Hydro Holdings’ limited partnership interests (the “Ownership Test”).  Brookfield Asset Management and its subsidiaries currently meet the Ownership Test.

Brookfield Renewable entered into a voting agreement with the Brookfield subsidiary that ultimately controls TerraForm Power. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of one of the four directors of the Brookfield subsidiary, thereby providing Brookfield Renewable with significant influence over this subsidiary.

F - 75

Brookfield Asset Management has provided a $400 million committed unsecured revolving credit facility maturing in December 2018. See Note 13 – Long-term debt and credit facilities for further details. Brookfield Asset Management had also placed funds on deposit with Brookfield Renewable in the amount of $140 million during the first quarter of the current year, which was repaid prior to the end of the first quarter. The interest expense on the draws from the credit facility and the deposit totaled $1 million. 

In 2011, on formation of Brookfield Renewable, Brookfield Asset Management transferred certain development projects to Brookfield Renewable for no upfront consideration but is entitled to receive variable consideration on commercial operation or sale of these projects. An amount of $8 million has been paid relating to the commissioning of a 25 MW hydroelectric facility in Brazil.

The following table reflects the related party agreements and transactions in the consolidated statements of income, for the year ended December 31:

(MILLIONS)			2017		2016		2015
Revenues
	Power purchase and revenue agreements	$	601	$	527	$	469
	Wind levelization agreement		6		8		6
		$	607	$	535	$	475
Direct operating costs
	Energy purchases	$	(13)	$	(3)	$	(5)
	Energy marketing fee		(24)		(23)		(22)
	Insurance services		(19)		(20)		(30)
		$	(56)	$	(46)	$	(57)
Management service costs		$	(82)	$	(62)	$	(48)

The following table reflects the impact of the related party agreements and transactions on the consolidated statements of financial position as at December 31:

(MILLIONS)			Related party		2017		2016
Current assets
Due from related parties
	Amounts due from		Brookfield	$	54	$	47
			Equity-accounted investments and other		6		7
				$	60	$	54
Current liabilities
Due to related parties
	Amount due to		Brookfield	$	48	$	48
	Accrued distributions payable on LP
		Units and Redeemable/Exchangeable
		partnership units	Brookfield		32		26
	Amount due to		Equity-accounted investments and other		32		2
				$	112	$	76

Current assets 

Amounts due from Brookfield are non-interest bearing, unsecured and due on demand.

F - 76

Current liabilities

Amounts due to Brookfield are unsecured, payable on demand and relate to recurring transactions.

28. SUPPLEMENTAL INFORMATION

The net change in working capital balances for the year ended December 31 shown in the consolidated statements of cash flows is comprised of the following:

(MILLIONS)		2017		2016		2015
Trade receivables and other current assets	$	(40)	$	30	$	(72)
Accounts payable and accrued liabilities		32		(160)		2
Other assets and liabilities		(17)		(7)		8
	$	(25)	$	(137)	$	(62)

29. PENSION AND EMPLOYEE FUTURE BENEFITS

Brookfield Renewable offers a number of pension plans to its employees, as well as certain health care, dental care, life insurance and other benefits to certain retired employees pursuant to Brookfield Renewable’s policy.  The plans are funded by contributions from Brookfield Renewable and from plan members.  Pension benefits are based on length of service and final average earnings and some plans are indexed for inflation after retirement. The pension plans relating to employees of Brookfield Renewable have been included in the consolidated financial statements.

The Brookfield Renewable Pension Governance Committee (BRGC) is responsible for the implementation of strategic decisions and monitoring of the administration of Brookfield Renewable’s defined benefit pension plans.  Specifically, the BRGC will establish the investment strategies, approve the funding policies as well as assess that Brookfield Renewable has complied with all applicable law, fiduciary, reporting and disclosure requirements.

Actuarial valuations for Brookfield Renewable’s pension plans are required as per governing provincial or federal regulations. For the United States registered plans, actuarial valuations are required annually. For the Canadian registered plans, actuarial valuations are required on a triennial basis if the funding level of the plan is above a certain threshold. Currently, all Canadian plans are on a triennial schedule. In the Colombian business, there are obligations for pension plans and other employee benefits. Actuarial valuations on these obligations are performed annually by qualified, independent actuaries. 

The dates of the most recent actuarial valuations for Brookfield Renewable’s pension and non-pension benefit plans range from January 2015 to January 2018. Brookfield Renewable measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year.

The benefit liabilities represent the amount of pension and other employee future benefits that Brookfield Renewable’s employees and retirees have earned at year-end. The benefit obligation under these plans is determined through periodic actuarial reports which were based on the assumptions indicated in the following table.

F - 77

Actuarial assumptions as at December 31:

		Defined benefit			Non-pension			Defined benefit			Non-pension			Defined benefit			Non-pension
		pension plans			benefit plans			pension plans			benefit plans			pension plans			benefit plans
		2017						2016						2015
		(%)						(%)						(%)
Discount rate		2.4	-	7.3	3.7	-	7.1	2.2	-	7.3	4.1	-	7.3	2.9	-	4.7	4.2	-	4.7
Rate of price inflation		1.5	-	3.5	N/A			1.5	-	3.5	N/A			2.0	-	2.5	N/A
Rate of compensation
	increases	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	3.0	2.5	-	3.0
Health care trend rate(1)		N/A			5.3	-	6.9	N/A			5.3	-	6.9	N/A			6.3	-	7.1

⁽¹⁾Assumed immediate trend rate at year-end.

Plan obligations and the annual pension expense are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, discount rates, rate of compensation increases and other assumptions. The discount rate, rate of price inflation and inflation-linked assumptions and health care cost trend rate are the assumptions that generally have the most significant impact on the benefit obligations.

The discount rate for benefit obligation purposes is determined, as far as possible, by reference to market yields on high quality corporate bonds. In Colombia deep market in bonds does not exist. Accordingly, the discount rate is determined by reference to yields on government bonds. Rate of compensation increases reflect the best estimate of merit increases to be provided, consistent with assumed inflation rates. 

A 50 basis point change in the assumptions mentioned before, used for the calculation of the benefit obligations as at December 31, 2017, would result in the following increase (decrease) of the benefit obligations:

		Defined benefit		Non-pension
(MILLIONS)		pension plans		benefit plans
Discount rate
	50 basis point increase		(11)		(4)
	50 basis point decrease		13		5
Rate of price inflation and inflation-linked assumptions
	50 basis point increase		4		N/A
	50 basis point decrease		(4)		N/A
Health care cost trend rate
	50 basis point increase		N/A		4
	50 basis point decrease		N/A		(3)

The sensitivity analysis presented above may not be representative of the actual change in the defined benefit obligation as it is unlikely that the change in assumptions would occur in isolation of one another as some of the assumptions may be correlated.

F - 78

Expense recognized in the consolidated statements of income and consolidated statements of comprehensive income (loss) for the year ended December 31:

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Current service costs			$	3	$	1	$	3	$	1	$	3	$	1
Past service costs (recovery)				(1)		-		-		-		1		(1)
Interest expense				2		3		2		3		1		2
Administrative expenses				1		-		1		-		1		-
Recognized in consolidated
	statement of income			5		4		6		4		6		2
Remeasurement of the net
	defined benefit liability:
	Return on plan assets			(8)		-		(2)		-		(1)		-
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Recognized in consolidated
	statement of comprehensive
	income			-		2		2		-		1		(6)
Total			$	5	$	6	$	8	$	4	$	7	$	(4)

The amounts included in the consolidated statements of financial position arising from Brookfield Renewable’s obligations in respect of its defined benefit plans are as follows:

		Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
		pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)			2017				2016				2015
Present value of defined
	benefit obligation	$	172	$	57	$	158	$	53	$	124	$	35
Fair value of plan assets			(135)		(5)		(119)		(5)		(103)		-
Net liability		$	37	$	52	$	39	$	48	$	21	$	35

F - 79

Defined benefit obligations

The movement in the defined benefit obligation for the year ended December 31 is as follows:

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Balance, beginning of year			$	158	$	53	$	124	$	35	$	128	$	43
Current service cost				3		1		3		1		3		1
Past service (recovery) cost				(1)		-		-		-		1		(1)
Interest expense				7		3		7		3		5		2
Remeasurement losses (gains)
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Benefits paid				(7)		(2)		(8)		(2)		(5)		(2)
Business combination				-		-		25		14		-		-
Exchange differences				4		-		3		2		(10)		(2)
Balance, end of year			$	172	$	57	$	158	$	53	$	124	$	35

Expected employer’s contributions to the defined benefit plans for the year ended December 31, 2018 are $6 million.

Fair value of plan assets

The movement in the fair value of plan assets for the year ended December 31 is as follows:

	Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
	pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)		2017				2016				2015
Balance, beginning of year	$	119	$	5	$	103	$	-	$	108	$	-
Interest income		5		-		5		-		4		-
Return on plan assets		8		-		2		-		1		-
Employer contributions		5		2		7		3		5		2
Business combination		-		-		9		4		-		-
Benefits paid		(7)		(2)		(8)		(2)		(5)		(2)
Exchange differences		5		-		1		-		(10)		-
Balance, end of year	$	135	$	5	$	119	$	5	$	103	$	-

The composition of plan assets as at December 31 is as follows:

		2017	2016
		(%)	(%)
Asset category:
	Cash and cash equivalents	2	5
	Equity securities	54	50
	Debt securities	44	44
	Real estate	-	1
		100	100

F - 80

30.  SUBSIDIARY PUBLIC ISSUERS

The following tables provide consolidated summary financial information for Brookfield Renewable, BRP Equity, and Finco:

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
As at December 31, 2017:
Current assets		$	32	$	412	$	1,691	$	525	$	2,816	$	(3,810)	$	1,666
Long-term assets			4,483		262		-		20,142		29,508		(25,157)		29,238
Current liabilities			43		7		180		3,024		3,071		(3,811)		2,514
Long-term liabilities			-		-		1,505		693		12,670		(760)		14,108
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		6,298		-		6,298
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,843		-		-		2,843
Preferred equity			-		616		-		-		-		-		616
Preferred limited partners' equity			511		-		-		516		-		(516)		511
As at December 31, 2016:
Current assets		$	26	$	-	$	1,581	$	150	$	2,092	$	(2,942)	$	907
Long-term assets			3,779		620		-		18,415		27,250		(23,234)		26,830
Current liabilities			33		9		19		2,971		1,644		(2,943)		1,733
Long-term liabilities			-		-		1,556		738		12,775		(1,737)		13,332
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		5,589		-		5,589
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,680		-		-		2,680
Preferred equity			-		576		-		-		-		-		576
Preferred limited partners' equity			324		-		-		324		-		(324)		324

⁽¹⁾Includes investments in subsidiaries under the equity method.

⁽²⁾Includes BRELP, BRP Bermuda Holdings I Limited, Brookfield BRP Holdings (Canada) Inc. and Brookfield BRP Europe Holdings Limited, together the “Holding Entities”.

⁽³⁾Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco and the Holding Entities.

⁽⁴⁾Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

F - 81

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
For the year ended
	December 31, 2017
Revenues		$	-	$	-	$	-	$	-	$	2,625	$	-	$	2,625
Net income (loss)			(4)		10		(1)		(435)		631		(150)		51
For the year ended
	December 31, 2016
Revenues		$	-	$	-	$	-	$	1	$	2,451	$	-	$	2,452
Net income (loss)			(20)		-		(1)		(100)		558		(397)		40
For the year ended
	December 31, 2015
Revenues		$	-	$	-	$	-	$	8	$	1,620	$	-	$	1,628
Net income (loss)			2		-		(1)		(42)		235		(91)		103

⁽¹⁾Includes investments  in subsidiaries under the equity method.

⁽²⁾Includes the Holding Entities. 

⁽³⁾Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco, and the Holding Entities.

⁽⁴⁾Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

See Note 13 – Long-term debt and credit facilities for additional details regarding the medium-term corporate notes issued by Finco. See Note 14 – Non-controlling interests for additional details regarding Class A Preference Shares issued by BRP Equity.

31.  SUBSEQUENT EVENTS

On January 16, 2018, Brookfield Renewable issued 10,000,000 Series 13 Preferred LP Units at a price of C$25 per unit for gross proceeds of C$250 million ($201 million).

On January 19, 2018, Brookfield Renewable completed financing associated with its equity-accounted 2.1 GW pumped storage facility in the United Kingdom by securing £60 million ($83 million) of long-term debt and £90 million ($125 million) letter of credit facility. The long-term debt matures in 2021 and bears interest at LIBOR plus a margin of 2.75%.

On January 29, 2018, Brookfield Renewable completed R$130 million ($40 million) of financing with respect to a 19 MW hydroelectric facility currently under construction in Brazil. The loan bears interest at a rate of TJLP plus 2.15% and matures in 2038.

On February 15, 2018, Brookfield Renewable completed a refinancing associated with a 296 MW hydroelectric facility in the United States. The financing was a $350 million interest only green bond bearing interest at 4.5%, maturing in 2033.  Proceeds were used to repay the existing principal amount of $315 million and the excess was distributed to investors.

On February 22, 2018, TerraForm Global issued $400 million of senior notes at 6.13%, maturing in March 2026.  Along with cash on the balance sheet, proceeds were used to repay the existing $760 million of 9.75% senior notes due in 2022. Additionally, TerraForm Global secured a $45 million revolving credit facility, maturing in February 2021.

On February 27, 2018, Brookfield Renewable completed a COP 750 billion ($262 million) bond refinancing associated with the Colombian business.

F - 82

EX-12.1

 

Exhibit 12.1

CERTIFICATION

I, Sachin Shah, certify that:

1.I have reviewed this Annual Report on Form 20-F of Brookfield Renewable Partners L.P.; 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the Annual Report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): 

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 

- 1 -

Dated: February 28, 2018

/s/ Sachin Shah
Name:	Sachin Shah
Title:	Chief Executive Officer of the Service Provider, BRP Energy Group L.P.
(Principal Executive Officer)

EX-12.2

 

Exhibit 12.2

CERTIFICATION

I, Wyatt Hartley, certify that:

1.I have reviewed this Annual Report on Form 20-F of Brookfield Renewable Partners L.P.; 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: 

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; 

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the Annual Report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): 

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. 

Dated: February 28, 2018

/s/ Wyatt Hartley
Name:	Wyatt Hartley
Title:	Chief Financial Officer of the Service Provider, BRP Energy Group L.P.
(Principal Financial Officer)

- 2 -

EX-13.1

 

Exhibit 13.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, who is carrying out the functions of chief executive officer for Brookfield Renewable Partners L.P. (the “Partnership”) pursuant to the Master Services Agreement, hereby certifies, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, as filed with the Securities and Exchange Commission on the date hereof, (i) the annual report of the Partnership on Form 20-F for the fiscal year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Annual Report fairly presents in all material respects the financial condition and results of operations of the Partnership.

Dated: February 28, 2018

/s/ Sachin Shah

Sachin Shah

Chief Executive Officer of the Service

Provider, BRP Energy Group L.P.

- 1 -

EX-13.2

 

Exhibit 13.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

The undersigned, who is carrying out the functions of chief financial officer for Brookfield Renewable Partners L.P. (the “Partnership”) pursuant to the Master Services Agreement, hereby certifies, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, as filed with the Securities and Exchange Commission on the date hereof, (i) the annual report of the Partnership on Form 20-F for the fiscal year ended December 31, 2017 (the “Annual Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained in the Annual Report fairly presents in all material respects the financial condition and results of operations of the Partnership.

Dated: February 28, 2018

/s/ Wyatt Hartley

Wyatt Hartley

Chief Financial Officer of the Service

Provider, BRP Energy Group L.P.

- 1 -

EX-15.1

Exhibit 15.1

BROOKFIELD RENEWABLE PARTNERS LIMITED

BOARD OF DIRECTORS CHARTER

May 2017

1.         Purpose of the Partnership and the Managing General Partner

Brookfield Renewable Partners L.P. (the “Partnership”) and its related entities have been established by Brookfield Asset Management Inc. (“BAM”) as BAM’s primary vehicle through which it will acquire renewable power assets on a global basis.  The purpose of the Partnership is to: (i) establish, acquire and/or hold interests in Brookfield Renewable Energy L.P. (“BRELP”) and, subject to approval of the Managing General Partner (as defined below), in other entities involved in the power generating and development business; (ii) engage in any activity related to the capitalization and financing of the Partnership’s interests in  BRELP and such other entities; and (iii) engage in any activity that is incidental to or in furtherance of the foregoing and that is approved by its general partner and that lawfully may be conducted by a limited partnership organized under the Limited Partnership Act  1883 (Bermuda) and the Partnership’s limited partnership agreement.

Brookfield Renewable Partners Limited (the “Managing General Partner”) is the general partner of the Partnership and is responsible for conducting, directing and managing all activities of the Partnership. 

2.         Role of the Board

The board of directors (the “Board”) of the Managing General Partner meets regularly to review reports by the Partnership’s Service Providers (as defined below) on the Partnership’s performance and other relevant matters of interest. In addition to the general supervision of the Service Providers, the Board performs the following functions:

(a)supervising the affiliates of BAM that are engaged in the provision of management services under the master services agreement (collectively, the “Service Providers”); 

(b)capitalizing and financing the Partnership’s interests in BRELP;

(c)providing oversight of the activities of BRELP; and

(d)overseeing the other activities of the Managing General Partner.

3.         Authority and Responsibilities

The Board meets regularly to review reports by the Service Providers on the Partnership’s performance. In addition to the general supervision of the provision of services by the Service Providers, the Board performs the following functions:

- 1 -

(a)risk assessment – assessing the major risks facing the Partnership and reviewing, approving and monitoring the manner of addressing  those risks;

(b)communications and disclosure policy – adopting a communications and disclosure policy for the Partnership, including ensuring the timeliness and integrity of communications to unitholders and establishing suitable mechanisms to receive stakeholder views;

(c)corporate governance – developing the Partnership’s approach to corporate governance, including developing a set of corporate governance principles and guidelines applicable to the Partnership;

(d)internal controls – reviewing and monitoring the controls and procedures within the Partnership to maintain its integrity, including its disclosure controls and procedures, and its internal controls and procedures for financial reporting and compliance; and

(e)maintaining integrity – on an ongoing basis, satisfying itself that the chief executive officer and other executive officers of the Service Providers create a culture of integrity throughout the organization, including compliance  with the Partnership’s Code of Business Conduct & Ethics and its Anti-bribery and Anti-corruption Policy.

The Partnership’s main purpose is to hold limited partnership interests of BRELP.  Accordingly, the Board performs its functions principally through requiring that the general partner of BRELP perform comparable functions in respect of BRELP, including adopting policies in respect of communications and disclosure and corporate governance that are comparable to those of the Managing General Partner.  The policies of BRELP must also impose appropriate obligations on the entities in which it invests.  Both the Managing General Partner and the general partner of BRELP will fulfill their responsibilities regarding the evaluation of risks and internal controls through receiving and evaluating reports on such matters from entities in which they invest.

4.         Composition and Procedures

(a)Size of Board and Selection Process – The directors of the Managing General Partner are elected by its shareholders from time to time.  The Nominating and Governance Committee recommends  to the full Board the nominees for election to the Board and the Board proposes to its shareholders a slate of nominees for election, the number of which is subject to limits in its constating documents. The Nominating and Governance Committee also recommends the number of directors from time to time. 

(b)Qualifications – Directors should have the highest personal and professional ethics and values and be committed to advancing the best interests of the Partnership.  They should possess skills and competencies in areas that are relevant to the Managing General Partner’s activities. At least three directors and at least a majority of the directors will be independent directors based on the rules and guidelines of applicable stock exchanges and securities regulatory authorities. If the Chair of the Board is not independent, there shall be a Lead Independent Director of the Board selected by the Board on the recommendation of the Nominating and Governance Committee.

(c)Meetings – The Board holds  at least four scheduled meetings a year. The Board is responsible for its agenda. Prior to each Board meeting, the Chair of the Board

- 2 -

discusses agenda items for the meeting with the Service Providers. Materials for each meeting are distributed to the directors in advance of the meetings.  If the Chair of the Board is absent from a meeting, the other directors shall select a director from those in attendance to act as chair of the meeting.  The directors shall appoint a secretary to be the secretary of all meetings and to maintain minutes of all meetings and deliberations of the Board.

At the conclusion of each regularly scheduled meeting, the independent directors meet separately. The Lead Independent Director chairs these in-camera sessions.

(d)Committees – The Board has established the following standing committees to assist it in discharging its responsibilities: Audit and Nominating and Governance. Special committees may be established  from time to time to assist the Board in connection with specific matters. The chair of each committee reports to the Board following meetings of their committee. The governing charter of each standing committee is reviewed and approved annually by the Board.

(e)Evaluation – The Nominating and Governance Committee performs an annual evaluation of the effectiveness of the Board as a whole, the committees of the Board and the contributions of individual directors, and provides a report to the Board on the findings of this evaluation. In addition, each committee assesses its own performance annually.

(f)Compensation – The Nominating and Governance Committee recommends to the Board the compensation for directors and supervises any changes to the fees to be paid pursuant to the master services agreement (it is the policy of the Managing General Partner that management directors do not receive compensation for their service on the Board). In reviewing the adequacy and form of compensation for directors, the Nominating and Governance Committee seeks to ensure that the director compensation reflects the responsibilities and risks involved in being a director of the Managing General Partner and aligns the interests of the directors with the best interests of the Partnership.

(g)Access to Outside Advisors – The Board and any committee may at any time retain outside financial, legal or other advisors at the expense of the Managing General Partner.  Any director may, subject to the approval of the Chair of the Board, retain an outside advisor at the expense of the Managing General Partner.

(h)Charter of Expectations – The Board has adopted a Charter of Expectations for Directors which outlines the basic duties and responsibilities of directors and the expectations the Managing General Partner places on them in terms of professional and personal competencies, performance, behaviour, conflicts of interest, limited partnership interest ownership and resignation events.  Among other things, the Charter of Expectations outlines the role of directors in stakeholder engagement and the requirement of directors to attend Board meetings and review meeting materials in advance.

This Charter of the Board was reviewed and approved by the Board on May 2, 2017.

- 3 -

EX-15.2

 

Exhibit 15.2

BROOKFIELD RENEWABLE PARTNERS LIMITED

Audit Committee Charter

May 2017

A committee of the board of directors (the “Board”) of Brookfield Renewable Partners Limited (the “Managing General Partner”), the general partner of Brookfield Renewable Partners L.P. (the “Partnership”), to be known as the Audit Committee (the “Committee”), shall have the following terms of reference:

Membership And Chair

Annually the Board shall appoint three or more directors (the “Members” and each a “Member”) to serve on the Committee for the upcoming year or until the Member ceases to be a director, resigns or is replaced, whichever occurs first.

The Members will be selected by the Board on the recommendation of the Nominating and Governance Committee of the Managing General Partner (the “Nominating and Governance Committee”). Any Member may be removed, with or without cause, from office or replaced at any time by the Board. All Members will be Independent (as defined below). Members must disclose any form of association they have with a current or former external or internal auditors of the Managing General Partner, any other member of the BAM Group or any member of the BEP Group to the Nominating and Governance Committee for a determination as to whether this association affects the Member’s status as an Independent Member. In addition, every Member will be Financially Literate (as defined below) and at least one Member will be an Audit Committee Financial Expert (as defined below).  Members may not serve on more than two other public company audit committees, except with the prior approval of the Board.  Not more than fifty per cent of the Members may be residents of any one jurisdiction (other than Bermuda and any other jurisdiction designated by the Board from time to time).

The Board shall appoint one Member as the chair of the Committee (the “Chair”). If the Board fails to appoint a Chair, the Members of the Committee shall elect a Member to act as Chair by majority vote to serve at the pleasure of the majority. If the Chair is absent from a meeting, the Members shall select a Member from those in attendance to act as Chair of the meeting.

Responsibilities

The Committee shall:

(a)oversee the work of the Partnership’s independent auditor (the “auditor”) engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Partnership;

(b)review and evaluate the auditor’s independence, experience, qualifications and performance and determine whether the auditor should be appointed or re-

- 1 -

appointed and nominate the auditor for appointment or re-appointment by the Board;

(c)have the sole authority to retain, compensate, direct, oversee and terminate the auditor and any counsel, other auditors and other advisors hired to assist the Committee, who shall ultimately be accountable to the Committee;

(d)when a change of auditor is proposed, review all issues related to the change, including the information to be included in the notice of change of auditor as required, and the orderly transition of such change;

(e)review the terms of the auditor’s engagement and the appropriateness and reasonableness of the proposed audit fees;

(f)at least annually, obtain and review a report by the auditor describing:

(i)the auditor’s internal quality-control procedures; and

(ii)any material issues raised by the most recent internal quality control review, or peer review, of the auditor, or review by any independent oversight body or governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the auditor, and the steps taken to deal with any issues raised in any such review;

(g)at least annually, confirm that the auditor has submitted a formal written statement describing all of its relationships with the Partnership, Brookfield Renewable Energy L.P. and any of its subsidiaries; discuss with the auditor any disclosed relationships or services that may affect its objectivity and independence; obtain written confirmation from the auditor that it is objective within the meaning of the applicable rules of professional conduct/code of ethics adopted by the order of chartered accountants to which it belongs and is an independent public accountant within the meaning of the applicable securities legislation, and is in compliance with any independence requirements adopted by the Public Company Accounting Oversight Board; and, confirm that the auditor has complied with applicable laws respecting the rotation of certain members of the audit engagement team;

(h)review and evaluate the lead partner of the auditor;

(i)ensure the regular rotation of the audit engagement team members as required by law, and periodically consider whether there should be regular rotation of the auditor firm;

(j)meet privately with the auditor as frequently as the Committee feels is appropriate to fulfill its responsibilities, which will not be less frequently than annually, to discuss any items of concern to the Committee or the auditor, including:

(i)planning and staffing of the audit;

(ii)any material written communications between the auditor and the Service Providers (as defined below) and between the auditor and the auditor’s national office;

(iii)whether or not the auditor is satisfied with the quality and effectiveness of financial recording procedures and systems;

(iv)the extent to which the auditor is satisfied with the nature and scope of its examination;

- 2 -

(v)whether or not the auditor has received the full co-operation of the Service Providers pursuant to the Master Services Agreement (as defined below); 

(vi)the auditor’s opinion of the competence and performance of any key financial personnel of the Partnership;

(vii)the items required to be communicated to the Committee in accordance with generally accepted auditing standards;

(viii)all critical accounting policies and practices to be used by the Partnership, and all accounting adjustments that were noted or proposed by the auditor but were “passed” (as immaterial or otherwise);

(ix)all alternative treatments of financial information within International Financial Reporting Standards (“IFRS”) that have been discussed with the Service Providers, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the auditor;

(x)any difficulties encountered in the course of the audit work, any restrictions imposed on the scope of activities or access to requested information, any significant disagreements with the Service Providers and the Service Providers’ response; and

(xi)any illegal act that may have occurred and the discovery of which is required to be disclosed to the Committee pursuant to the applicable securities legislation;

(k)annually review and approve the Audit and Non-Audit Services Policy (“Audit and Non-Audit Services Policy”) which sets forth the parameters by which the auditor can provide certain audit and non-audit services to the Partnership not prohibited by law and the process by which the Committee pre-approves such services.  The Committee, or a member(s) of the Committee duly delegated, reviews and approves all auditor requests to provide audit and non-audit services that are not pre-approved under the Audit and Non-Audit Policy, or are in excess of the aggregate fee threshold for the amount of services that can be provided by the auditor.  At each quarterly meeting of the Committee, the Committee ratifies all audit and non-audit services provided by the auditor for the then-ended quarter;

(l)resolve any disagreements between the Service Providers and the auditor regarding financial reporting;

(m)review, and, where appropriate, recommend for approval by the Board, the following:

(i)audited annual financial statements, in conjunction with the report of the auditor;

(ii)interim financial statements;

(iii)annual and interim management discussion and analysis of financial condition and results of operation;

(iv)reconciliations of the annual or interim financial statements; and

(v)all other audited or unaudited financial information contained in public disclosure documents, including, without limitation, any prospectus, or other offering or public disclosure documents and financial statements required by regulatory authorities;

(n)discuss earnings press releases and other press releases containing financial information (to ensure consistency of the disclosure to the financial statements),

- 3 -

as well as financial information and earnings guidance provided to analysts and rating agencies including the use of “pro forma” or “adjusted” non-IFRS information in such press releases and financial information.  Such review may consist of a general discussion of the types of information to be disclosed or the types of presentations to be made;

(o)review the effect of regulatory and accounting initiatives as well as off-balance sheet structures on the Partnership’s financial statements;

(p)review and monitor the effectiveness of and compliance with the Disclosure Policy of the Partnership;

(q)review disclosures made to the Committee by the Chief Executive Officer and Chief Financial Officer of the Service Providers, BRP Energy Group L.P., during their certification process for applicable securities law filings about any significant deficiencies and material weaknesses in the design or operation of the Partnership’s internal control over financial reporting which are reasonably likely to adversely affect the Partnership’s ability to record, process, summarize and report financial information, and any fraud involving management or other employees; 

(r)review the effectiveness of Bthe Partnership’s policies and practices concerning financial reporting, any proposed changes in major accounting policies and the appointment and replacement of the person(s) responsible for financial reporting and the internal audit function;

(s)review the adequacy of the internal controls that have been adopted by the Partnership to safeguard assets from loss and unauthorized use and to verify the accuracy of the financial records and any special audit steps adopted in light of material control deficiencies;

(t)meet privately with the person(s) responsible for the Partnership’s internal audit function as frequently as the Committee feels appropriate to fulfill its responsibilities, which will not be less frequently than annually, to discuss any items of concern;

(u)review the mandate, budget, planned activities, staffing and organizational structure of the internal audit function (which will be provided by the Service Providers or outsourced to a firm other than the auditor) to confirm that it is independent and has sufficient resources to carry out its mandate. The Committee will discuss this mandate with the auditor; review the appointment and replacement of the person(s) in charge of the Partnership’s internal audit and review the significant reports prepared by the internal auditor and the responses provided.  As part of this process, the Committee reviews and approves the governing charter of the internal audit function on an annual basis;

(v)review the controls and procedures that have been adopted to confirm that material information about the Partnership and its subsidiaries that is required to be disclosed under applicable law or stock exchange rules is disclosed and to review the public disclosure of financial information extracted or derived from the Partnership’s financial statements and periodically assess the adequacy of such controls and procedures;

(w)review periodically the Partnership’s policies with respect to risk assessment and management, particularly financial risk exposure, including the steps taken to monitor and control risks;

(x)review the Partnership’s exposures to currency, interest rate, credit and market risks in relation to its capacity to bear risk, and the management of such risks (through hedges, swaps, other financial instruments and otherwise) and be satisfied that measures are in place for the review of such exposures and management of such risks affecting the entities into which Brookfield Renewable Energy L.P. invests;

(y)review the Partnership’s insurance coverage, deductible levels, reinsurance requirements, and various risk sharing protocols and be satisfied that measures are in place for the review of such risks affecting the entities into which Brookfield Renewable Energy L.P. invests;

(z)review systemic risks and other risk-related matters referred to the Committee, including those identified by the Partnership’s internal auditors, as they relate to the Partnership, and be satisfied that measures are in place for the review of such risks affecting the entities into which Brookfield Renewable Energy L.P. invests;

(aa)review periodically the status of taxation matters of the Partnership;

(bb)set clear policies for hiring partners and employees and former partners and employees of the auditor;

(cc)review, with legal counsel where required, such litigation, claims, tax assessments, transactions, material inquiries from regulators and governmental agencies or other contingencies which may have a material impact on financial results or which may otherwise adversely affect the financial well-being of the Partnership;

(dd)review periodically the Partnership’s susceptibility to fraud and oversee the Service Providers’ processes for identifying and managing the risks of fraud; and

(ee)consider other matters of a financial or risk management nature as directed by the Board.

The Partnership’s main purpose is to hold limited partnership interests of Brookfield Renewable Energy L.P.  Accordingly, the Committee performs its functions in part through requiring that Brookfield Renewable Energy L.P. perform appropriate functions and processes and impose appropriate obligations on the entities in which it invests.  Both the Managing General Partner and the general partner of Brookfield Renewable Energy L.P. will fulfill their responsibilities regarding the evaluation of risks and internal controls through receiving and evaluating reports on such matters from or in respect of the entities in which they invest. 

Reporting

The Committee will regularly report to the Board on:

(a)the auditor’s qualifications and independence;

(b)the performance of the auditor and the Committee’s recommendations regarding its reappointment or termination;

(c)the performance of the Partnership’s internal audit function;

(d)the adequacy of the Partnership’s internal controls and disclosure controls;

- 5 -

(e)its recommendations regarding the annual and interim financial statements of the Partnership and any reconciliation of the Partnership’s financial statements, including any issues with respect to the quality or integrity of the financial statements;

(f)its review of any other public disclosure document including the annual report and the  annual and interim management’s discussion and analysis of financial condition and results of operations;

(g)the Partnership’s compliance with legal and regulatory requirements, particularly those related to financial reporting; and

(h)all other significant matters it has addressed and with respect to such other matters that are within its responsibilities.

Complaints Procedure

The Committee will establish a procedure for the receipt, retention and follow-up of complaints received by the Partnership regarding accounting, internal controls, disclosure controls or auditing matters and the procedure for the confidential, anonymous submission of concerns by the individuals engaged in the provision of services regarding such matters pursuant to the Master Services Agreement.

Review and Disclosure

The Committee will review this Charter at least annually and submit it to the Nominating and Governance Committee together with any proposed amendments.  The Nominating and Governance Committee will review this Charter and submit it to the Board for approval with such further amendments as it deems necessary and appropriate.

This Charter will be posted on the Partnership’s website and the annual report of the Partnership will state that this Charter is available on the website or is available in print to any unitholder who requests a copy.

Assessment

At least annually, the Nominating and Governance Committee will review the effectiveness of this Committee in fulfilling its responsibilities and duties as set out in this Charter. The Committee will also conduct its own assessment of the Committee’s performance on an annual basis.

Access to Outside Advisors and Management

The Committee may retain any outside advisor, including legal counsel, at the expense of the Partnership, without the Board’s approval, at any time. The Committee has the authority to determine any such advisor’s fees.

- 6 -

The Partnership will provide for appropriate funding, for payment of compensation to any auditor engaged to prepare or issue an audit report or perform other audit, review or attest services, and ordinary administrative expenses of the Committee.

Members will meet privately with the Service Providers as frequently as they feel is appropriate to fulfill the Committee’s responsibilities, but not less than annually.

Meetings

Meetings of the Committee may be called by any Member or by the Secretary of the Managing General Partner.  Meetings will be held each quarter and at such additional times as is necessary for the Committee to fulfill its responsibilities.  The Committee shall appoint a secretary (who may be the Secretary of the Managing General Partner) to be the secretary of each meeting of the Committee and to maintain minutes of the meeting and deliberations of the Committee.

The powers of the Committee shall be exercisable at a meeting at which a quorum is present.  A quorum shall be not less than a majority of the Members at the relevant time.  Matters decided by the Committee shall be decided by majority vote. 

Notice of each meeting shall be given to each Member, the internal auditor, the auditor, and to the Chair of the Board.  Notice of meeting may be given orally or by letter, facsimile or telephone not less than 24 hours before the time fixed for the meeting.  Members may waive notice of any meeting and attendance at a meeting is deemed waiver of notice.  The notice need not state the purpose or purposes for which the meeting is being held.

The Committee may invite from time to time such persons as it may see fit to attend its meetings and to take part in discussion and consideration of the affairs of the Committee.  The Committee may require the auditors to attend any or all meetings.

In addition, the Committee shall meet at least annually with the person responsible for the internal audit function and the independent auditor in separate executive sessions to provide the opportunity for full and frank discussion without members of the Service Providers present.

Definitions

Capitalized terms used in this Charter and not otherwise defined have the meaning attributed to them below:

“affiliate” of any person means any other person that, directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with such person.

“Audit Committee Financial Expert” means a person who has the following attributes:

(a)an understanding of generally accepted accounting principles and financial statements;

(b)the ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

- 7 -

(c)experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Brookfield Renewable’s financial statements, or experience actively supervising one or more persons engaged in such activities;

(d)an understanding of internal controls and procedures for financial reporting; and

(e)an understanding of audit committee functions acquired through any one or more of the following;

(i)education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions;

(ii)experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

(iii)experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

(iv)other relevant experience.

“BAM” means Brookfield Asset Management Inc.

“BAM Group” means BAM and any affiliates of BAM, other than any member of the BEP Group.

“BEP Group” means the Partnership, Brookfield Renewable Energy L.P., the Holding Entities, the Operating Entities and any other direct or indirect subsidiary of any Holding Entity.

“Financially Literate” means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Partnership’s financial statements.

“Holding Entities” means the subsidiaries of Brookfield Renewable Energy L.P., from time to time, through which it indirectly holds all of the Partnership’s interests in the Operating Entities.

“Independent” has the meaning based on the rules and guidelines of applicable stock exchanges and securities regulating authorities.

“Master Services Agreement” means the master services agreement among the Partnership, the Service Providers, Brookfield Renewable Energy L.P. and the Holding Entities.

“Operating Entities” means any entities which, from time to time, directly or indirectly hold the operations and/or renewable energy assets of the Partnership.

“Service Providers” means BRP Energy Group L.P., Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P., Brookfield Renewable Energy Group (Bermuda) Limited and Brookfield Global Renewable Energy Advisor Limited and other affiliates of BAM that provide services pursuant to the Master Services Agreement or any other service agreement or arrangement that is contemplated by the Master Services Agreement.

This Charter of the Committee was reviewed and approved by the Board on May 2, 2017.

- 8 -

EX-15.3

 

Exhibit 15.3

Consent of Independent Registered Public Accounting Firm

We consent to the use in this Annual Report on Form 20-F of Brookfield Renewable Partners L.P. (“Brookfield Renewable”) of our reports dated February 28, 2018, with respect to the consolidated financial statements of Brookfield Renewable as at December 31, 2017 and 2016, and for each of the years in the three-year period ended December 31, 2017, and the effectiveness of Brookfield Renewable’s internal control over financial reporting as of December 31, 2017, included herein.

/s/ Ernst & Young LLP

Chartered Professional Accountants

Licensed Public Accountants

Toronto, Canada

February 28, 2018

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017
Document And Entity Infromation [Line Items]
Entity Registrant Name	BROOKFIELD RENEWABLE PARTNERS L.P.
Entity Central Index Key	0001533232
Trading Symbol	BEP
Document type	20-F
Document period end date	Dec. 31, 2017
Amendment flag	false
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Limited Partnership units
Document And Entity Infromation [Line Items]
Entity Public Float		$ 7,459,058,727
Entity LP Units Outstanding	180,388,361
General partnership units
Document And Entity Infromation [Line Items]
Entity Public Float		109,639,773
Entity LP Units Outstanding	2,651,506
Redeemable/Exchangeable partnership units
Document And Entity Infromation [Line Items]
Entity Public Float		$ 5,361,384,061
Entity LP Units Outstanding	129,658,623

XML

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Statment of Income (Loss) [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Other income	47	64	122
Direct operating costs	978	1,038	552
Management service costs	(82)	(62)	(48)
Interest expense borrowings	(632)	(606)	(429)
Share of earnings (loss) from equity-accounted investments	2	0	10
Unrealized financial instruments loss	33	4	9
Depreciation	782	781	616
Other	(28)	(38)	(63)
Income tax (expense) recovery
Current	(39)	(44)	(18)
Deferred	(49)	97	80
Total Income Tax recovery (expense)	(88)	53	60
Net (loss) income	51	40	103
Net (loss) income attributable to:
Non-controlling interests	288	251	156
Preferred limited partners' equity	28	15	1
Limited partners' equity	$ (32)	$ (36)	$ 2
Basic and Diluted earnings per LP unit	$ (0.18)	$ (0.23)	$ 0.01
Non-controlling interests [member]
Consolidated Statment of Income (Loss) [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Participating Non-controlling Interests Operating Subsidiaries
Income tax (expense) recovery
Net (loss) income	53	65	69
Net (loss) income attributable to:
Non-controlling interests	53	65	69
General partnership interest in a holding subsidiary held by Brookfield
Income tax (expense) recovery
Net (loss) income			0
Net (loss) income attributable to:
Non-controlling interests	(1)	0	0
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Income tax (expense) recovery
Net (loss) income	(23)	(29)	1
Net (loss) income attributable to:
Non-controlling interests	(23)	(29)	1
Preferred equity
Income tax (expense) recovery
Net (loss) income	26	25	30
Net (loss) income attributable to:
Non-controlling interests	$ 26	$ 25	$ 30

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Statement Of Comprehensive Income [line items]
Net (loss) income	$ 51	$ 40	$ 103
Other comprehensive income that will not be reclassified to net income
Revaluations of property, plant and equipment	872	417	1,197
Revaluations of property, plant and equipment related to equity-accounted investments	54	7	96
Actuarial (loss) gain on defined benefit plans	(2)	(2)	5
Deferred income taxes on above items	(338)	34	283
Total items that will not be reclassified to net income	1,262	388	1,015
Other comprehensive income (loss) that may be reclassified to net income
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	4	8	10
Unrealized gain on available-for-sale securities	(22)	61	0
Reclassification adjustments for amounts recognized in net (loss) income	(1)	(41)	(32)
Foreign currency translation	190	986	(1,138)
Unrealized (loss) gain on foreign currency swaps - net investment hedge	(94)	(66)	55
Deferred income taxes on above items	11	(7)	(8)
Total items that may be reclassified subsequently to net (loss) income	88	941	(1,113)
Other comprehensive income	1,350	1,329	(98)
Comprehensive income	1,401	1,369	5
Comprehensive income attributable to:
Preferred limited partners' equity	28	15	1
Limited partners' equity	494	332	(94)
Comprehensive income	1,401	1,369	5
Non-controlling interests [member]
Other comprehensive income (loss) that may be reclassified to net income
Comprehensive income	1,401	1,369	5
Comprehensive income attributable to:
Comprehensive income	1,401	1,369	5
Participating Non-controlling Interests Operating Subsidiaries
Consolidated Statement Of Comprehensive Income [line items]
Net (loss) income	53	65	69
Other comprehensive income (loss) that may be reclassified to net income
Other comprehensive income	383	635	204
Comprehensive income attributable to:
Non-controlling interests	436	700	273
General partnership interest in a holding subsidiary held by Brookfield
Consolidated Statement Of Comprehensive Income [line items]
Net (loss) income			0
Other comprehensive income (loss) that may be reclassified to net income
Other comprehensive income	9	6	(2)
Comprehensive income attributable to:
Non-controlling interests	8	6	(2)
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Consolidated Statement Of Comprehensive Income [line items]
Net (loss) income	(23)	(29)	1
Other comprehensive income (loss) that may be reclassified to net income
Other comprehensive income	393	304	(87)
Comprehensive income attributable to:
Non-controlling interests	370	275	(86)
Preferred equity
Consolidated Statement Of Comprehensive Income [line items]
Net (loss) income	26	25	30
Other comprehensive income (loss) that may be reclassified to net income
Other comprehensive income	39	16	(117)
Comprehensive income attributable to:
Non-controlling interests	$ 65	$ 41	$ (87)

XML

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 799	$ 223
Restricted cash	181	121
Trade receivables and other current assets	554	454
Financial instrument assets	72	55
Due from related parties	60	54
Total Current Assets	1,666	907
Financial instrument assets	113	145
Equity-accounted investments	721	206
Property, plant and equipment, at fair value	27,096	25,257
Goodwill	901	896
Deferred income tax assets	177	150
Other long-term assets	230	176
Total Assets	30,904	27,737
Current liabilities
Accounts payable and accrued liabilities	542	467
Financial instrument liabilities	184	156
Due to related parties	112	76
Current portion of long-term debt	1,676	1,034
Total Current Liabilities	2,514	1,733
Financial instrument liabilities	86	72
Long-term debt and credit facilities	10,090	9,148
Deferred income tax liabilities	3,588	3,802
Other long-term liabilities	344	310
Total Liabilities	16,622	15,065
Equity
Equity Attributable To Preferred LP Equity	616	576
Limited partners' equity	3,956	3,448
Total Equity	14,282	12,672
Total Equity And Liabilities	30,904	27,737
Non-controlling interests
Current assets
Property, plant and equipment, at fair value	27,096	25,257
Total Assets	30,904	27,737
Current liabilities
Total Liabilities	16,622	15,065
Participating Non-controlling Interests Operating Subsidiaries
Equity
Non-controlling interests	6,298	5,589
Total Equity	6,298	5,589
General partnership interest in a holding subsidiary held by Brookfield
Equity
Non-controlling interests	58	55
Total Equity	58	55
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Equity
Non-controlling interests	2,843	2,680
Total Equity	2,843	2,680
Preferred equity
Equity
Non-controlling interests	616	576
Total Equity	$ 616	$ 576

XML

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Limited Partners' Equity	Foreign Currency Translation	Revaluation Surplus	Actuarial losses on defined benefit plans	Cash flow hedges	Available-for-sale investments	Preferred limited partners' equity	Preferred equity	Participating Non-controlling Interests Operating Subsidiaries	General partnership interest in a holding subsidiary held by Brookfield	Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Balance, as at at Dec. 31, 2014		$ (241)	$ (241)	$ 3,685	$ (9)	$ (27)			$ 728	$ 2,062	$ 59	$ 2,865
Net (loss) income	$ 103	2	0	0	0	0		$ 1	30	69	0	1
Other comprehensive income	(98)	0	(429)	334	2	(3)		0	(117)	204	(2)	(87)
Issue Of Equity
Net proceeds	128	0	0	0	0	0		128	0	0	0	0
LP Units and preferred shares purchased for cancellation	(10)	(9)							(1)
Capital contributions	460	0								460
Distributions or dividends declared		(239)						(1)	(30)	(208)	(12)	(217)
Distribution reinvestment plan	5	5
Other	1	(3)									7	(3)
Change in period	(118)	(244)	(429)	334	2	(3)		128	(118)	525	(7)	(306)
Balance, as at at Dec. 31, 2015	8,763	(485)	(670)	4,019	(7)	(30)		128	610	2,587	52	2,559
Net (loss) income	40	(36)						15	25	65		(29)
Other comprehensive income	1,329		241	105	(1)	(1)	$ 24		16	635	6	304
Issue Of Equity
Net proceeds		657						147
Adjustment		(85)									2	83
Exchange of preferred shares								49	(49)
Capital contributions	2,621									2,621
Acquisition	1,417									1,417
Distributions or dividends declared		(281)						(15)	(25)	(119)	(24)	(232)
Distribution reinvestment plan		9
MTO adjustments		(24)	25							(1,617)
Other		(12)							(1)		19	(5)
Change in period		228	266	105	(1)	(1)	24	196	(34)	3,002	3	121
Balance, as at at Dec. 31, 2016	12,672	(257)	(404)	4,124	(8)	(31)	24	324	576	5,589	55	2,680
Net (loss) income	51	(32)						28	26	53		(23)
Other comprehensive income	1,350		26	508	(1)	2	(9)		39	383	9	393
Issue Of Equity
Net proceeds		411						187
Adjustment		(63)									1	62
Capital contributions	294									294
Acquisition	525									525
Distributions or dividends declared		(328)						(28)	(26)	(539)	(35)	(243)
Distribution reinvestment plan		10
Other		0		(16)					1	(7)	29	(26)
Change in period		(2)	26	492	(1)	2	(9)	187	40	709	3	163
Balance, as at at Dec. 31, 2017	$ 14,282	$ (259)	$ (378)	$ 4,616	$ (9)	$ (29)	$ 15	$ 511	$ 616	$ 6,298	$ 58	$ 2,843

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net (loss) income	$ 51	$ 40	$ 103
Adjustments for the following non-cash items:
Depreciation	782	781	616
Unrealized financial instruments loss	33	4	9
Share of earnings (loss) from equity-accounted investments	2	0	10
Deferred income tax (recovery) expense	(49)	97	80
Gain on disposal	0	0	(53)
Other non-cash items	4	24	62
Dividends received from equity-accounted investments	31	6	19
Changes in due to or from related parties	(5)	(11)	18
Net change in working capital balances	25	137	62
Cash Flows From (Used In) Operating Activities	928	632	588
Financing activities
Long-term debt - borrowings	1,874	3,477	944
Long-term debt - repayments	1,607	1,975	855
Capital contributions from participating non-controlling interests - in operating subsidiaries	294	2,621	460
Acquisition of Isagen from non-controlling interests	(5)	(1,540)	0
Issuance of preferred limited partnership units	187	147	128
Issuance of LP Units	411	657	0
Repurchase of LP Units and preferred shares	0	0	10
Distributions paid:
To participating non-controlling interests - in operating subsidiaries	539	119	208
To preferred shareholders	25	25	31
To preferred limited partners' unitholders	(26)	(12)	0
To unitholders of Brookfield Renewable or BRELP	591	522	461
Cash Flows From Used In Financing Activities	(27)	2,709	(33)
Investing activities
Acquisitions	234	2,886	682
Acquisitions of equity-accounted investments	439	0	0
Cash and cash equivalents in acquired entity	611	117	19
Investment in:
Sustaining capital expenditures	(138)	(118)	(94)
Development and construction of renewable power generating assets	(217)	(251)	(191)
Capital distribution received from equity-accounted investments, net	0	0	144
Proceeds from disposal of assets	150	0	143
Investment in securities	77	60	18
Restricted cash and other	16	7	56
Cash Flows From Used In Investing Activities	(328)	(3,191)	(623)
Foreign exchange gain on cash	3	10	(19)
Cash and cash equivalents
Increase (decrease)	576	160	(87)
Balance, beginning of period	223	63	150
Balance, end of period	799	223	63
Supplemental cash flow information:
Interest paid	611	588	414
Interest received	27	40	18
Income taxes paid	48	55	32
Participating Non-controlling Interests Operating Subsidiaries
Operating activities
Net (loss) income	53	65	69
Financing activities
Capital contributions from participating non-controlling interests - in operating subsidiaries	294	2,621	460
Preferred equity
Operating activities
Net (loss) income	$ 26	$ 25	$ 30

XML

BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES

1. BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES

(a) Statement of compliance

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The accounting policies used in the consolidated financial statements are based on the IFRS applicable as at December 31, 2017, which encompass individual IFRS, International Accounting Standards (“IAS”), and interpretations made by the International Financial Reporting Interpretations Committee (“IFRIC”) and the Standard Interpretations Committee (“SIC”).The policies set out below are consistently applied to all periods presented, unless otherwise noted.

These consolidated financial statements have been authorized for issuance by the Board of Directors of its general partner, BRPL, on February 28, 2018.

Certain comparative figures have been reclassified to conform to the current year’s presentation.

References to $, C$, €, R$, £, and COP are to United States (“U.S.”) dollars, Canadian dollars, Euros, Brazilian reais, British pounds sterling, and Colombian pesos, respectively.

All figures are presented in millions of U.S. dollars unless otherwise noted.

(b) Basis of preparation

The consolidated financial statements have been prepared on the basis of historical cost, except for the revaluation of property, plant and equipment and certain assets and liabilities which have been measured at fair value. Cost is recorded based on the fair value of the consideration given in exchange for assets.

(i) Consolidation

These consolidated financial statements include the accounts of Brookfield Renewable and its subsidiaries, which are the entities over which Brookfield Renewable has control. An investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Non-controlling interests in the equity of Brookfield Renewable’s subsidiaries are shown separately in equity in the consolidated statements of financial position.

Brookfield Renewable has entered into a voting agreement with Brookfield, which provides Brookfield Renewable with control of the general partner of Brookfield Renewable Energy L.P. (“BRELP”), a holding subsidiary. Accordingly, Brookfield Renewable consolidates the accounts of BRELP and its subsidiaries. In addition, BRELP issued redeemable-exchangeable limited partnership units to Brookfield (“Redeemable/Exchangeable partnership units”), pursuant to which the holder may at its request require BRELP to redeem the Redeemable/Exchangeable partnership units for cash consideration. This right is subject to Brookfield Renewable’s right of first refusal which entitles it, at its sole discretion, to elect to acquire all of the Redeemable/Exchangeable partnership units so presented to BRELP that are tendered for redemption in exchange for LP Units. As Brookfield Renewable, at its sole discretion, has the right to settle the obligation with LP Units, the Redeemable/Exchangeable partnership units are classified as equity of Brookfield Renewable (“Participating non-controlling interests – in a holding subsidiary – Redeemable/Exchangeable units held by Brookfield”).

Brookfield Renewable has entered into voting agreements with Brookfield, whereby Brookfield Renewable gained control of the entities that own certain renewable power generating operations in the United States, Brazil, Europe and other countries (including India and China). Brookfield Renewable has also entered into a voting agreement with our consortium partners in respect of our Colombian operations. These voting agreements provide Brookfield Renewable the authority to direct the election of the Boards of Directors of the relevant entities, among other things, and therefore provide Brookfield Renewable with control. Accordingly, Brookfield Renewable consolidates the accounts of these entities. Refer to Note 27 - Related party transactions for further information.

For entities previously controlled by Brookfield Asset Management, the voting agreements entered into do not represent business combinations in accordance with IFRS 3, Business Combinations(“IFRS 3”), as all combining businesses are ultimately controlled by Brookfield Asset Management both before and after the transactions were completed. Brookfield Renewable accounts for these transactions involving entities under common control in a manner similar to a pooling of interest, which requires the presentation of pre-voting agreement financial information as if the transactions had always been in place. Refer to Note 1(o)(ii) - Critical judgments in applying accounting policies - Common control transactions for Brookfield Renewable’s policy on accounting for transactions under common control.

(ii) Equity-accounted investments

Equity-accounted investments are entities over which Brookfield Renewable has significant influence or joint arrangements representing joint ventures. Significant influence is the ability to participate in the financial and operating policy decisions of the investee, but without controlling or jointly controlling those investees. Such investments are accounted for using the equity method.

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Brookfield Renewable accounts for its interests in joint ventures using the equity method.

Under the equity method, the carrying value of an interest in an investee is initially recognized at cost and adjusted for Brookfield Renewable’s share of net income, other comprehensive income (“OCI”), distributions by the equity-accounted investment and other adjustments to Brookfield Renewable’s proportionate interest in the investee.

(c) Foreign currency translation

All figures reported in the consolidated financial statements and tabular disclosures to the consolidated financial statements are reflected in millions of U.S. dollars, which is the functional currency of Brookfield Renewable. Each of the foreign operations included in these consolidated financial statements determines its own functional currency, and items included in the financial statements of each subsidiary are measured using that functional currency.

Assets and liabilities of foreign operations having a functional currency other than the U.S. dollar are translated at the rate of exchange prevailing at the reporting date and revenues and expenses at the rate of exchange prevailing at the dates of the transactions during the period. Gains or losses on translation of foreign subsidiaries are included in OCI. Gains or losses on foreign currency denominated balances and transactions that are designated as hedges of net investments in these operations are reported in the same manner.

In preparing the consolidated financial statements of Brookfield Renewable, foreign currency denominated monetary assets and liabilities are translated into the functional currency using the closing rate at the applicable consolidated statement of financial position dates. Non-monetary assets and liabilities, denominated in a foreign currency and measured at fair value, are translated at the rate of exchange prevailing at the date when the fair value was determined and non-monetary assets measured at historical cost are translated at the historical rate. Revenues and expenses are measured in the functional currency at the rates of exchange prevailing at the dates of the transactions with gains or losses included in income.

(d) Cash and cash equivalents

Cash and cash equivalents include cash, term deposits and money market instruments with original maturities of less than 90 days.

(e) Restricted cash

Restricted cash includes cash and cash equivalents, where the availability of funds is restricted primarily by credit agreements.

(f) Property, plant and equipment and revaluation method

Power generating assets are classified as property, plant and equipment and are accounted for using the revaluation method under IAS 16, Property, Plant and Equipment (“IAS 16”). Property, plant and equipment are initially measured at cost and subsequently carried at their revalued amount, being the fair value at the date of the revaluation, less any subsequent accumulated depreciation and any subsequent accumulated impairment losses.

Brookfield Renewable generally determines the fair value of its property, plant and equipment by using a 20-year discounted cash flow model. This model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. The model also includes estimates of future electricity prices, anticipated long-term average generation, estimated operating and capital expenditures, and assumptions about future inflation rates and discount rates by geographical location. Construction work-in-progress (“CWIP”) is revalued when sufficient information exists to determine fair value using the discounted cash flow method. Revaluations are made on an annual basis as at December 31 to ensure that the carrying amount does not differ significantly from fair value. For power generating assets acquired through business combinations during the year, Brookfield Renewable initially measures the assets at fair value consistent with the policy described in Note 1(l) – Business combinations. Accordingly, in the year of acquisition, power generating assets are not revalued at year-end unless there is an indication that assets are impaired.

Where the carrying amount of an asset increased as a result of a revaluation, the increase is recognized in income to the extent the increase reverses a previously recognized decrease recorded through income, with the remainder of the increase recognized in OCI and accumulated in equity under revaluation surplus and non-controlling interest. Where the carrying amount of an asset decreased, the decrease is recognized in OCI to the extent that a balance exists in revaluation surplus with respect to the asset, with the remainder of the decrease recognized in income.

Depreciation on power generating assets is calculated on a straight-line basis over the estimated service lives of the assets, which are as follows:

Costs are allocated to significant components of property, plant and equipment. When items of property, plant and equipment have different useful lives, they are accounted for as separate items (significant components) and depreciated separately. To ensure the accuracy of useful lives and residual values, a review is conducted annually.

Depreciation is calculated based on the cost of the asset less its residual value. Depreciation commences when the asset is in the location and conditions necessary for it to be capable of operating in the manner intended by management. It ceases at the earlier of the date the asset is classified as held-for-sale and the date the asset is derecognized. An item of property, plant and equipment and any significant component is derecognized upon disposal or when no future economic benefits are expected from its use. Other assets include equipment, buildings and leasehold improvements. Buildings, furniture and fixtures, leasehold improvements and office equipment are recorded at historical cost, less accumulated depreciation. Land and CWIP are not subject to depreciation.

The depreciation of property, plant and equipment in Brazil is based on the duration of the authorization or the useful life of a concession asset. The weighted-average remaining duration at December 31, 2017 is 15 years (2016: 15 years). Since land rights are part of the concession or authorization, this cost is also subject to depreciation.

Any accumulated depreciation at the date of revaluation is eliminated against the gross carrying amount of the asset, and the net amount is applied to the revalued amount of the asset.

Gains and losses on disposal of an item of property, plant and equipment are recognized in Other income in the consolidated statements of income. The revaluation surplus is reclassified within the respective components of equity and not reclassified to net income when the assets are disposed.

(g) Asset impairment

At each statement of financial position date, management assesses whether there is any indication that assets are impaired. For non-financial tangible and intangible assets (including equity-accounted investments), an impairment is recognized if the recoverable amount, determined as the greater of the estimated fair value, less costs to sell, and the discounted future cash flows generated from use and eventual disposal of an asset or cash-generating unit, is less than its carrying value. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail. Should an impairment loss subsequently reverse, the carrying amount of the asset is increased to the lesser of the revised estimate of the recoverable amount, and the carrying amount that would have been recorded had no impairment loss been recognized previously.

(h) Trade receivables and other current assets

Trade receivables and other current assets are recognized initially at fair value, and subsequently measured at amortized cost using the effective interest method, less any allowance for uncollectability.

(i) Financial instruments

All financial instruments are classified into one of the following categories: assets and liabilities at fair value through profit or loss (“FVTPL”), cash, loans and receivables, financial instruments used for hedging, and other financial liabilities. All financial instruments are recorded at fair value at recognition. Subsequent to initial recognition, financial assets classified as loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method. Financial assets and financial liabilities classified as financial instruments used for cash-flow hedging continue to be recognized at fair value through OCI. Other financial assets and financial liabilities and non-hedging financial instruments are recorded at fair value through profit and loss.

Brookfield Renewable presents the liability and equity components separately upon recognition of such financial instruments. The amount of accretion relating to the liability component is recognized in profit or loss; and the amount of consideration relating to the equity component is recognized in equity.

Brookfield Renewable selectively utilizes derivative financial instruments to manage financial risks, including interest rate, commodity and foreign exchange risks. A derivative is a financial instrument, which requires little or no initial investment, settles at a future date, and has a value that changes in response to the change in a specified variable such as an interest rate, financial instrument price, commodity price, foreign exchange rate, index of prices or rates, credit rating or credit index. Hedge accounting is applied when the derivative is designated as a hedge of a specific exposure, and it is highly probable that it will continue to be effective as a hedge based on an expectation of offsetting cash flows or fair value. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as a hedge or the hedging relationship is terminated. Once discontinued, the cumulative change in fair value of a derivative that was previously recorded in equity by the application of hedge accounting is recognized in income over the remaining term of the original hedging relationship, unless the originally forecasted transaction is no longer expected to occur, at which point it is released to income. The fair values of derivative financial instruments are included in financial instrument assets or financial instrument liabilities, respectively.

(i) Items qualifying as hedges

Cash flow hedge

The effective portion of unrealized gains and losses on interest rate forward and swap contracts designated as hedges of future interest rate payments are included in equity as cash flow hedges when the interest rate risk relates to an anticipated interest payment. The periodic exchanges of payments on interest rate swap contracts designated as hedges of debt are recorded on an accrual basis as an adjustment to interest expense. The periodic exchanges of payments on interest rate contracts designated as hedges of future interest payments are recorded in income over the term of the corresponding interest payments.

Net investment hedge

Realized and unrealized gains and losses on foreign exchange forward contracts designated as hedges of currency risks are included in equity when the currency risk relates to a net investment in a subsidiary with a functional currency other than the U.S. dollar and are included in income in the period in which the subsidiary is disposed.

(ii) Items not qualifying as hedges

Upon initial recognition of a derivative financial instrument that is not designated as a hedge, a derivative asset or liability is recorded with an offsetting deferred liability or asset, respectively. Gains or losses arising from changes in fair value of the derivative asset or liability are recognized in income through fair value gains or losses in the period the changes occur. The deferred liability or asset is amortized through income, on a straight-line basis, over the life of the derivative financial instrument.

(iii) Available-for-sale investments

Brookfield Renewable maintains a portfolio of marketable securities comprised of liquid equity and debt securities categorized as available-for-sale when it is not Brookfield Renewable’s strategic intent to sell the securities and the securities were not acquired principally for their near-term sale.  Available-for-sale equity and debt investments are recorded at fair value with unrealized gains and losses recorded in OCI. Realized gains and losses are recorded in income when investments are sold and are calculated using the average carrying amount of securities sold. If the fair value of an investment declines below the carrying amount, qualitative and quantitative assessments of whether the impairment is either significant or prolonged is undertaken. All relevant facts and circumstances in this assessment are undertaken to determine, particularly the length of time and extent to which fair value has declined below the carrying amount. In the case of significant or prolonged decline in fair value of an investment, an impairment loss is recognized.

(j) Revenue and expense recognition

Revenue is derived from the sale of electricity and is recorded at the time power is provided based upon the output delivered and capacity provided at rates specified under either contract terms or prevailing market rates. The revenue must be considered collectible and the costs incurred to provide the electricity to be measurable before recognizing the related revenue.Costs related to the purchases of power or fuel are recorded upon delivery. All other costs are recorded as incurred.

(k) Income taxes

Current income tax assets and liabilities are measured at the amount expected to be paid to tax authorities, net of recoveries, based on the tax rates and laws enacted or substantively enacted at the statement of financial position dates. Current income tax assets and liabilities are included in trade receivables and other current assets and accounts payable and accrued liabilities, respectively.

Deferred tax is recognized on taxable temporary differences between the tax bases and the carrying amounts of assets and liabilities. Deferred tax is not recognized if the temporary difference arises from goodwill or from initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither taxable profit nor accounting profit. Deferred income tax assets are recognized for all deductible temporary differences, carry forwards of unused tax credits and unused tax losses, to the extent that it is probable that deductions, tax credits and tax losses can be utilized. The carrying amount of deferred income tax assets is reviewed at each statement of financial position date and reduced to the extent it is no longer probable that the income tax assets will be recovered. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the statement of financial position dates.

Current and deferred income taxes relating to items recognized directly in OCI are also recognized directly in OCI.

(l) Business combinations

The acquisition of a business is accounted for using the acquisition method. The consideration for an acquisition is measured at the aggregate of the fair values, at the date of exchange, of the assets transferred, the liabilities incurred to former owners of the acquired business, and equity instruments issued by the acquirer in exchange for control of the acquired business. The acquired business’ identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognized at their fair values at the acquisition date, except for income taxes which are measured in accordance with IAS 12, Income Taxes, share-based payments which are measured in accordance with IFRS 2, Share-based Payment and non-current assets that are classified as held-for-sale which are measured at fair value less costs to sell in accordance with IFRS 5, Non-current Assets Held for Sale and Discontinued Operations. The non-controlling interest in the acquiree is initially measured at the non-controlling interest’s proportion of the net fair value of the identifiable assets, liabilities and contingent liabilities recognized or when applicable, at the fair value of the shares outstanding.

To the extent that the aggregate of the fair value of consideration paid, the amount of any non-controlling interest and the fair value of any previously held interest in the acquiree exceeds the fair value of the net identifiable tangible and intangible assets acquired, goodwill is recognized. To the extent that this difference is negative, the amount is recognized as a gain in income. Goodwill is not amortized and is not deductible for tax purposes. However, after initial recognition, goodwill will be measured at cost less any accumulated impairment losses. An impairment assessment will be performed at least annually, and whenever circumstances such as significant declines in expected revenues, earnings or cash flows indicate that it is more likely than not that goodwill might be impaired. Goodwill impairment charges are not reversible.

When a business combination is achieved in stages, previously held interests in the acquired entity are re-measured to fair value at the acquisition date, which is the date control is obtained, and the resulting gain or loss, if any, is recognized in income. Amounts arising from interests in the acquired business prior to the acquisition date that have previously been recognized in OCI are reclassified to income. Upon disposal or loss of control of a subsidiary, the carrying amount of the net assets of the subsidiary (including any OCI relating to the subsidiary) are derecognized with the difference between any proceeds received and the carrying amount of the net assets recognized as a gain or loss in income.

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in fair values are adjusted against the cost of the acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as liabilities will be recognized in the consolidated statements of income, whereas changes in the fair values of contingent consideration classified within equity are not subsequently re-measured.

(m) Other items

(i) Capitalized costs

Capitalized costs related to CWIP include all eligible expenditures incurred in connection with the development and construction of the power generating asset. The expenditures consist of cost of materials, direct labor and any other costs directly attributable to bringing the asset to a working condition for its intended use, and the costs of dismantling and removing the items and restoring the site on which they are located. Interest and borrowing costs are capitalized when activities that are necessary to prepare the asset for its intended use or sale are in progress, expenditures for the asset have been incurred and funds have been used or borrowed to fund the construction or development. Capitalization of costs ceases when the asset is ready for its intended use.

(ii) Pension and employee future benefits

Pension and employee future benefits are recognized in the consolidated financial statements in respect of employees of the operating entities within Brookfield Renewable. The costs of retirement benefits for defined benefit plans and post-employment benefits are recognized as the benefits are earned by employees. The project unit credit method, using the length of service and management’s best estimate assumptions, is used to value its pension and other retirement benefits. All actuarial gains and losses are recognized immediately through OCI in order for the net pension asset or liability recognized in the consolidated statements of financial position to reflect the full value of the plan deficit or surplus. Net interest is calculated by applying the discount rate to the net defined benefit asset or liability. Changes in the net defined benefit obligation related to service costs (comprising of current service costs, past services costs, gains and losses on curtailments and non-routine settlements), and net interest expense or income are recognized in the consolidated statements of income.

Re-measurements, comprising of actuarial gains or losses, the effect of the asset ceiling, and the return on plan assets (excluding net interest), are recognized immediately in the consolidated statements of financial position with a corresponding debit or credit to retained earnings through OCI in the period in which they occur. Re-measurements are not reclassified to profit or loss in subsequent periods. For defined contribution plans, amounts are expensed based on employee entitlement.

(iii) Decommissioning, restoration and environmental liabilities

Legal and constructive obligations associated with the retirement of property, plant and equipment are recorded as liabilities when those obligations are incurred and are measured at the present value of the expected costs to settle the liability, using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The liability is accreted up to the date the liability will be incurred with a corresponding charge to operating expenses. The carrying amount of decommissioning, restoration and environmental liabilities is reviewed annually with changes in the estimates of timing or amount of cash flows added to or deducted from the cost of the related asset.

(iv) Interest and borrowing costs

Interest and borrowing costs are capitalized when such costs are directly attributable to the acquisition, construction or production of a qualifying asset. A qualifying asset is an asset that takes a substantial period of time to prepare for its intended use.

(v) Provisions

A provision is a liability of uncertain timing or amount. A provision is recognized if Brookfield Renewable has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount can be reliably estimated. Provisions are not recognized for future operating losses. The provision is measured at the present value of the best estimate of the expenditures expected to be required to settle the obligation using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the obligation. Provisions are re-measured at each statement of financial position date using the current discount rate. The increase in the provision due to the passage of time is recognized as interest expense.

(vi) Interest income

Interest income is earned with the passage of time and is recorded on an accrual basis.

(vii) Government grants

Brookfield Renewable becomes eligible for government grants by constructing or purchasing renewable power generating assets, and by bringing those assets to commercial operation, coupled with a successful application to the applicable program or agency. The assessment of whether or not a project has complied with the conditions and that there is reasonable assurance the grants will be received will be undertaken on a case by case basis. Brookfield Renewable reduces the cost of the asset by the amount of the grant. The grant amounts are recognized in income on a systematic basis as a reduction of depreciation over the periods, and in the proportions, in which depreciation on those assets is charged.

With respect to grants related to income, the government assistance (in the form of the difference between market price and guaranteed fixed price) typically becomes payable once electricity is produced and delivered to the relevant grid. It is at this point that the receipt of the grant becomes reasonably assured, and therefore the grant is recognized as revenue in the month that delivery of the electricity occurs.

(n) Critical estimates

Brookfield Renewable makes estimates and assumptions that affect the carrying value of assets and liabilities, disclosure of contingent assets and liabilities and the reported amount of income and OCI for the year. Actual results could differ from these estimates. The estimates and assumptions that are critical to the determination of the amounts reported in the consolidated financial statements relate to the following:

(i) Property, plant and equipment

The fair value of Brookfield Renewable’s property, plant and equipment is calculated using estimates and assumptions about future electricity prices from renewable sources, anticipated long-term average generation, estimated operating and capital expenditures, future inflation rates and discount rates, as described in Note 12 - Property, plant and equipment, at fair value. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies - Property, plant and equipment for further details.

Estimates of useful lives and residual values are used in determining depreciation and amortization. To ensure the accuracy of useful lives and residual values, these estimates are reviewed on an annual basis.

(ii) Financial instruments

Brookfield Renewable makes estimates and assumptions that affect the carrying value of its financial instruments, including estimates and assumptions about future electricity prices, long-term average generation, capacity prices, discount rates and the timing of energy delivery. Non-financial instruments are valued using estimates of future electricity prices which are estimated by considering broker quotes for the years in which there is a liquid market and, for the subsequent years, Brookfield Renewable’s best estimate of electricity prices that would allow new entrants into the market. The fair value of interest rate swaps is the estimated amount that another party would receive or pay to terminate the swap agreements at the reporting date, taking into account current market interest rates. This valuation technique approximates the net present value of future cash flows. See Note 5 - Risk management and financial instruments for more details.

(iii) Deferred income taxes

The consolidated financial statements include estimates and assumptions for determining the future tax rates applicable to subsidiaries and identifying the temporary differences that relate to each subsidiary. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply during the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the consolidated statement of financial position dates. Operating plans and forecasts are used to estimate when the temporary difference will reverse.

(o) Critical judgments in applying accounting policies

The following are the critical judgments that have been made in applying the accounting policies used in the consolidated financial statements and that have the most significant effect on the amounts in the consolidated financial statements:

(i) Preparation of consolidated financial statements

These consolidated financial statements present the financial position, results of operations and cash flows of Brookfield Renewable. Judgment is required in determining what assets, liabilities and transactions are recognized in the consolidated financial statements as pertaining to Brookfield Renewable’s operations.

(ii) Common control transactions

Common control business combinations specifically fall outside of scope of IFRS 3 and as such management has used its judgment to determine an appropriate policy to account for these transactions, considering other relevant accounting guidance that is within the framework of principles in IFRS and that reflects the economic reality of the transactions, in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. As a result, the consolidated financial statements account for assets and liabilities acquired at the previous carrying value on the predecessor’s financial statements. Differences between the consideration given and the assets and liabilities received are recorded directly to equity.

(iii) Property, plant and equipment

The accounting policy relating to Brookfield Renewable’s property, plant and equipment is described in Note 1(f) - Property, plant and equipment and revaluation method. In applying this policy, judgment is used in determining whether certain costs are additions to the carrying amount of the property, plant and equipment as opposed to repairs and maintenance. If an asset has been developed, judgment is required to identify the point at which the asset is capable of being used as intended and to identify the directly attributable costs to be included in the carrying value of the development asset. The useful lives of property, plant and equipment are determined by independent engineers periodically with an annual review by management.

Annually, Brookfield Renewable determines the fair value of its property, plant and equipment using a methodology that it has judged to be reasonable. The methodology is generally a 20-year discounted cash flow model. Twenty years is the period considered reasonable as Brookfield Renewable has 20-year capital plans and it believes a reasonable third party would be indifferent between extending the cash flows further in the model versus using a discounted terminal value.

The valuation model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. With respect to estimated future generation that does not incorporate long-term power purchase agreement pricing, the cash flow model uses estimates of future electricity prices using broker quotes from independent sources for the years in which there is a liquid market. The valuation of power generating assets not linked to long-term power purchase agreements also requires the development of a long-term estimate of future electricity prices. In this regard the valuation model uses a discount to the all-in cost of construction with a reasonable return, to secure energy from new renewable on-shore wind development resources as the benchmark that will establish the market price for electricity for renewable resources.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth by the year 2025 in North America and Colombia, 2023 in Europe, and 2021 in Brazil. Based on current supply and demand fundamentals, Brookfield Renewable revised the year of new entry in North America to 2025 from 2023. The year of new entry is viewed as the point when generators must build additional capacity to maintain system reliability and provide an adequate level of reserve generation with the retirement of older coal fired plants and rising environmental compliance costs in North America and Europe, and overall increasing demand in Colombia and Brazil. For the North American and European businesses, Brookfield Renewable has estimated a discount to these new-build wind prices to determine renewable electricity prices for hydroelectric and wind facilities. In Brazil and Colombia, the estimate of future electricity prices is based on a similar approach as applied in North America using a forecast of the all-in cost of development.

Terminal values are included in the valuation of hydroelectric assets in North America and Colombia. For the hydroelectric assets in Brazil, cash flows have been included based on the duration of the authorization or useful life of a concession asset without consideration of potential renewal value.

Discount rates are determined each year by considering the current interest rates, average market cost of capital as well as the price risk and the geographical location of the operational facilities as judged by management. Inflation rates are also determined by considering the current inflation rates and the expectations of future rates by economists. Operating costs are based on long-term budgets escalated for inflation. Each operational facility has a 20-year capital plan that it follows to ensure the maximum life of its assets is achieved. Foreign exchange rates are forecasted by using the spot rates and the available forward rates, extrapolated beyond the period available. The inputs described above to the discounted cash flow model require management to consider facts, trends and plans in making its judgments as to what derives a reasonable fair value of its property, plant and equipment.

(iv) Financial instruments

The accounting policy relating to Brookfield Renewable’s financial instruments is described in Note 1(i) - Financial instruments. In applying the policy, judgments are made in applying the criteria set out in IAS 39, Financial Instruments: Recognition and Measurement (“IAS 39”), to record financial instruments at fair value through profit and loss, and the assessments of the effectiveness of hedging relationships.

(v) Deferred income taxes

The accounting policy relating to Brookfield Renewable’s income taxes is described in Note 1(k) - Income taxes. In applying this policy, judgments are made in determining the probability of whether deductions, tax credits and tax losses can be utilized.

(p) Future changes in accounting policies

The following table provides a brief description of accounting standards issued but not yet effective, none of which will be early adopted by Brookfield Renewable:

Standard	Description	Effective date	Effect on financial statements
In July 2014, the IASB issued the final version of IFRS 9, Financial Instruments (“IFRS 9”).	The standard reflects all phases of the financial instruments project and replaces IAS 39, Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. This standard establishes principles for the financial reporting of financial assets and financial liabilities that will present relevant and useful information to users of financial statements for their assessment of the amounts, timing and uncertainty of an entity’s future cash flows. The new standard makes several improvements to IAS 39; mostly notably adopting a principle based approach to hedge accounting. While this does not change the type of hedging relationships or the requirement to measure ineffectiveness, it simplifies the application of hedge accounting and should allow for better alignment of risk management strategies with accounting presentation. Other changes include replacing the multiple financial asset impairment models in IAS 39 with a single model based on expected credit losses on all financial assets, and replacing the existing complex classifications structure with a business model approach based on the intent and nature of the cash flows.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 9 is a significant initiative for Brookfield Renewable.Management has chosen to adopt the standard retrospectively with no restatement of comparative periods. The assessment of financial assets and liabilities under the new classification methodology has been completed. Hedging documentation has been updated for compliance with IFRS 9 and updated risk management policies and internal controls to align with the new standard. Management has also assessed the impact of the new impairment requirements for financial assets.There are no material adjustments from the adoption of the standard.

Standard	Description	Effective date	Effect on financial statements
IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) was issued by the IASB on May 28, 2014.	IFRS 15 outlines a single comprehensive model to account for revenue arising from contracts with customers and will replace the majority of existing IFRS requirements on revenue recognition including IAS 18, Revenue, IAS 11, Construction Contracts and related interpretations. The core principle of the standard is to recognize revenue to depict the transfer of goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard has prescribed a five-step model to apply the principles. The standard also specifies how to account for the incremental costs of obtaining a contract and the costs directly related to fulfilling a contract as well as requiring more informative and relevant disclosures. IFRS 15 applies to nearly all contracts with customers, unless covered by another standard, such as leases, financial instruments and insurance contracts.In April 2016, the IASB issued amendments to IFRS 15, which provided additional guidance on the identification of performance obligations, on assessing principal versus agent considerations and on licensing revenue. The amendments also provide additional transition relief upon initial adoption of IFRS 15 and have the same effective date as the IFRS 15 standard.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 15 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard using the modified retrospective approach. This method results in a cumulative catch-up adjustment to equity as of January 1, 2018 as if the standard had always been in effect. Management has completed its review of material revenue streams. The majority of Brookfield Renewable’s revenue streams are within the scope of IFRS 15 and are include the sale of energy, capacity and renewable energy credits through power purchase agreements or through merchant mechanisms. Based on management’s analysis, substantially all of the contracts currently in place for the year beginning on January 1, 2018 do not contain a difference in the timing or measurement of revenue recognition under the new standard and the impact of both the cumulative catch up and ongoing revenue recognition is expected to not be material to the overall statements of Brookfield Renewable.

Standard	Description	Effective date	Effect on financial statements
IFRS 16, Leases (“IFRS 16”) was issued by the IASB on January 13, 2016.	IFRS 16 brings most leases onto the statement of financial position for lessees under a single model, eliminating the distinction between operating and finance leases. Lessor accounting remains largely unchanged and the distinction between operating and finance leases is retained. Under IFRS 16 a lessee recognizes a right-of-use asset and a lease liability. The right-of-use asset is treated similarly to other non-financial assets and depreciated accordingly, and the liability accrues interest. The lease liability is initially measured at the present value of the lease payments payable over the lease term, discounted at the rate implicit in the lease. Lessees are permitted to make an accounting policy election, by class of underlying asset, to apply a method like IAS 17’s operating lease accounting and not recognize lease assets and lease liabilities for leases with a lease term of 12 months or less, and on a lease-by-lease basis, to apply a method similar to current operating lease accounting to leases for which the underlying asset is of low value. IFRS 16 supersedes IAS 17, Leases and related interpretations. A lessee will apply IFRS 16 to its leases either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying IFRS 16 being recognized at the date of initial application.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2019, with early adoption permitted.	Management has formed its adoption working group and participated in planning sessions with Brookfield Asset Management. Management continues to evaluate the impact of IFRS 16 on the consolidated financial statements.

XML

PRINCIPAL SUBSIDIARIES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

PRINCIPAL SUBSIDIARIES

2. PRINCIPAL SUBSIDIARIES

The following table lists the subsidiaries of Brookfield Renewable which, in the opinion of management, significantly affect its financial position and results of operations as at December 31, 2017:

	Jurisdiction of	Percentage of
	Incorporation	voting securities
	or Organization	owned or controlled
Alta Wind VIII LLC(1)	Delaware	100
BIF II Safe Harbor Holdings LLC(1)	Delaware	100
BIF III Holtwood LLC(1)	Delaware	100
BRE GLBL Holdings L.P.(1)	Bermuda	100
BRI Green Energy Limited(1)	Republic of Ireland	100
Brookfield BRP Canada Corp.	Alberta	100
Brookfield Energia Comercializadora Ltda	Brazil	100
Brookfield Power US Holding America Co.	Delaware	100
Brookfield Power Wind Prince LP	Ontario	100
Brookfield Renewable UK Hydro Limited	England and Wales	100
Brookfield Smoky Mountain Hydropower LLC(1)	Delaware	100
Brookfield White Pine Hydro LLC(1)	Delaware	100
Catalyst Old River Hydroelectric Limited Partnership(2)	Louisiana	75
Erie Boulevard Hydropower, L.P.	Delaware	100
Granite Reliable Power, LLC(1)	Delaware	89.5
Great Lakes Hydro America, LLC	Delaware	100
Great Lakes Power Limited	Ontario	100
Hawks Nest Hydro LLC	Delaware	100
Isagen S.A. E.S.P.(1)	Colombia	99.5
Itiquira Energética S.A.	Brazil	100
Kwagis Power Limited Partnership	British Columbia	75
Lièvre Power L.P.	Québec	100
Mississagi Power Trust	Québec	100
Orion Canadian Holdings 1 AIV L.P.	Ontario	100
PEA - Parque Eólico da Serra, Unipessola S.A.(1)	Portugal	100
Powell River Energy Inc.	Canada	100
Rumford Falls Hydro LLC	Delaware	100
Safe Harbor Water Power Corporation(1)	Pennsylvania	100
Tangará Energia S.A.(1)	Brazil - São Paulo	100
Windstar Energy, LLC	California	100
2016 Comber Wind Limited Partnership	Ontario	100

• Voting control held through voting agreements with Brookfield.
• Non-voting economic interest held through preferred shares and secured notes.

XML

ACQUISITIONS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

BUSINESS COMBINATIONS

3. ACQUISITIONS

The following investmentswere accounted for using the equity method asBrookfield Renewable has significant influence through its position in the business, and the results of operations have been included in the auditedannual consolidated financial statements since the date of investment. See Note 19 – Equity-accounted investments.

European Storage

InAugust 2017, Brookfield Renewable, along with its institutional partners, acquired a 25% interest in FHH Guernsey Ltd which owns a 2.1 GW pumped storage portfolio in the United Kingdom (“European Storage”). Brookfield Renewable retains an approximate 7% economic interest in the portfolio. Total consideration was £194 million ($248 million). The acquisition costs of £1 million ($1 million) were incurred and capitalized.

TerraForm Power

In October 2017, along with its institutional partners, Brookfield Renewable closed the acquisition of a 51% interest in TerraForm Power, Inc. (“TerraForm Power”). TerraForm Power is a 2,600 MW large scale diversified portfolio of solar and wind assets located predominately in the U.S. Brookfield Renewable retains an indirect economic interest of approximately 16% in TerraForm Power for a total net investment of $203 million.

Brookfield Renewable had previously accounted for its indirect interest in TerraForm Power as an available for sale investment. The change from available for sale accounting to equity method accounting resulted in a gain of $13 million being reclassified from the audited annual consolidated statement of comprehensive income to the statement of income and included in Other income, representing the accumulated gain on the previously held indirect investment.The acquisition costs of $1million were incurredand capitalized.

In October 2017, Brookfield Renewable entered into a voting agreement with the Brookfield subsidiary that ultimately controls TerraForm Power. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election for one of the four directors of the Brookfield subsidiary, thereby providing Brookfield Renewable with significant influence over this subsidiary.

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the date of acquisition.

European Wind

In February 2017, Brookfield Renewable entered into an agreement to acquire, along with its institutional partners, a 100% interest in a 16 MW wind facility in Northern Ireland (“European Wind”).

In August 2017, Brookfield Renewable, along with its institutional partners, completed the acquisition of European Wind, which was commissioned in July of 2017. Accordingly, if the acquisition had taken place at the beginning of the year, the revenue from European Wind earned prior to the date of acquisition would have been immaterial. The total consideration was £24 million ($32 million). Brookfield Renewable retains an approximate 40% controlling interest in the asset. The total acquisition costs of less than $1 million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income.

TerraForm Global

In December 2017, along with its institutional partners, Brookfield Renewable closed the acquisition of a 100% interest in TerraForm Global, Inc. (“TerraForm Global”). TerraForm Global is 919 MW portfolio of diversified solar and wind assets located predominately in Brazil and Asia. The total consideration paid was $657 million and the fair value of the interest previously held was $100 million. Brookfield Renewable retains a 31% economic interest in TerraForm Global with its share of the fair value of previously held interest on the acquisition date totaling $30 million. Brookfield Renewable’s share of the consideration paid was $202 million.

Brookfield Renewable had previously accounted for its indirect interest in TerraForm Global as an available for sale investment. The change from available for sale accounting to consolidation accounting resulted in a gain of $2 million being reclassified from the audited annual consolidated statement of comprehensive income to the statement of income and included in Other income, representing the accumulated gain on the previously held indirect investment.

If the acquisition had taken place at the beginning of the year, the revenue from TerraForm Global for the year ended December 31, 2017 would have been $250 million. The total acquisition costs of $1million were expensed as incurred and have been classified under Other in the audited annual consolidated statements of income.

In December 2017, Brookfield Renewable entered into a voting agreement with an affiliate of Brookfield Renewable that ultimately controls TerraForm Global. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of the directors of the Brookfield subsidiary.

The provisional purchase price allocations, at fair value, with respect to the acquisitions are as follows:

	TerraForm		European
(MILLIONS)	Global		Wind		Total
Cash and cash equivalents	$	611	$	-	$	611
Restricted cash		90		-		90
Trade receivables and other current assets		62		1		63
Financial instruments		20		-		20
Property, plant and equipment, at fair value		1,208		37		1,245
Deferred tax assets		18		-		18
Other long-term assets		94		-		94
Current liabilities		(73)		(4)		(77)
Current portion of long-term debt		(1,183)		-		(1,183)
Financial instruments		(15)		-		(15)
Long-term debt		(5)		-		(5)
Deferred income tax liabilities		(15)		(2)		(17)
Other long-term liabilities		(54)		-		(54)
Non-controlling interests		(1)		-		(1)
Fair value of net assets acquired		757		32		789

Completed in 2016

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the respective dates of acquisition.

Colombia Portfolio

On January 22, 2016, Brookfield Renewable and its institutional partners (the “consortium”) acquired a 57.6% interest in Isagen S.A. E.S.P (“Isagen”) from the Colombian government (the “Initial Investment”). Isagen was a listed entity in Colombia. It is Colombia’s third-largest power generation company and owns and operates a 3,032 MW portfolio, consisting predominantly of a portfolio of largely reservoir-based, hydroelectric facilities. Annual generation is expected to approximate 15,000 GWh.

Following the closing of the Initial Investment, the consortium was required to conduct two mandatory tender offers (“MTOs”) for the Isagen public shareholders at the same price per share paid for its initial 57.6% controlling interest.

The consortium closed the First MTO and the Second MTO on May 13, 2016 and September 14, 2016, respectively. During 2017, the consortium acquired further shares from public shareholders and completed delisting of Isagen from the Colombia Stock Exchange. After giving effect to the MTOs and additional shares the consortium ownership stands at 99.5% as of December 31, 2017.

Brookfield Renewable is the general partner of and controls the entity that holds the consortium’s 99.5% interest in Isagen. Brookfield Renewable’s investment is equivalent to an approximate 24% economic interest.

The total acquisition costs of $13 million were expensed as incurred and have been classified under Other in theaudited annual consolidated statements of income in 2016.

If the acquisition had taken place at the beginning of the year, the revenue from Isagen for the year ended December 31, 2016 would have been $900 million.

Brazil Portfolio

In January 2016, Brookfield Renewable acquired a 51 MW hydroelectric portfolio in Brazil (“Brazil Portfolio”). Total consideration of R$417 million ($103 million) included cash paid of R$355 million ($88 million), deferred consideration of R$35 million ($9 million) and the impact of the foreign currency contracts of R$24 million ($6 million). Brookfield Renewable retains a 100% interest in the portfolio.

The total acquisition costs of less than $1 million were expensed as incurred and classified under Other in the audited annualconsolidated statements of income in 2016.

North American Portfolio

In April 2016, Brookfield Renewable acquired a 296 MW portfolio of hydroelectric facilities in Pennsylvania that are expected to generate 1,109 GWh annually (“Pennsylvania Hydro”). The acquisition was completed with institutional partners, and Brookfield Renewable retains approximately 28.6% interest in the portfolio.

Total cash consideration was $859 million. The acquisition costs of $6 million were expensed as incurred and have been classified under Other in the audited annualconsolidated statements of income in 2016.

If the acquisition had taken place at the beginning of the year, the revenue from Pennsylvania Hydro for the year ended December 31, 2016 would have been $46million.

In April 2016, Brookfield Renewable entered into a voting agreement with a Brookfield subsidiary that forms part of Brookfield Infrastructure Fund III. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of the directors of the entity that ultimately controls and operates the Pennsylvania Hydro assets.  

European Wind Development Project

In September 2016, Brookfield Renewable acquired a 19 MW wind development project in Ireland. The total consideration of €8 million ($9 million) included cash consideration of €7 million ($8 million) and deferred consideration and working capital adjustments of €1 million ($1 million). The acquisition was completed with institutional partners, and Brookfield Renewable retained an approximately 40% controlling interest in the asset. The total acquisition costs of less than $1 million were expensed as incurred and have been classified under Other in the audited annualconsolidated statements of income.

Purchase price allocations

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Colombia		Brazil		Pennsylvania		Ireland		Total
Cash and cash equivalents	$	113	$	4	$	-	$	-	$	117
Trade receivables and other current assets		174		2		1		-		177
Property, plant and equipment, at fair value		4,772		100		859		10		5,741
Other long-term assets		15		-		-		-		15
Current liabilities		(463)		(3)		(1)		-		(467)
Long-term debt		(899)		-		-		-		(899)
Deferred income tax liabilities		(1,019)		-		-		(1)		(1,020)
Other long-term liabilities		(149)		-		-		-		(149)
Non-controlling interests		(1,417)		-		-		-		(1,417)
Fair value of net assets acquired		1,127		103		859		9		2,098
Goodwill (Note 17)		799		-		-		-		799
Purchase price	$	1,926	$	103	$	859	$	9	$	2,897

Completed in 2015

The following investments were accounted for using the acquisition method, and the results of operations have been included in the audited annual consolidated financial statements since the respective dates of acquisition.

European Wind Portfolio

In February 2015, Brookfield Renewable acquired two wind facilities in Portugal (“Portugal Wind Portfolio”) with an aggregate capacity of 123 MW, and expected to generate 260 GWh annually.

The acquisition was completed with institutional partners, and Brookfield Renewable retains an approximate 40% controlling interest. Total consideration of €65 million ($71 million) included cash paid on closing of €58 million ($63 million), post-closing adjustments, and deferred consideration.

The revenue for the year ended December 31, 2015is $28 million.

In June 2015, Brookfield Renewable acquired an onshore wind development pipeline in Scotland (“Scotland Wind Pipeline”) totaling approximately 1,200 MW, including a mix of contracted, permitted and earlier stage development projects. Total consideration of £47 million ($72 million) included upfront cash paid of £40 million ($62 million), contingent consideration, and working capital adjustments. The acquisition costs of $1 million were expensed as incurred. The contingent consideration was recorded at its fair value of £6 million ($9 million), which represents the present value of a probability-weighted evaluation of Brookfield Renewable’s obligation to pay up to £63 million ($97 million) related to the build-out of the development pipeline. The contingent consideration was recognized in the Consolidated Statements of Financial Position within the Other long-term liabilities line item.

Brazil Portfolio

In November 2014, Brookfield Renewable entered into an agreement to acquire a 488 MW portfolio in Brazil comprising of hydroelectric, wind and biomass generating capacity (“Brazil Portfolio”). The acquisitions were completed in 2015 with institutional partners, and Brookfield Renewable retains an approximate 40% controlling interest.

Total consideration of R$1,867million ($588million) included cash paid of R$1,717 million ($541million) and deferred consideration. The remaining non-controlling interests were subsequently acquired for R$50million ($16million).The total acquisition costs of $2 million were expensed as incurred.

If the acquisition had taken place at the beginning of 2015 the revenue from the acquisition would have been $93 million (unaudited) for the year ended December 31, 2015.

Voting Agreements

In March 2015, Brookfield Renewable entered into voting agreements with certain Brookfield subsidiaries (and their managing members) related to Brookfield Infrastructure Fund II (the “BIF II Entities”) which are co-investors along with a subsidiary of Brookfield Renewable in Brazilian entities (the “FIPs”) which hold the Brazil Portfolio power generating operations. Pursuant to these voting agreements, the BIF II Entities agreed to provide Brookfield Renewable, among other things, the authority to direct the election of the manager of the jointly-owned FIPs.  

Purchase price allocations

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Brazil		Portugal		Scotland		Total
Cash and cash equivalents	$	19	$	-	$	-	$	19
Restricted cash		16		5		-		21
Trade receivables and other current assets		16		3		1		20
Property, plant and equipment, at fair value		854		209		84		1,147
Current liabilities		(21)		(19)		(1)		(41)
Long-term debt		(280)		(111)		-		(391)
Other long-term liabilities		-		(16)		(12)		(28)
Non-controlling interests		(16)		-		-		(16)
Net assets acquired	$	588	$	71	$	72	$	731

During the years ended December 31, 2017 and 2016, the purchase price allocations for the acquisitions in 2016 and 2015, respectively, were finalized. No material changes to the provisional purchase price allocations disclosed in the audited annual consolidated financial statements for 2016 and 2015 had to be considered for acquisitions made in the respective years.

XML

DISPOSAL OF ASSETS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

DISPOSAL OF ASSETS

4. DISPOSAL OF ASSETS

In March 2017, along with its institutional partners, Brookfield Renewable sold its interest in two wind facilities in Ireland,with a combined capacity of 137 MW, to a third party. Gross cash consideration consisted of €147 million ($155 million), inclusive of working capital adjustments. The resulting loss on disposition of €5 million ($5 million), net of €5 million ($5 million) of transaction costs,was recognized in the audited annual consolidated statements of income within Other. Brookfield Renewable’s interest was approximately 40%.

As a result of the disposition, the post-tax accumulated revaluation surplus of €44 million ($47 million) was reclassified from other comprehensive income directly to equity. Further, other comprehensive loss of €3 million ($3 million) post-tax on interest rate swaps which had been designated as hedges was reclassified to the audited annual consolidated statements of income.

Summarized financial information relating to the disposal of the facilities is shown below:

(MILLIONS)
Net proceeds, including working capital adjustments and transaction costs		$	150
Carrying value
	Assets		353
	Liabilities		(198)
			155
Loss on disposal		$	(5)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

5. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT

Brookfield Renewable’s activities expose it to a variety of financial risks, including market risk (i.e., commodity price risk, interest rate risk, and foreign currency risk), credit risk and liquidity risk. Brookfield Renewable uses financial instruments primarily to manage these risks.

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes. Therefore, the discussion below is not intended to fully reflect Brookfield Renewable’s risk exposure.

(a) Market risk

Market risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate because of changes in market prices.

Brookfield Renewable faces market risk from foreign currency assets and liabilities, the impact of changes in interest rates, and floating rate liabilities. Market risk is managed by funding assets with financial liabilities in the same currency and with similar interest rate characteristics and holding financial contracts, such as interest rate swaps and foreign exchange contracts, to minimize residual exposures. Financial instruments held by Brookfield Renewable that are subject to market risk include borrowings and financial instruments, such as interest rate, currency and commodity contracts. The categories of financial instruments that can give rise to significant variability are described below:

(i) Electricity price risk

Electricity price risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate because of changes in electricity prices. Electricity price risk arises from the sale of Brookfield Renewable’s uncontracted generation. Brookfield Renewable aims to sell electricity under long-term contracts to secure stable prices and mitigate its exposure to wholesale markets.

The table below summarizes the impact of changes in the market price of electricity as at December 31. The impact is expressed in terms of the effect on net income and OCI. The sensitivities are based on the assumption that the market price changes by five percent with all other variables held constant.

Impact of a 5% change in the market price of electricity, on outstanding energy derivative contracts, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	(3)	$	(1)	$	(2)	$	(4)	$	(7)	$	(7)
5% decrease		3		1		2		4		7		7

(ii) Foreign currency risk

Foreign currency risk is defined for these purposes as the risk that the fair value of a financial instrument held by Brookfield Renewable will fluctuate because of changes in foreign currency rates.

Brookfield Renewable has exposure to the Canadian dollar, Brazilian real, Euro, British pound sterling, Colombian peso, Indian rupee, South African rand, Malaysian ringgit, Thai baht and Chinese yuan through its investments in foreign operations. Consequently, fluctuations in the U.S. dollar exchange rate against these currencies increase the volatility of net income and other comprehensive income. Brookfield Renewable holds foreign currency contracts primarily to mitigate this exposure.

The table below summarizes the impact of changes in the exchange rate as at December 31. The impact is expressed in terms of the effect on income and OCI. The sensitivities are based on the assumption that the currency exchange rate changes by five percent with all other variables held constant.

Impact of a 5% change in U.S. dollar exchange rates, on outstanding foreign exchange swaps, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	4	$	1	$	2	$	79	$	51	$	10
5% decrease		(4)		(1)		(2)		(79)		(51)		(10)

Amounts represent the potential annual net pretax impact.

Amounts represent the potential annual net pretax impact.

Amounts represent the potential annual net pretax impact.

(iii) Interest rate risk

Interest rate risk is defined for these purposes as the risk that the fair value or future cash flows of a financial instrument held by Brookfield Renewable will fluctuate, because of changes in interest rates.

Brookfield Renewable’s assets largely consist of long duration physical assets. Brookfield Renewable’s financial liabilities consist primarily of long-term fixed rate debt or floating-rate debt that has been swapped to fixed rates with interest rate financial instruments. All non-derivative financial liabilities are recorded at their amortized cost. Brookfield Renewable also holds interest rate contracts to lock-in fixed rates on certain anticipated future debt issuances.

Brookfield Renewablewill enter into interest rate swaps designed to minimize the exposure to interest rate fluctuations on its variable rate debt.  Fluctuations in interest rates could impact Brookfield Renewable’s cash flows, primarily with respect to the interest payable against Brookfield Renewable’s variable rate debt, which is limited to certain subsidiary borrowings with a total principal value of $4,176 million (2016: $4,194 million). Of this principal value, $824 million (2016: $966 million) has been hedged through the use of interest rate swaps. The fair values of the recognized liability for the interest rate swaps were calculated using a valuation model with observable interest rates.

The table below summarizes the impact of changes in the interest rate as at December 31. The impact is expressed in terms of the effect on income and OCI. The sensitivities are based on the assumption that the interest rate changes by one percent with all other variables held constant.

Impact of a 1% change in interest rates, on outstanding interest rate swaps and variable rate debt, for the year ended December 31:

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
1% increase	$	17	$	(17)	$	(15)	$	54	$	115	$	125
1% decrease		(17)		17		15		(54)		(115)		(125)

(b) Credit risk

Credit risk is the risk of loss due to the failure of a borrower or counterparty to fulfill its contractual obligations. Brookfield Renewable’s exposure to credit risk in respect of financial instruments relates primarily to counterparty obligations regarding energy contracts, interest rate swaps, forward foreign exchange contracts and physical electricity and gas transactions.

Brookfield Renewable minimizes credit risk with counterparties through the selection, monitoring and diversification of counterparties, and the use of standard trading contracts, and other credit risk mitigation techniques. In addition, Brookfield Renewable’s power purchase agreements are reviewed regularly and are almost exclusively with customers having long standing credit histories or investment grade ratings, which limit the risk of non-collection. See Note 22 - Trade receivables and other current assets, for additional details regarding Brookfield Renewable’s trade receivables balance.

The maximum credit exposure at December 31 was as follows:

(MILLIONS)		2017		2016
Cash and cash equivalents	$	799	$	223
Restricted cash(1)		284		250
Trade receivables and other short-term receivables		442		365
Financial instrument assets(1)		185		200
Due from related parties		60		54
	$	1,770	$	1,092

Includes both the current and long-term amounts.

(c) Liquidity risk

Liquidity risk is the risk that Brookfield Renewable cannot meet a demand for cash or fund an obligation when due. Liquidity risk is mitigated by Brookfield Renewable’s cash and cash equivalent balances and its access to undrawn credit facilities. Details of the available portion of credit facilities are included in Note 13 – Long-term debt and credit facilities.  Brookfield Renewable also ensures that ithas access to public capital markets and maintains a strong investment grade credit rating.

Brookfield Renewable is also subject to the risk associated with debt financing. This risk is mitigated by the long-term duration of debt instruments and the diversification in maturity dates over an extended period of time.

CASH OBLIGATIONS

The table below classifies the cash obligations related to Brookfield Renewable’s liabilities into relevant maturity groupings based on the remaining period from the statement of financial position dates to the contractual maturity date.  As the amounts are the contractual undiscounted cash flows (gross of unamortized financing fees and accumulated amortization, where applicable), they may not agree with the amounts disclosed in the consolidated statements of financial position.

AS AT DECEMBER 31, 2017
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	542	$	-	$	-	$	542
Financial instrument liabilities(1)		184		62		24		270
Due to related parties		112		-		-		112
Other long-term liabilities - concession payments		1		3		10		14
Long-term debt and credit facilities(1)		1,676		4,587		5,579		11,842
Interest payable on long-term debt(2)		634		1,924		1,697		4,255
Total	$	3,149	$	6,576	$	7,310	$	17,035
AS AT DECEMBER 31, 2016
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	467	$	-	$	-	$	467
Financial instrument liabilities(1)		156		66		6		228
Due to related parties		76		-		-		76
Other long-term liabilities - concession payments		1		4		11		16
Long-term debt and credit facilities(1)		1,034		3,970		5,256		10,260
Interest payable on long-term debt(2)		589		1,821		1,449		3,859
Total	$	2,323	$	5,861	$	6,722	$	14,906

⁽¹⁾Includes both the current and long-term amounts.

⁽²⁾Represents aggregate interest payable expected to be paid over the entire term of the obligations, if held to maturity. Variable rate interest payments have been calculated based on estimated interest rates.

Brookfield Renewable classifies its assets and liabilities as outlined below:

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2017	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	799	$	-	$	-	$	-	$	-	$	799
Restricted cash		181	-	-		-		-		-		181
Trade and other receivables(2)		442		-		-		-		-		442
Other current assets		-		-		-		-		112		112
Due from related parties(2)		60		-		-		-		-		60
Financial instrument assets(3)		-		20		6		159		-		185
Equity-accounted investments		-		-		-		-		721		721
Property, plant and equipment, at fair value		-		-		-		-		27,096		27,096
Goodwill		-		-		-		-		901		901
Deferred income tax assets		-		-		-		-		177		177
Other long-term assets		103		-		-		-		127		230
Total assets	$	1,585	$	20	$	6	$	159	$	29,134	$	30,904
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	542	$	-	$	542
Financial instrument liabilities(3)		-		145		125		-		-		270
Due to related parties(2)		-		-		-		112		-		112
Long-term debt and credit facilities(2)(3)		-		-		-		11,766		-		11,766
Deferred income tax liabilities		-		-		-		-		3,588		3,588
Other long-term liabilities		-		-		-		344		-		344
Total liabilities	$	-	$	145	$	125	$	12,764	$	3,588	$	16,622

• Measured at fair value with all gains and losses recorded in the consolidated statement of income.
• Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.
• Includes both the current and long-term amounts.

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2016	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	223	$	-	$	-	$	-	$	-	$	223
Restricted cash		121		-		-		-		-		121
Trade and other receivables(2)		365		-		-		-		-		365
Other current assets		-		-		-		-		89		89
Due from related parties(2)		54		-		-		-		-		54
Financial instrument assets(3)		-		14		50		136		-		200
Equity-accounted investments		-		-		-		-		206		206
Property, plant and equipment, at fair value		-		-		-		-		25,257		25,257
Goodwill		-		-		-		-		896		896
Deferred income tax assets		-		-		-		-		150		150
Other long-term assets		129		-		-		-		47		176
Total assets	$	892	$	14	$	50	$	136	$	26,645	$	27,737
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	467	$	-	$	467
Financial instrument liabilities(3)		-		11		217		-		-		228
Due to related parties(2)		-		-		-		76		-		76
Long-term debt and credit facilities(2)(3)		-		-		-		10,182		-		10,182
Deferred income tax liabilities		-		-		-		-		3,802		3,802
Other long-term liabilities		-		-		-		310		-		310
Total liabilities	$	-	$	11	$	217	$	11,035	$	3,802	$	15,065

• Measured at fair value with all gains and losses recorded in the consolidated statement of income.
• Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.
• Includes both the current and long-term amounts.

Fair value disclosures

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, management looks primarily to external readily observable market inputs such as interest rate yield curves, currency rates, commodity prices and, as applicable, credit spreads.

A fair value measurement of a non-financial asset is the consideration that would be received in an orderly transaction between market participants, considering the highest and best use of the asset.

Assets and liabilitiesmeasured at fair value are categorized into one of three hierarchy levels, described below. Each level is based on the transparency of the inputs used to measure the fair values of assets and liabilities.

Level 1 –inputs are based on unadjusted quoted prices in active markets for identical assets and liabilities;

Level 2 – inputs, other than quoted prices in Level 1, that are observable for the asset or liability, either directly or indirectly; and

Level 3 – inputs for the asset or liability that are not based on observable market data.

The following table presents Brookfield Renewable’s assets and liabilities measured and disclosed at fair value classified by the fair value hierarchy as at December 31:

(MILLIONS)		Level 1		Level 2		Level 3		2017		2016
Assets measured at fair value:
Cash and cash equivalents		$	799	$	-	$	-	$	799	$	223
Restricted cash(1)			284		-		-		284		250
Financial instrument assets(2)
	Energy derivative contracts		-		-		-		-		8
	Interest rate swaps		-		6		-		6		7
	Foreign exchange swaps		-		20		-		20		49
	Available-for-sale investments(2)		79		80		-		159		136
Property, plant and equipment			-		-		27,096		27,096		25,257
Liabilities measured at fair value:
Financial instrument liabilities(3)
	Energy derivative contracts		-		(19)		-		(19)		(5)
	Interest rate swaps		-		(155)		-		(155)		(178)
	Foreign exchange swaps		-		(96)		-		(96)		(45)
Contingent consideration(4)			-		-		(18)		(18)		(16)
Liabilities for which fair value is disclosed:
	Long-term debt and credit facilities		-		(12,479)		-		(12,479)		(10,870)
Total		$	1,162	$	(12,643)	$	27,078	$	15,597	$	14,816

• Includes both the current amount and long-term amount included in Other long-term assets.
• Includes amounts in Level 2 that relate to the Brookfield Infrastructure Debt Fund holdings.
• Includes both current and long-term amounts.
• Amount relates to 2015 and 2014 business combinations with obligations lapsing in 2021 and 2024 respectively.

There were no transfers between levels during the year ended December 31, 2017.

Financial instruments disclosures

The aggregate amount of Brookfield Renewable’s net financial instrument positions as at December 31 are as follows:

				2017				2016
					Net Liabilities		Net Liabilities
(MILLIONS)	Assets		Liabilities		(Assets)		(Assets)
Energy derivative contracts	$	-	$	19	$	19	$	(3)
Interest rate swaps		6		155		149		171
Foreign exchange swaps		20		96		76		(4)
Available-for-sale securities		159		-		(159)		(136)
Total		185		270		85		28
Less: current portion		72		184		112		101
Long-term portion	$	113	$	86	$	(27)	$	(73)

The following table presents the change in Brookfield Renewable’s total net financial instrument liability position as at and for the year ended December 31:

(MILLIONS)		Note		2017		2016		2015
Balance, beginning of year			$	28	$	145	$	77
Increases (decreases) in the net financial instrument liability position:
	Unrealized loss (gain) through income on energy derivative contracts	(a)		5		-		(2)
	Unrealized loss through OCI on energy derivative contracts	(a)		17		28		3
	Unrealized (gain) loss through income on interest rate swaps	(b)		(1)		7		(2)
	Unrealized (gain) loss through OCI on interest rate swaps	(b)		(18)		1		20
	Unrealized loss (gain) through income on foreign exchange swaps	(c)		29		(3)		13
	Unrealized loss (gain) through OCI on foreign exchange swaps	(c)		94		61		(57)
	Unrealized loss through income on available-for-sale investments	(d)		-		-		25
	Unrealized loss (gain) through OCI on available-for-sale investments	(d)		20		(52)		-
	Acquisitions, settlements and other			(89)		(159)		68
Balance, end of year			$	85	$	28	$	145
Financial instrument liabilities not designated as hedging instruments:
Energy derivative contracts		(a)	$	5	$	3	$	-
Interest rate swaps		(b)		107		2		-
Foreign exchange swaps		(c)		33		6		-
Net positions			$	145	$	11	$	-
Financial instrument liabilities designated as hedging instruments:
Energy derivative contracts		(a)	$	14	$	2	$	1
Interest rate swaps		(b)		48		176		178
Foreign exchange swaps		(c)		63		39		12
Net positions			$	125	$	217	$	191
Financial instrument assets not designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(3)	$	-
Interest rate swaps		(b)		(1)		(1)		-
Foreign exchange swaps		(c)		(19)		(10)		(1)
Available-for-sale investments		(d)		(159)		(136)		(14)
Net positions			$	(179)	$	(150)	$	(15)
Financial instrument assets designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(5)	$	(31)
Interest rate swaps		(b)		(5)		(6)		-
Foreign exchange swaps		(c)		(1)		(39)		-
Net positions			$	(6)	$	(50)	$	(31)
Total net positions			$	85	$	28	$	145

(a) Energy derivative contracts

Brookfield Renewable has entered into long-term energy derivative contracts primarily to stabilize or eliminate the price risk on the sale of certain future power generation. Certain energy contracts are recorded in Brookfield Renewable’s consolidated financial statements at an amount equal to fair value, using quoted market prices or, in their absence, a valuation model using both internal and third-party evidence and forecasts.

For the year ended December 31, 2017, gains of $23million relating to energy derivative contracts were realized and reclassified from OCI to revenues in the consolidated statements of income (loss) (2016: $48 million and 2015: $32 million).

Based on market prices as of December 31, 2017, unrealized losses of $9 million (2016: $6 million gains and 2015: $25 million gains) recorded in accumulated other comprehensive income (“AOCI”) on energy derivative contracts are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market prices.

(b) Interest rate hedges

Brookfield Renewable has entered into interest rate hedge contracts primarily to minimize exposure to interest rate fluctuations on its variable rate debt or to lock in interest rates on future debt refinancing. All interest rate hedge contracts are recorded in the consolidated financial statements at fair value.

At December 31, 2017, agreements with a total notional exposure of $1,704 million were outstanding (2016: $2,397 million) including $780million (2016: $871 million) associated with agreements that are not formally designated as hedging instruments. The weighted-average fixed interest rate resulting from these agreements is 4.5% (2016: 2.5%).

For the year ended December 31, 2017, net movements relating to cash flow hedges realized and reclassified from OCI to interest expense – borrowings in the consolidated statements of income (loss) were $20million losses (2016: $16 million and 2015: $nil).

Based on market prices as of December 31, 2017, unrealized losses of $18million (2016: $110 million and 2015: $114 million) recorded in AOCI on interest rate swaps are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market rates.

(c) Foreign exchange swaps

Brookfield Renewable has entered into foreign exchange swaps to minimize its exposure to currency fluctuations impacting its investments and earnings in foreign operations, and to fix the exchange rate on certain anticipated transactions denominated in foreign currencies.

At December 31, 2017, agreements with a total notional exposure of $2,306 million were outstanding (2016: $1,325 million) including $718million (2016: $283 million) associated with agreements that are not formally designated as hedging instruments.

Based on market prices as of December 31, 2017, unrealized losses of $48million (2016: $1million and 2015: $12 million) recorded in AOCI on foreign exchange swaps are expected to be settled or reclassified into income in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market rates.

(d)  Available-for-sale

Brookfield Renewable’s available for sale assets consist of investments in liquid equity and debtsecurities.

Available-for-sale securities are recorded on the statement of financial position at fair value, and are assessed for impairment at each reporting date. For the year ended December 31, 2017, net movements relating to available-for-sale securities realized and reclassified from OCI to net income were $2million gains (2016: $9 million gains and 2015: $nil).

XML

SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

SEGMENTED INFORMATION

6. SEGMENTED INFORMATION

Brookfield Renewable’s Chief Executive Officer and Chief Financial Officer (collectively, the chief operating decision maker or “CODM”) review the results of the business, manage operations, and allocate resources based on the type of technology.

With effect from the fourth quarter of 2017, operations are segmented by technology – 1) hydroelectric, 2) wind, 3) solar, storage, and other (Co-gen and biomass), and 4) corporate – with hydroelectric and wind further segmented by geography (North America, Colombia, Brazil, Europe and Other). To reflect the way in which the CODM now reviews results, manage operations and allocate resources, following the investments in European Storage, TerraForm Power and TerraForm Global and as Brookfield Renewable continues to build out its solar and storage businesses, the CODM has commenced reviewing these businesses along with its Co-gen and biomass businesses on an aggregate basis. The Colombia segment aggregates the financial results of its hydroelectric and Co-gen facilities. A pumped storage facility in North America, that was previously included in the hydroelectric segment, is now included in the “Solar, storage and other” segment. The corporate segment represents all activity performed above the individual segments for the business.

In addition, with the effect from the fourth quarter of 2017, the reporting to the CODM such that the measures utilized by the CODM to assess performance and allocate resources are on a proportionate basis. Information on a proportionate basis reflects Brookfield Renewable’s share from facilities which it accounts for using consolidation and the equity method whereby Brookfield Renewable either controls or exercises significant influence or joint control over the investment, respectively. Proportionate information provides a Unitholder (holders of the GP interest, Redeemable/Exchangeable partnership units, and LP Units) perspective that the CODMconsiders important when performing internal analyses and making strategic and operating decisions. The CODM also believes that providing proportionate information helps investors understand the impacts of decisions made by management and financial results allocable to Brookfield Renewable’s Unitholders.

Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Tables reconciling IFRS data with data presented on a proportionate consolidation basis have been disclosed. Segment revenues, other income, direct operating costs, interest expense, depreciation, current and deferred income taxes, and other are items that will differ from results presented in accordance with IFRS as these items (1) include Brookfield Renewable’s proportionate share of earnings from equity-accounted investments attributable to each of the above-noted items, and (2) exclude the proportionate share of earnings (loss) of consolidated investments not held by us apportioned to each of the above-noted items.

Segmented net income (loss) is not a measure the CODM uses to review the results of business and allocate resources. Brookfield Renewable does not control those entities that have not been consolidated and as such, have been presented as equity-accounted investments in its financial statements. The presentation of the assets and liabilities and revenues and expenses do not represent Brookfield Renewable’s legal claim to such items, and the removal of financial statement amounts that are attributable to non-controlling interests does not extinguish Brookfield Renewable’s legal claims or exposures to such items.

Brookfield Renewable reports its results in accordance with these segments and presents prior period segmented information in a consistent manner.

In accordance with IFRS 8, Operating Segments, Brookfield Renewable discloses information about its reportable segments based upon the measures used by the CODM in assessing performance. The accounting policies of the reportable segments are the same as those described in Note 1 – Basis of preparation and significant accounting policies. Brookfield Renewable analyzes the performance of its operating segments based on revenues, Adjusted EBITDA, and Funds From Operations.

Brookfield Renewable uses Adjusted EBITDA to assess the performance of its operations before the effects of interest expense, income taxes, depreciation, management service costs, non-controlling interests, unrealized gain or loss on financial instruments, non-cash gain or loss from equity-accounted investments, distributions to preferred shareholders and preferred limited partners and other typical non-recurring items. As compared to the preceding years, Brookfield Renewable revised its definition of Adjusted EBITDA to include its proportionate share of Adjusted EBITDA from equity-accounted investments. In preceding years, Brookfield Renewable included its proportionate shares of Funds From Operations from equity-accounted investments. Brookfield Renewablerevised its definition as it believes it provides a more meaningful measure for investors to evaluate financial and operating performance on an allocable basis to Unitholders.

Brookfield Renewable uses Funds From Operations to assess the performance of itsbusiness and is defined as Adjusted EBITDA less management service costs, interest and current income taxes, which is then adjusted for the cash portion of non-controlling interests and distributions to preferred shareholders and preferred limited partners.

The following segmented information is regularly reported to the CODM.

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’s investments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2017:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Solar,		Corporate		Total	equity		to non-		As per
		North						North						Storage and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			945		191		243		161		46		26		67		-	1,679		(74)		1,020		2,625
Other income			1		2		12		-		-		-		6		19	40		(11)		18		47
Direct operating costs			(281)		(94)		(77)		(42)		(20)		(4)		(34)		(25)	(577)		28		(429)		(978)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		57		-		57
Adjusted EBITDA			665		99		178		119		26		22		39		(6)	1,142		-		609		-
Management service costs			-		-		-		-		-		-		-		(82)	(82)		-		-		(82)
Interest expense - borrowings			(180)		(42)		(18)		(45)		(10)		(6)		(17)		(89)	(407)		21		(246)		(632)
Current income taxes			1		(5)		(12)		-		(1)		-		(1)		-	(18)		1		(22)		(39)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(28)	(28)		-		-		(28)
	Preferred equity		-		-		-		-		-		-		-		(26)	(26)		-		-		(26)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(22)		-		(22)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(341)		(341)
Funds From Operations			486		52		148		74		15		16		21		(231)	581		-		-		-
Depreciation			(222)		(26)		(141)		(89)		(24)		(8)		(29)		-	(539)		22		(265)		(782)
Unrealized financial instrument loss			(3)		(3)		-		(1)		(12)		-		-		(10)	(29)		1		(5)		(33)
Deferred income tax expense			(67)		(10)		2		45		6		-		1		(3)	(26)		(3)		(20)		(49)
Other			(20)		6		(8)		(3)		(5)		2		(6)		(9)	(43)		13		2		(28)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(33)		-		(33)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		288		288
Net income (loss) attributable to Unitholders(2)			174		19		1		26		(20)		10		(13)		(253)	(56)		-		-		(56)

• Share of earnings from equity-accounted investments of $2 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $53 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.
• Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’sinvestments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2016:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		192		187		151		56		17		58		1	1,481		(37)		1,008		2,452
Other income			24		3		13		-		-		-		(1)		8	47		-		17		64
Direct operating costs			(295)		(107)		(70)		(36)		(24)		(4)		(26)		(24)	(586)		16		(468)		(1,038)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		21		-		21
Adjusted EBITDA			548		88		130		115		32		13		31		(15)	942		-		557		-
Management service costs			-		-		-		-		-		-		-		(62)	(62)		-		-		(62)
Interest expense - borrowings			(177)		(36)		(24)		(41)		(14)		(7)		(12)		(91)	(402)		12		(216)		(606)
Current income taxes			(4)		(6)		(9)		-		-		-		-		-	(19)		-		(25)		(44)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(15)	(15)		-		-		(15)
	Preferred equity		-		-		-		-		-		-		-		(25)	(25)		-		-		(25)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(12)		-		(12)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(316)		(316)
Funds From Operations			367		46		97		74		18		6		19		(208)	419		-		-		-
Depreciation			(244)		(31)		(125)		(80)		(38)		(4)		(18)		-	(540)		11		(252)		(781)
Unrealized financial instrument loss			1		-		-		-		-		-		2		(6)	(3)		(2)		1		(4)
Deferred income tax expense			31		6		7		49		6		-		-		(21)	78		-		19		97
Other			(27)		4		(5)		4		6		(1)		(2)		2	(19)		-		(19)		(38)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(9)		-		(9)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		251		251
Net income (loss) attributable to Unitholders(2)			128		25		(26)		47		(8)		1		1		(233)	(65)		-		-		(65)

The following table provides each segment’s results in the format that management organizes its segments to make operating decisions and assess performance and reconciles Brookfield Renewable’s proportionate results to our consolidated statements of income on a line by line basis by aggregating the components comprising the earnings from Brookfield Renewable’s investments in associates and reflecting the portion of each line item attributable to non-controlling interests for the year ended December 31, 2015:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		-		203		150		56		9		59		-	1,296		(44)		376		1,628
Other income			23		-		28		12		8		-		-		5	76		-		46		122
Direct operating costs			(285)		-		(67)		(38)		(20)		(1)		(31)		(23)	(465)		18		(105)		(552)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		26		-		26
Adjusted EBITDA			557		-		164		124		44		8		28		(18)	907		-		317		-
Management service costs			-		-		-		-		-		-		-		(48)	(48)		-		-		(48)
Interest expense - borrowings			(179)		-		(18)		(48)		(12)		(3)		(5)		(81)	(346)		6		(89)		(429)
Current income taxes			(5)		-		(10)		-		-		-		-		-	(15)		-		(3)		(18)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(1)	(1)		-		-		(1)
	Preferred equity		-		-		-		-		-		-		-		(30)	(30)		-		-		(30)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(6)		-		(6)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(225)		(225)
Funds From Operations			373		-		136		76		32		5		23		(178)	467		-		-		-
Depreciation			(218)		-		(113)		(83)		(32)		(4)		(12)		-	(462)		9		(161)		(614)
Unrealized financial instrument loss			1		-		-		2		-		-		(1)		(15)	(13)		1		3		(9)
Deferred income tax recovery			36		-		4		16		2		-		-		20	78		-		2		80
Other			14		-		(8)		(30)		(1)		-		(4)		(39)	(68)		-		-		(68)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(10)		-		(10)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		156		156
Net income (loss) attributable to Unitholders(2)			206		-		19		(19)		1		1		6		(212)	2		-		-		2

The following table presents information on a segmented basis about certain items in Brookfield Renewable’s statement of financial position:

																						Contribution
		Attributable to Unitholders																				from		Attributable
		Hydroelectric						Wind								Solar		Corporate		Total		equity		to non-		Total
		North						North								Storage and						accounted		controlling
(MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other		Other						investments		interests
As at December 31, 2017:
Property, plant and equipment, at fair value		$	11,396	$	1,303	$	1,908	$	1,798	$	482	$	304	$	11	$	1,227	$	-	$	18,429	$	(1,451)	$	10,118	$	27,096
Total assets			11,709		1,574		2,149		1,888		532		443		31		1,456		180		19,962		(1,040)		11,982		30,904
Total borrowings			3,049		447		200		1,005		233		192		9		752		2,552		8,439		(848)		4,175		11,766
Total liabilities			5,237		801		380		1,338		334		208		18		877		2,786		11,979		(1,039)		5,682		16,622
For the year ended December 31, 2017:
	Additions to property, plant and equipment		90		8		59		6		34		-		-		13		10		220		(10)		144		354
As at December 31, 2016:
Property, plant and equipment, at fair value		$	10,922	$	1,273	$	1,895	$	1,327	$	545	$	139	$	-	$	491	$	-		16,592	$	(428)	$	9,093	$	25,257
Total assets			11,219		1,577		2,059		1,389		587		153		-		561		182		17,727		(280)		10,290		27,737
Total borrowings			2,946		467		194		727		249		50		-		215		2,229		7,077		(232)		3,337		10,182
Total liabilities			5,414		824		340		990		337		51		-		268		2,418		10,642		(280)		4,703		15,065
For the year ended December 31, 2016:
	Additions to property, plant and equipment		86		9		79		3		18		1		-		18		8		222		(10)		146		358

Geographical Information

The following table presents consolidated revenue split by geographical region:

(MILLIONS)		2017		2016		2015
United States	$	871	$	786	$	799
Colombia		797		819		-
Canada		480		442		426
Brazil		366		269		265
Europe		111		136		138
		2,625		2,452		1,628

The following table presents consolidated property, plant and equipment and equity-accounted investments split by geographical region:

(MILLIONS)		2017		2016
United States	$	11,131	$	10,163
Colombia		5,401		5,275
Canada		5,810		5,845
Brazil		3,479		2,922
Europe		1,332		1,258
Other		664		-
		27,817		25,463

XML

OTHER INCOME

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

Other income

7. OTHER INCOME

Brookfield Renewable’s other income for the year ended December 31 is comprised of the following:

(MILLIONS)			2017		2016		2015
Interest income and other		$	32	$	41	$	21
Gain on available for sale investments (Note 3)			15		-		-
Gains on settlement of foreign currency contracts			-		23		31
Gain on disposal(1)			-		-		53
Compensation related to expired Brazilian
	concession agreements(2)		-		-		17
		$	47	$	64	$	122

^[1],[2]

[1] In 2015, concession agreements relating to two Brazilian hydroelectric facilities expired. Brookfield Renewable elected not to renew these agreements in exchange for compensation of $17 million.

[2] In 2015, the sale of the 102 MW wind facility in California resulted in a gain of $53 million. Brookfield Renewable’s share of the gain was $ 12 million, representing the 22 % interest in the facility, and is net of the cash portion of non-controlling interests.

XML

DIRECT OPERATING COSTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

DIRECT OPERATING COSTS

8.DIRECT OPERATING COSTS

Brookfield Renewable’s direct operating costs for the year ended December 31 are comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Operations, maintenance and administration		$	567	$	553	$	396
Water royalties, property taxes and other			161		149		119
Fuel and power purchases(1)			226		313		15
Energy marketing fees	27		24		23		22
		$	978	$	1,038	$	552

^[1]

[1] F uel and power purchase s are primarily attributable to our portfolio in Colombia.

XML

OTHER

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

Other

9. OTHER

Brookfield Renewable’s other for the year ended December 31 is comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Transaction costs		$	(9)	$	(22)	$	(6)
Change in fair value of property, plant and equipment	12		(33)		(36)		(45)
Unrealized loss on available-for-sale securities			-		-		(25)
Other			14		20		13
		$	(28)	$	(38)	$	(63)

XML

FOREIGN CURRENCY TRANSLATION

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

FOREIGN CURRENCY TRANSLATION

10. FOREIGN CURRENCY TRANSLATION

Brookfield Renewable’s foreign currency translation for the year ended December 31 shown in the consolidated statements of comprehensive income (loss) is comprised of the following:

(MILLIONS)		Notes		2017		2016		2015
Foreign currency translation on
	Property, plant and equipment, at fair value	12	$	506	$	1,186	$	(1,975)
	Long-term debt and credit facilities			(282)		(244)		697
	Deferred income tax liabilities and assets			(82)		(157)		202
	Other assets and liabilities			48		201		(62)
			$	190	$	986	$	(1,138)

XML

INCOME TAXES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

INCOME TAXES

11. INCOME TAXES

The major components of income tax recovery (expense) for the year ended December 31 are as follows:

(MILLIONS)		2017		2016		2015
Income tax (expense) recovery applicable to:
Current taxes
Attributed to the current period	$	(39)	$	(44)	$	(18)
Deferred taxes
Income taxes - origination and reversal of temporary differences	$	8	$	71	$	87
Relating to change in tax rates / imposition of new tax laws		(42)		35		6
Relating to unrecognized temporary differences and tax losses		(15)		(9)		(15)
	$	(49)	$	97	$	78
Total income tax (expense) recovery	$	(88)	$	53	$	60

The major components of deferred income tax recovery (expense) for the year ended December 31 recorded directly to OCI are as follows:

(MILLIONS)		2017		2016		2015
Deferred income taxes attributed to:
Financial instruments designated as cash flow hedges	$	(4)	$	2	$	8
Other		15		(7)		(17)
Revaluation surplus
Origination and reversal of temporary differences		(248)		(55)		(263)
Relating to changes in tax rates / imposition of new tax laws		586		19		(19)
	$	349	$	(41)	$	(291)

Brookfield Renewable’s effective income tax (expense) recovery for the year ended December 31 is different from its recovery at its statutory income tax rate due to the differences below:

(MILLIONS)			2017		2016		2015
Statutory income tax (expense) recovery(1)		$	(50)	$	5	$	(15)
(Reduction) increase resulting from:
	Increase in tax assets not recognized		(15)		(9)		(15)
	Deemed profit method differences in Brazil		1		(11)		10
	Differences between statutory rate and future tax rate		(38)		54		68
	Income or losses recorded not taxable to Brookfield Renewable		14		14		14
	Other		-		-		(2)
Effective income tax (expense) recovery		$	(88)	$	53	$	60

Statutory income tax expense is calculated at the domestic rates applicable to the profits in the country concerned.

The above reconciliation has been prepared by aggregating the information for all of Brookfield Renewable’s subsidiaries using the domestic rate in each tax jurisdiction.

Brookfield Renewable’s effective income tax rate was 63.31% for the year ended December 31, 2017 (2016: 384.03%). The effective tax rate is more than the statutory rate primarily due to rate differentials, legislative changes in tax rates during the year, and non-controlling interests’ income not subject to tax.

The following table details the expiry date, if applicable, of the unrecognized deferred tax assets as at December 31:

(MILLIONS)		2017		2016
2018 to 2022	$	8	$	-
2023 and thereafter		108		98

The deferred tax assets and liabilities of the following temporary differences have been recognized in the consolidated financial statements for the year ended December 31:

			Amount available		Difference		Net deferred
	Non-capital		for future		between tax and		tax (liabilities)
(MILLIONS)	losses		deductions		carrying value		assets
As at January 1, 2015	$	403	$	88	$	(2,986)	$	(2,495)
Recognized in Net income (loss)		73		(11)		16		78
Recognized in equity		(1)		-		(279)		(280)
Business combination		5		-		(35)		(30)
Foreign exchange		(22)		(12)		223		189
As at December 31, 2015		458		65		(3,061)		(2,538)
Recognized in Net income (loss)		24		(10)		83		97
Recognized in equity		17		-		(48)		(31)
Business combination		-		-		(1,020)		(1,020)
Foreign exchange		-		1		(161)		(160)
As at December 31, 2016		499		56		(4,207)		(3,652)
Recognized in Net income (loss)		(97)		(5)		53		(49)
Recognized in equity		13		-		341		354
Business combination		79		-		(63)		16
Foreign exchange		14		4		(98)		(80)
As at December 31, 2017	$	508	$	55	$	(3,974)	$	(3,411)

The deferred income tax liabilities include $2,561 million (2016: $2,948 million) of liabilities which relate to property, plant and equipment revaluations included in equity.

The taxable temporary difference attributable to Brookfield Renewable’s interest in its subsidiaries, branches, associates, and joint ventures is $1,549 million (2016: $1,380million).

As a result of the recent U.S. income tax reform, Brookfield Renewable's net deferred tax liability decreased by $546 million, of which $41million was recorded as a tax expense in net income and $587million was recorded as a tax recovery in other comprehensive income. Over the long term, it is expected that the decrease in the U.S. federal income tax rate to reduce our overall effective tax rate.

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE

12.PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE

The following table presents a reconciliation of property, plant and equipment at fair value:

(MILLIONS)		Notes	Hydroelectric		Wind		Other(1)		Total(2)
As at December 31, 2014			$	15,210	$	3,315	$	41	$	18,566
Additions				183		51		55		289
Acquisitions through business combinations		3		307		624		229		1,160
Disposal				-		(230)		-		(230)
Items recognized through OCI
	Change in fair value			1,141		52		16		1,209
	Foreign exchange			(1,585)		(336)		(54)		(1,975)
Items recognized through net income
	Change in fair value			(2)		(43)		-		(45)
	Depreciation			(407)		(200)		(9)		(616)
As at December 31, 2015			$	14,847	$	3,233	$	278	$	18,358
Additions				269		71		18		358
Acquisitions through business combinations		3		5,731		10		-		5,741
Items recognized through OCI
	Change in fair value			190		187		54		431
	Foreign exchange			1,114		21		51		1,186
Items recognized through net income
	Change in fair value			(17)		(10)		(9)		(36)
	Depreciation			(565)		(199)		(17)		(781)
As at December 31, 2016			$	21,569	$	3,313	$	375	$	25,257
Additions				253		95		6		354
Acquisitions through business combinations		3		-		618		627		1,245
Disposal		4		-		(338)		-		(338)
Items recognized through OCI
	Change in fair value			828		91		(32)		887
	Foreign exchange			332		177		(3)		506
Items recognized through net income
	Change in fair value			(20)		(8)		(5)		(33)
	Depreciation			(563)		(197)		(22)		(782)
As at December 31, 2017			$	22,399	$	3,751	$	946	$	27,096

• Includes solar, storage, biomass and Co-gen.
• Includes intangible assets of $13million (2016: $14 million and 2015: $13 million) and construction work in process (“CWIP”) of $601million (2016: $663 millionand 2015: $405 million).

The fair value of Brookfield Renewable’s property, plant and equipment is calculated as described in Notes1(f) -Property, plant and equipment and revaluation method and 1(n) - Critical estimates. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies – Property, plant and equipment.Brookfield Renewable has classified its property, plant and equipment under level 3 of the fair value hierarchy. 

Discount rates, terminal capitalization rates and exit dates used in the valuation methodology, are provided in the following table:

		North America		Colombia		Brazil		Europe
		2017	2016	2017	2016	2017	2016	2017	2016
Discount rate
	Contracted	4.9% - 6.0%	4.8% - 5.5%	11.3%	N/A	8.9%	9.2%	4.1% - 4.5%	4.1% - 5.0%
	Uncontracted	6.5% - 7.6%	6.6% - 7.2%	12.6%	N/A	10.2%	10.5%	5.9% - 6.3%	5.9% - 6.8%
Terminal
	capitalization rate(1)	6.2% - 7.5%	6.3% - 6.9%	0.126	N/A	N/A	N/A	NA	N/A
Exit date		2037	2036	2037	N/A	2032	2031	2031	2031

• Discount rates are not adjusted for asset specific risks.
• The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

The following table summarizes the impact of a change in discount rates, electricity prices and terminal capitalization rates on the fair value of property, plant and equipment:

	2017
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(710)	$	(130)	$	(50)	$	(20)	$	(910)
25 bps decrease in discount rates		770		130		50		20		970
5% increase in future electricity prices		620		310		70		20		1,020
5% decrease in future electricity prices		(620)		(310)		(70)		(20)		(1,020)
25 bps increase in terminal capitalization rate(1)		(180)		(50)		-		-		(230)
25 bps decrease in terminal capitalization rate(1)		190		50		-		-		240
	2016
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(670)	$	N/A	$	(50)	$	(20)	$	(740)
25 bps decrease in discount rates		730		N/A		50		20		800
5% increase in future electricity prices		540		N/A		70		20		630
5% decrease in future electricity prices		(540)		N/A		(70)		(20)		(630)
25 bps increase in terminal capitalization rate(1)		(180)		N/A		-		-		(180)
25 bps decrease in terminal capitalization rate(1)		190		N/A		-		-		190

The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

Terminal values are included in the valuation of hydroelectric assets in the United States, Canada and Colombia. For the hydroelectric assets in Brazil, cash flows have been included based on the duration of the authorization or useful life of a concession asset without consideration of potential renewal value. The weighted-average remaining duration of the authorization or useful life of a concession asset at December 31, 2017, is 15 years (2016:15 years). Consequently, there is no terminal value attributed to the hydroelectric assets in Brazil. If an additional 20 years of cash flows were included in Brazil, the fair value of property, plant and equipment would increase by approximately $1,500 million.

The following table summarizes the percentage of total generation contracted under power purchase agreements as at December 31, 2017:

	North America		Colombia		Brazil		Europe
1 - 10 years		58%		17%		66%		78%
11 - 20 years		42%		-		57%		35%

The following table summarizes power prices from long-term power purchase agreements that are linked specifically to the related power generating assets:

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	84	COP	211,000	R$	274	€	90
11 - 20 years		88		-		407		107

Assumes nominal prices based on weighted-average generation.

The following table summarizes the estimates of future electricity prices:

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	63	COP	238,000	R$	309	€	78
11 - 20 years		112		339,000		458		95

Assumes nominal prices based on weighted-average generation.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth between 2021 and 2025. A further one year change would increase or decrease the fair value of property, plant and equipment by approximately $160 million (2016: $130 million).

Had Brookfield Renewable’s revalued property, plant and equipment been measured on a historical cost basis, the carrying amounts, net of accumulated depreciation would have been as follows at December 31:

(MILLIONS)		2017		2016
Hydroelectric	$	12,740	$	12,761
Wind		3,030		2,688
Solar and other(1)		933		319
	$	16,703	$	15,768

Includes biomass and Co-gen.

XML

LONG-TERM DEBT AND CREDIT FACILITIES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

LONG-TERM DEBT AND CREDIT FACILITIES

13. LONG-TERM DEBT AND CREDIT FACILITIES

The composition of debt obligations as at December 31is presented in the following table:

		2017						2016
		Weighted-average				Estimated		Weighted-average				Estimated
		Interest	Term	Carrying		Fair		Interest	Term	Carrying		Fair
(MILLIONS EXCEPT AS NOTED)		rate (%)	(years)	value		value		rate (%)	(years)	value		value
Corporate borrowings
	Series 3 (C$200)	5.3	0.8	$	159	$	163	5.3	1.8	$	149	$	158
	Series 4 (C$150)	5.8	18.9		119		144	5.8	19.9		111		132
	Series 7 (C$450)	5.1	2.8		358		382	5.1	3.8		334		368
	Series 8 (C$400)	4.8	4.1		318		344	4.8	5.1		298		331
	Series 9 (C$400)	3.8	7.4		318		321	3.8	8.4		298		308
	Series 10 (C$500)	3.6	9.0		398		400	3.6	10.0		372		380
		4.5	6.4	$	1,670	$	1,754	4.5	7.4	$	1,562	$	1,677
Credit facilities		2.6	4.5	$	887	$	887	1.9	4.5	$	673	$	673
Subsidiary borrowings
	Hydroelectric	6.3	8.8	$	6,392		6,813	6.9	7.8	$	6,249		6,600
	Wind	5.8	9.7		2,211		2,343	4.6	13.1		1,735		1,879
	Solar and other	11.0	8.2		682		682	8.9	18.8		41		41
		6.5	9.0	$	9,285	$	9,838	6.4	9.0	$	8,025	$	8,520
Total debt					11,842		12,479				10,260		10,870
Add: Unamortized premiums(1)					1						2
Less: Unamortized financing fees(1)					(77)						(80)
Less: Current portion(2)(3)					(1,676)						(1,034)
				$	10,090					$	9,148

• Unamortized premiums and unamortized financing fees are amortized to interest expense over the terms of the borrowing
• As part of the TerraForm Global transaction, Brookfield Renewable acquired $841 million of borrowings that were immediately classified as current due to the change of control provision allowing the holders to direct TerraForm Global to redeem the bonds at 101% of par value in the first quarter of 2018. Brookfield Renewable redeemed these borrowings at approximately 107% of par value in the first quarter of 2018 with a combination of available cash on hand and proceeds from note offering that closed on February 22, 2018. See Note 20 – Cash and Cash Equivalents and Note 31 – Subsequent Events.
• As part of the TerraForm Global transaction, Brookfield Renewable acquired project level financings that were in default prior to the acquisition, had outstanding principal amounts totaling $342 million and mature in 2031. See Note 18 – Capital Management..

The following table outlines changes in Brookfield Renewable’s borrowings for the year ended December 31:

			Cash flows from		Non-cash
(MILLIONS)	Jan 1		financing activities		Acquisition		Disposal		Other(1)		Dec 31
2017	$	10,182	$	267	$	1,188	$	(173)	$	302	$	11,766
2016	$	7,338	$	1,502	$	1,104	$	-	$	238	$	10,182

Includes foreign exchange and amortization of unamortizedpremium and financing fees.

Future repayments of Brookfield Renewable’s debt obligations, for each of the next five years and thereafter are as follows:

(MILLIONS)		2018		2019		2020		2021		2022		Thereafter		Total
Corporate borrowings and
	credit facilities	$	159	$	202	$	377	$	-	$	984	$	835	$	2,557
Subsidiary borrowings
	Hydro		206		366		1,013		822		317		3,668		6,392
	Wind		665		115		122		125		132		1,052		2,211
	Solar and other		646		3		3		2		4		24		682
		$	1,676	$	686	$	1,515	$	949	$	1,437	$	5,579		11,842
Equity-accounted investments		$	110	$	116	$	112	$	716	$	602	$	3,003	$	4,659
														$	16,501

Subsidiary borrowings and corporate borrowings and credit facilities include $1 million and $77 million of unamortized premiums and deferred financing fees, respectively.

The following table outlines change in financing fees for the year ended December 31:

(MILLIONS)			2017		2016		2015
Corporate borrowings
	Unamortized financing fees, beginning of year	$	6	$	5	$	5
	Additional financing fees		-		2		1
	Amortization of financing fees		(1)		(1)		(1)
	Unamortized financing fees, end of year	$	5	$	6	$	5
Subsidiary borrowings
	Unamortized financing fees, beginning of year	$	74	$	54	$	66
	Additional financing fees		16		41		7
	Amortization of financing fees		(14)		(17)		(15)
	Foreign exchange translation and other		(4)		(4)		(4)
	Unamortized financing fees, end of year	$	72	$	74	$	54
Total		$	77	$	80	$	59

Corporate borrowings

Corporate borrowings are obligations of a finance subsidiary of Brookfield Renewable, Brookfield Renewable Partners ULC (“Finco”) (Note 30 - Subsidiary Public Issuers). Finco may redeem some or all of the borrowings from time to time, pursuant to the terms of the indenture. The balance is payable upon maturity, and interest on corporate borrowings is paid semi-annually.The term notes payable by Finco are unconditionally guaranteed by Brookfield Renewable, Brookfield Renewable Energy L.P. (“BRELP”) and certain other subsidiaries.

Our sole near time maturity is our C$200 million ($159 million) Series 3 medium-term notes which mature in November 2018.

Subsidiary borrowings

Subsidiary borrowings are typically asset-specific, long-term, non-recourse borrowings denominated in the domestic currency of the subsidiary. Subsidiary borrowings in North America, Europe and South Africa consist of both fixed and floating interest rate debt. Subsidiary borrowings in South Africa consist of floating interest rate debt indexed to the Johannesburg Interbank Agreed Rate (“JIBAR”) and U.S. dollar denominated debt indexed to the London Interbank Offered Rate (“LIBOR”). Brookfield Renewable uses interest rate swap agreements in North America, Europe and South Africa to minimize its exposure to floating interest rates. Subsidiary borrowings in Brazil consist of floating interest rates of Taxa de Juros de Longo Prazo (“TJLP”), the Brazil National Bank for Economic Development’s long-term interest rate, or Interbank Deposit Certificate rate (“CDI”), plus a margin. Subsidiary borrowings in Colombia include floating interest rates of Indicador Bancario de Referencia rate (“IBR”), the Banco Central de Colombia short-term interest rate, or Colombian Consumer Price Index (“IPC”), the Banco Central de Colombia inflation rate, plus a margin. Subsidiary borrowings in Malaysia consist of floating interest rate debt indexed to the Kuala Lumpur Interbank Offering Rate (“KLIBOR”). Subsidiary borrowings in India consist of fixed interest rate U.S. dollar denominated debt.

In March 2017, Brookfield Renewable completed the refinancing of a $60 million bank loan associated with a 417 MW hydroelectric facility in Pennsylvania. The loan bears interest at LIBOR plus a margin of 3.75% and matures in March 2022.

In May 2017, Brookfield Renewable completed the refinancing associated with a 44 MW hydroelectric portfolio in New England by issuing notes for $65 million. The notes carry a 4.86% coupon rate and mature in May 2027.

In June 2017, Brookfield Renewable completed the refinancing associated with a 11 MW wind asset in Arizona by securing a $11 million bank loan. The loan has been fully hedged for an all-in rate of 5.28% and matures in June 2024.

In June 2017, Brookfield Renewable completed the financing associated with a 17 MW hydroelectric facility in Quebec by issuing notes for C$55 million ($43 million). The notes bear an all-in rate of 4.49% and mature in May 2044.

In July 2017, Brookfield Renewable completed the refinancing of a 360 MW hydroelectric portfolio in New England. The financing was a $475 million green bond bearing interest at 4.4% with a maturity in July 2032.

In October 2017, Brookfield Renewable completed financing associated with a 47 MW portfolio of wind farms in Ireland by securing €78 million ($92 million) of long-term debt, €6 million ($8 million) working capital facility and €4 million ($4 million) debt reserve facility. The long-term debt matures in 2032 and bears interest at EURIBOR plus a margin of 1.5%.

In December 2017, Brookfield Renewable completed a $305 million refinancing, associated with an 872 MW portfolio of hydroelectric facilities in New York at an all-in interest rate of 4.29% and with a maturity in December 2030.

In December 2017, Brookfield Renewable completed a £17 million ($22 million) non-recourse financing associated with a 16 MW wind asset in Northern Ireland. The long-term debt matures in 2035 and bears interest at GBP LIBOR plus a margin of 2.20%.

In December 2017, Brookfield Renewable completed R$166 million ($50 million) of financing with respect to a 28 MW hydroelectric facility currently under construction in Brazil. The loan bears interest at a rate of TJLP plus 2.12% and matures in 2038.

Credit facilities

In June 2017, Brookfield Renewable extended the maturity of $1,600 million of its corporate credit facilities by one year to June 30, 2022. The applicable margin is 1.20%. The credit facilities are used for general working capital purposes and issuing letters of credit. The credit facilities bear interest at the applicable banker’s acceptance rate, LIBOR or EURIBOR plus an applicable margin. The applicable margin is tiered on the basis of Brookfield Renewable’s unsecured long-term debt rating.

During the first quarter of 2017, the committed unsecured revolving credit facility provided by Brookfield Asset Management was increased to $400 million. During the fourth quarter of 2017, Brookfield Renewable extended the maturityby one year toDecember 2018. Interest rate applicable on the draws is LIBOR plus 2%.

Brookfield Renewable and its subsidiaries issue letters of credit from some of their credit facilities for general corporate purposes which include, but are not limited to, security deposits, performance bonds and guarantees for debt service reserve accounts.

The following table summarizes the available portion of credit facilities as at December 31:

(MILLIONS)		2017		2016
Authorized credit facilities	$	2,090	$	1,890
Draws on credit facilities(1)		(685)		(673)
Issued letters of credit		(193)		(250)
Available portion of credit facilities	$	1,212	$	967

XML

NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

NON-CONTROLLING INTERESTS

14. NON-CONTROLLING INTERESTS

Brookfield Renewable’s non-controlling interestsare comprised of the following as at December 31:

(MILLIONS)			2017		2016
Participating non-controlling interests - in operating subsidiaries		$	6,298	$	5,589
General partnership interest in a holding subsidiary held by Brookfield			58		55
Participating non-controlling interests - in a holding subsidiary -
	Redeemable/Exchangeable units held by Brookfield		2,843		2,680
Preferred equity			616		576
		$	9,815	$	8,900

Participating non-controlling interests – in operating subsidiaries

The net change in participating non-controlling interests – in operating subsidiaries is as follows:

												Isagen
		Brookfield								Isagen		public
		Americas		Brookfield		Brookfield			The	institu-		non-con
	Infrastructure			Infrastructure		Infrastructure		Catalyst		tional		-trolling
(MILLIONS)		Fund		Fund II		Fund III		Group		investors		interests		Other		Total
As at December 31, 2014		$	914	$	937	$	-	$	126	$	-	$	-	$	85	$	2,062
Net income			26		27		-		14		-		-		2		69
OCI			89		144		-		(12)		-		-		(17)		204
Capital contributions			-		460		-		-		-		-		-		460
Distributions			(70)		(126)		-		(7)		-		-		(5)		(208)
Other			(1)		(1)		-		-		-		-		2		-
As at December 31, 2015		$	958	$	1,441	$	-	$	121	$	-	$	-	$	67	$	2,587
Net (loss) income			(18)		(16)		15		16		47		19		2		65
OCI			46		228		-		2		148		205		6		635
Capital contributions			-		74		1,074		-		1,473		-		-		2,621
Acquisition			-		-		-		-		-		1,417		-		1,417
Distributions			(23)		(73)		(7)		(12)		-		-		(4)		(119)
MTO adjustments			-		-		3		-		7		(1,627)		-		(1,617)
As at December 31, 2016		$	963	$	1,654	$	1,085	$	127	$	1,675	$	14	$	71	$	5,589
Net (loss) income			(29)		(13)		33		12		47		-		3		53
OCI			(76)		269		111		2		78		(1)		-		383
Capital contributions			-		89		186		-		19		-		-		294
Acquisition			-		-		525		-		-		-		-		525
Distributions			(8)		(317)		(88)		(7)		(115)		-		(4)		(539)
Purchase of Isagen shares			-		-		(1)		-		(5)		5		-		(1)
Other			-		-		1		-		2		(9)		-		(6)
As at December 31, 2017		$	850	$	1,682	$	1,852	$	134	$	1,701	$	9	$	70	$	6,298
Interests held by third parties			75-80%		50-60%		23-71%		25%		53%		0.5%	21-50%

The privatization of the Isagen portfolio was completed on March 31, 2017 and its shares weredelistedfrom the Colombia Stock Exchange. During the year ended December 31, 2017, Brookfield Renewable, together with its co-investors, acquired an additional 3,358,523 shares in Isagen. In accordance with IFRS 10, Consolidated Financial Statements, Brookfield Renewable is accounting for the additional interests in Isagen purchased subsequent to the initial investments as equity transactions related to the acquisition of non-controlling interest. As at December 31, 2017 Brookfield Renewable together with its co-investors owns approximately 99.5% interest in Isagen. The remaining approximately 0.5% ownership interest not held by Brookfield Renewable and itsco-investors remains as non-controlling interest.

The following tables summarize certain financial information of operating subsidiaries that have non-controlling interests that are material to Brookfield Renewable:

		Brookfield
		Americas		Brookfield		Brookfield
		Infrastructure		Infrastructure		Infrastructure		The Catalyst
(MILLIONS)		Fund		Fund II		Fund III(1)		Group		Isagen(2)		Other		Total
Interests held by third parties			75-80%		50-60%		69-71%		25%		76%		21-50%
Place of business		United States,Brazil		United States,Brazil,Europe		United States, Brazil, India, China, South Africa		United States		Colombia		United States,Brazil,Canada
For the year ended
	December 31, 2015:
Revenue		$	136	$	402	$	-	$	160	$	-	$	30	$	728
Net income			34		49		-		56		-		8		147
Total comprehensive
	income (loss)		144		247		-		8		-		(51)		348
Net income allocated to
	non-controlling interests		26		27		-		14		-		2		69
For the year ended
	December 31, 2016:
Revenue		$	118	$	394	$	28	$	164	$	819	$	27	$	1,550
Net (loss) income			(22)		(23)		(8)		62		110		5		124
Total comprehensive
	income (loss)		37		356		(8)		70		502		31		988
Net (loss) income allocated to
	non-controlling interests		(18)		(16)		(5)		16		86		2		65
As at December 31, 2016:
Property, plant and
	equipment, at fair value	$	1,807	$	4,816	$	848	$	970	$	5,275	$	417	$	14,133
Total assets			1,865		5,125		855		1,072		6,539		428		15,884
Total borrowings			571		1,881		313		450		1,924		41		5,180
Total liabilities			631		2,235		319		466		3,396		60		7,107
Carrying value of non-
	controlling interests	$	963	$	1,654	$	383	$	127	$	2,391	$	71	$	5,589
For the year ended
	December 31, 2017:
Revenue		$	123	$	430	$	53	$	135	$	797	$	32	$	1,570
Net (loss) income			(34)		(20)		18		47		89		7		107
Total comprehensive
	(loss) income		(133)		529		126		57		236		-		815
Net (loss) income allocated
	to non-controlling interests		(29)		(13)		13		12		67		3		53
As at December 31, 2017:
Property, plant and
	equipment, at fair value	$	1,667	$	5,153	$	2,149	$	964	$	5,401	$	411	$	15,745
Total assets			1,718		5,430		3,294		1,066		6,526		426		18,460
Total borrowings			556		2,040		1,502		413		1,858		42		6,411
Total liabilities			628		2,422		1,678		432		3,336		63		8,559
Carrying value of non-
	controlling interests	$	850	$	1,682	$	1,138	$	134	$	2,424	$	70	$	6,298

• Excludes information relating to Isagen which is presented separately.
• The total third parties ownership interest in Isagen as of December 31, 2017 was 75.9% and comprised of Brookfield Infrastructure Fund III: 22.9%, Isagen Institutional investors 52.5% and Isagen public non-controlling interests: 0.5%.

General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests – in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield

Brookfield, as the owner of the 1% general partnership interest in BRELP held by Brookfield (“GP interest”), is entitled to regular distributions plus an incentive distribution based on the amount by which quarterly distributions exceed specified target levels. To the extent that LP Unit distributions exceed $0.375 per LP Unit per quarter, the incentive is 15% of distributions above this threshold. To the extent that quarterly LP Unit distributions exceed $0.4225 per LP Unit, the incentive distribution is equal to 25% of distributions above this threshold.

Consolidated equity includes Redeemable/Exchangeable partnership units and the GP interest. The Redeemable/Exchangeable partnership units are held 100% by Brookfield, which at its discretion has the right to redeem these units for cash consideration. No Redeemable/Exchangeable partnership units have been redeemed for cash consideration. Since this redemption right is subject to Brookfield Renewable’s right, at its sole discretion, to satisfy the redemption request with LP Units of Brookfield Renewable on a one for one basis, the Redeemable/Exchangeable partnership units are classified as equity in accordance with IAS 32, Financial Instruments: Presentation. The Redeemable/Exchangeable partnership units and GP interest are presented as non-controlling interests since they provide Brookfield the direct economic benefits and exposures to the underlying performance of BRELP. The LP Units issued by Brookfield Renewable and the Redeemable/Exchangeable partnership units issued by its subsidiary BRELP have the same economic attributes in all respects, except for the redemption right described above. The Redeemable/Exchangeable partnership units and the GP interest participate in earnings and distributions on a per unit basis equivalent to the per unit participation of the LP Units of Brookfield Renewable.

As at December 31, 2017, general partnership units, and Redeemable/Exchangeable partnership units outstanding were 2,651,506 (December 31, 2016: 2,651,506) and 129,658,623 (December 31, 2016: 129,658,623), respectively.

Distributions

The composition of the distributions for the year ended December 31 is presented in the following table:

(MILLIONS)			2017		2016
General partnership interest in a holding
	subsidiary held by Brookfield	$	5	$	5
Incentive distribution			30		19
		$	35	$	24
Participating non-controlling interests - in a
	holding subsidiary - Redeemable/
	Exchangeable units held by Brookfield	$	243	$	232
		$	278	$	256

The following table summarizes certain financial information regarding General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests – in a holding subsidiary – Redeemable/Exchangeable units held by Brookfield:

(MILLIONS)		2017		2016		2015
For the year ended December 31:
Revenue		$	2,625	$	2,452	$	1,628
Net income			51		40		103
Comprehensive income			1,401		1,369		5
Net income allocated to(1):
	GP interest		(1)		-		-
	Redeemable/Exchangeable partnership units		(23)		(29)		1
As at December 31:
Property, plant and equipment, at fair value		$	27,096	$	25,257
Total assets			30,904		27,737
Total borrowings			11,766		10,182
Total liabilities			16,622		15,065
Carrying value of(2):
	GP interest		58		55
	Redeemable/Exchangeable partnership units		2,843		2,680

• Allocated based on weighted-average GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 173.5 million, respectively (2016: 2.7 million, 129.7 million, and 156.4 million, respectively and 2015: 2.7 million, 129.7 million, and 143.3million, respectively).
• Allocated based on outstanding GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 180.4million, respectively (2016: 2.7 million, 129.7 million, and 166.8million, respectively).

Preferred equity

Brookfield Renewable’s preferred equity as at December 31 consists of Class A Preference Shares of Brookfield Renewable Power Preferred Equity Inc. (“BRP Equity”) as follows:

			Earliest	Dividends declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	dividend	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 1 (C$136)	5.45	3.36	Apr 30, 2020	$	4	$	3	$	108	$	101
Series 2 (C$113)(1)	4.51	3.63	Apr 30, 2020		3		3		90		84
Series 3 (C$249)	9.96	4.40	Jul 31, 2019		8		8		197		185
Series 5 (C$103)	4.11	5.00	Apr 30, 2018		4		4		82		76
Series 6 (C$175)	7.00	5.00	Jul 31, 2018		7		7		139		130
	31.03			$	26	$	25	$	616	$	576

Dividend rate represents annualized distribution based on the most recent quarterly floating rate.

The Class A Preference Shares do not have a fixed maturity date and are not redeemable at the option of the holders. As at December 31, 2017, none of the issued Class A Preference Shares have been redeemed by BRP Equity.

Class A Preference Shares – Normal Course Issuer Bid

In June 2017, the TSX accepted notice of BRP Equity’s intention to renew the normal course issuer bid in connection with its outstanding Class A Preference Shares for another year to June 26, 2018, or earlier should the repurchases be completed prior to such date. Under this normal course issuer bid, it is permitted to repurchase up to 10% of the total public float for each respective series of our Class A Preference Shares.

XML

PREFERRED LIMITED PARTNERS EQUITY

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

PREFERRED LIMITED PARTNERS EQUITY

15. PREFERRED LIMITED PARTNERS’ EQUITY

Brookfield Renewable’s preferred limited partners’ equity comprises of Class A Preferred LP Units as follows:

			Earliest	Distributions declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	distribution	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 5 (C$72)	2.89	5.59	Apr 30, 2018	$	4	$	3	$	49	$	49
Series 7 (C$175)	7.00	5.50	Jan 31, 2021		8		7		128		128
Series 9 (C$200)	8.00	5.75	Jul 31, 2021		8		5		147		147
Series 11 (C$250)	10.00	5.00	Apr 30, 2022		8		-		187		-
	27.89			$	28	$	15	$	511	$	324

On February 14, 2017, Brookfield Renewable issued 10,000,000 Class A, Series 11 Preferred Limited Partnership Units (the “Series 11 Preferred Units”) at a price of C$25 per unit for gross proceeds of C$250 million ($190 million). The holders of the Series 11 Preferred Units are entitled to receive a cumulative quarterly fixed distribution yielding 5.0% for the initial period ending April 30, 2022. Thereafter, the distribution rate will be reset every five years at a rate equal to the greater of: (i) the 5-year Government of Canada bond yield plus 3.82%, and (ii) 5.00%.

The holders of Series 11 Preferred Units will have the right, at their option, to convert their Series 11 Preferred Units intoClass A Preferred Limited Partnership Units, Series 12 (the “Series 12 Preferred Units”), subject to certainconditions, on April 30, 2022 and on April 30 every five years thereafter. The holders of Series 12 Preferred Units will be entitled to receive floating ratecumulative preferential cash distributions equal to the sum of the 90-day Canadian Treasury Bill Rate plus 3.82%.

XML

LIMITED PARTNERS EQUITY

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

LIMITED PARTNERS EQUITY

(MILLIONS)		2017		2016
Brookfield	$	101	$	83
External LP Unitholders		227		198
	$	328	$	281

In February 2017, unitholder distributions were increased to $1.87 per LP Unit on an annualized basis, an increase of nine cents per LP Unit, which took effect with the distribution payable in March 2017.

XML

GOODWILL

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

GOODWILL

17. GOODWILL

The following table provides a reconciliation of goodwill:

(MILLIONS)	2017		2016
Balance, beginning of year	$	896	$	-
Acquired through business acquisition		-		799
Foreign exchange		5		97
Balance, end of year	$	901	$	896

XML

CAPITAL MANAGEMENT

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

CAPITAL MANAGEMENT

18. CAPITAL MANAGEMENT

Brookfield Renewable’s primary capital management objectives are to ensure the sustainability of its capital to support continuing operations, meet its financial obligations, allow for growth opportunities and provide stable distributions to its LP Unitholders. Brookfield Renewable’s capital is monitored through debt to total capitalization ratio which is calculated as total debt plus deferred income tax liabilities, net of deferred income tax assets, and equity. The ratio as at December 31, 2017 was 40% (2016: 38%).

Brookfield Renewable has provided covenants to certain of its lenders for its corporate borrowings and credit facilities. The covenants require Brookfield Renewable to meet minimum debt to capitalization ratios. Subsidiaries of Brookfield Renewable have provided covenants to certain of their lenders for their property-specific borrowings. These covenants vary from one credit agreement to another and include ratios that address debt service coverage. Certain lenders have also put in place requirements that oblige Brookfield Renewable and its subsidiaries to maintain debt and capital expenditure reserve accounts. The consequences to the subsidiaries as a result of failure to comply with their covenants could include a limitation of distributions from the subsidiaries to Brookfield Renewable, as well as repayment of outstanding debt. Brookfield Renewable is dependent on the distributions made by its subsidiaries to service its debt.

As part of the TerraForm Global transaction, Brookfield Renewable acquired assets with project level financings that were in default prior to the acquisition, had outstanding principal amounts totaling $342 million and mature in 2031. As at December 31, 2017, the loans were not in compliance with certain covenants due to the SunEdison Bankruptcy, as well as issues with contractors under the engineering, procurement and construction contract. The loan balances have been classified as current as at December 31, 2017. Brookfield Renewable is currently working with all the lenders to cure such defaults and release the restrictions placed on the projects. Except for the aforementioned defaults, Brookfield Renewable complied with all material financial covenants as of December 31, 2017.

Brookfield Renewable’s strategy during 2017, which was unchanged from 2016, was to maintain the measure set out in the following schedule as at December 31:

(MILLIONS)			2017		2016
Total debt
	Current portion of long-term debt(1)	$	1,676	$	1,034
	Long-term debt and credit facilities		10,090		9,148
			11,766		10,182
Deferred income tax liabilities, net(2)			3,411		3,652
Equity			14,282		12,672
Total capitalization		$	29,459	$	26,506
Debt to total capitalization			40%		38%

^[1]

[1] As part of the TerraForm Global transaction, Brookfield Renewable acquired $ 841 million of borrowings that were immediately classified as current due to the change of control provision allowing the holders to direct TerraForm Global to redeem the bonds at 101 % of par value in the first quarter of 2018. Brookfield Renewable redeemed these borrowings at approximately 107 % of par value in the first quarter of 2018 with a combination of available cash on hand and proceeds from note offering th at closed on February 22, 2018. See Note 20 – Cash and Cash Equivalents and Note 31 – Subsequent Events Deferred income tax liabilities less deferred income tax assets.

XML

EQUITY-ACCOUNTED INVESTMENTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

EQUITY-ACCOUNTED INVESTMENTS

19. EQUITY-ACCOUNTED INVESTMENTS

The following are Brookfield Renewable’s equity-accounted investments as at December 31:

	Principal place	Ownership	Carrying value
	of business	interest
(MILLIONS)		%		2017		2016
FHH (Guernsey) Limited	Europe	25	$	245	$	-
TerraForm Power Inc.(1)	United States,Canada	16		212		-
Bear Swamp Power Co. L.L.C.	United States	50		173		114
Galera Centrais Eletricas S.A.	Brazil	50		28		29
Pingston Power Inc.	Canada	50		57		58
Brookfield Infrastructure Fund II Investees	United States,Europe	14 - 50		6		5
			$	721	$	206

The following table outlines the changes in Brookfield Renewable’s equity-accounted investments for the year ended December 31:

(MILLIONS)		2017		2016		2015
Balance, beginning of year		$	206	$	197	$	273
Share of net income			2		-		10
Share of OCI
	Revaluation of property, plant and equipment		54		7		96
	Other		2		1		-
Dividends declared			(31)		(6)		(19)
Capital distributions, net			-		-		(144)
Acquisition of European Storage (Note 3)			248		-		-
Acquisition of TerraForm Power (Note 3)			221		-		-
Foreign exchange translation			19		7		(19)
Balance, end of year		$	721	$	206	$	197

The following tables summarize certain financial information of equity-accounted investments:

(MILLIONS)					2017		2016
As at December 31:
Current assets				$	477	$	45
Property, plant and equipment, at fair value					8,098		864
Other assets					213		70
Current liabilities					687		42
Long-term debt					4,294		463
Other liabilities					958		71
(MILLIONS)			2017		2016		2015
For the year ended December 31
Revenue		$	310	$	74	$	89
Net (loss) income			(24)		-		19
Share of net income (loss)
	Cash earnings		29		9		20
	Non-cash loss		(27)		(9)		(10)

XML

CASH AND CASH EQUIVALENTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

CASH AND CASH EQUIVALENTS

20. CASH AND CASH EQUIVALENTS

Brookfield Renewable’s cash and cash equivalents as at December 31 are as follows:

Cash(1)	$	790	$	210
Short-term deposits		9		13
	$	799	$	223

XML

RESTRICTED CASH

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

RESTRICTED CASH

21. RESTRICTED CASH

Brookfield Renewable’s restricted cash as at December 31is as follows:

(MILLIONS)	Note		2017		2016
Operations		$	195	$	135
Credit obligations			85		104
Development projects			4		11
Total			284		250
Less: non-current	23		(103)		(129)
Current		$	181	$	121

XML

TRADE RECEIVABLES AND OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

TRADE RECEIVABLES AND OTHER CURRENT ASSETS

22. TRADE RECEIVABLES AND OTHER CURRENT ASSETS

Brookfield Renewable’s trade receivables and other current assets as at December 31are as follows:

(MILLIONS)		2017		2016
Trade receivables	$	360	$	262
Other short-term receivables		82		103
Prepaids and others		112		89
	$	554	$	454

As at December 31, 2017, 99% (2016: 95%) of trade receivables were current. Trade receivables are generally on 30-day terms and credit limits are assigned and monitored for all counterparties. In determining the recoverability of trade receivables, management performs a risk analysis considering the type and age of the outstanding receivables and the credit worthiness of the counterparties. Management also reviews trade receivable balances on an ongoing basis. Bad debt expense related to trade receivables is recognized at the time an account is deemed uncollectible. Accordingly, as at December 31, 2017 and 2016 an allowance for doubtful accounts for trade receivables was not deemed necessary.

XML

OTHER LONG-TERM ASSETS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

OTHER LONG-TERM ASSETS

23. OTHER LONG-TERM ASSETS

The composition of Brookfield Renewable’s other long-term assets as at December 31 is presented in the following table:

			Accumulated
		Cost	Amortization		Net Book Value		Net book value
(MILLIONS)	2017							2016
Restricted cash	$	103	$	-	$	103	$	129
Unamortized financing fees		32		(27)		5		6
Acquisition downpayment		46		-		46		-
Other		82		(6)		76		41
	$	263	$	(33)	$	230	$	176

At December 31, 2017 and 2016, restricted cash was held primarily to satisfy lease payments and credit agreements.

XML

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Brookfield Renewable’s accounts payable and accrued liabilities as at December 31are as follows:

(MILLIONS)			2017		2016
Operating accrued liabilities		$	271	$	147
Accounts payable			117		87
Interest payable on corporate and subsidiary borrowings			64		68
Deferred consideration			35		55
Acquisition related provisions			-		54
LP Unitholders’ distributions, preferred limited partnership unit
	distributions and preferred dividends payable(1)		29		24
Other			26		32
		$	542	$	467

^[1]

[1] Includes amounts payable only to external LP Unitholders. Amounts payable to Brookfield are included in due to related parties.

XML

OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

OTHER LONG-TERM LIABILITIES

25. OTHER LONG-TERM LIABILITIES

Brookfield Renewable’s other long-term liabilities as at December 31 are comprised of the following:

(MILLIONS)	Notes	2017			2016
Acquisition related provisions		$	80	$	111
Pension obligations	29		89		87
Decommissioning retirement obligations			85		47
Contingent consideration	3		18		16
Commitments for power purchase agreements			13		-
Concession payment liability			9		10
Deferred revenue			9		7
Other			41		32
		$	344	$	310

Brookfield Renewable has recorded decommissioning retirement obligations associated with certain power generating assets. The decommissioning retirement obligation has been established for hydroelectric and wind operation sites in North America that are expected to be restored between the years 2031 to 2138. The estimated cost of decommissioning activities is based on a third party assessment.

XML

COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

26. COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

In the course of its operations, Brookfield Renewable and its subsidiaries have entered into agreements for the use of water, land and dams. Payment under those agreements varies with the amount of power generated. The various agreements can be renewed and are extendable up to 2091.

The remaining development project costs on two Brazilian hydroelectric projects totaling 47 MW and one28 MW wind project in Europe are expected to be $44million. All three projects are expected to be fully operational in 2018.

As at December 31, 2017, Brookfield Renewable had commitments for future minimum lease payments under non-cancellable leases which fall due as follows:

(MILLIONS)
2018	$	33
2019		32
2020		31
2021		30
2022		27
Thereafter		262
Total	$	415

Contingencies

Brookfield Renewable and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on Brookfield Renewable’s consolidated financial position or results of operations.

Brookfield Renewable, on behalf of Brookfield Renewable’s subsidiaries, and the subsidiaries themselves have provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance. The activity on the issued letters of credit by Brookfield Renewable can be found in Note 13 – Long-term debt and credit facilities.

Brookfield Renewable along with institutional investors has provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance as it relates to interests in the Brookfield Americas Infrastructure Fund and the Brookfield Infrastructure Fund II. Brookfield Renewable’s subsidiaries have similarly provided letters of credit, which include, but are not limited to, guarantees for debt service reserves, capital reserves, construction completion and performance.

As at December 31, letters of credit issued by Brookfield Renewable along with institutional investorsand its subsidiaries were as follows:

(MILLIONS)		2017	2016
Brookfield Renewable along with institutional investors	$	76	$	66
Brookfield Renewable's subsidiaries		468		483
	$	544	$	549

Guarantees

In the normal course of operations, Brookfield Renewable and its subsidiaries execute agreements that provide for indemnification and guarantees to third parties of transactions such as business dispositions, capital project purchases, business acquisitions, and sales and purchases of assets and services. Brookfield Renewable has also agreed to indemnify its directors and certain of its officers and employees. The nature of substantially all of the indemnification undertakings prevents Brookfield Renewable from making a reasonable estimate of the maximum potential amount that Brookfield Renewable could be required to pay third parties as the agreements do not always specify a maximum amount and the amounts are dependent upon the outcome of future contingent events, the nature and likelihood of which cannot be determined at this time. Historically, neither Brookfield Renewable nor its subsidiaries have made material payments under such indemnification agreements.

XML

RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

RELATED PARTY TRANSACTIONS

27. RELATEDPARTYTRANSACTIONS

Brookfield Renewable’s related party transactions are recorded at the exchange amount. Brookfield Renewable’s related party transactions are primarily with Brookfield.

Brookfield Renewable and Brookfield have entered into, or amended, the following material agreements:

Principal Agreements

Limited Partnership Agreements

Each of the amended and restated limited partnership agreements of Brookfield Renewable and BRELP outline the key terms of the partnerships, including provisions relating to management, protections for limited partners, capital contributions, distributions and allocation of income and losses. BRELP’s general partner is entitled to receive incentive distributions from BRELP as a result of its ownership of the general partnership interest in BRELP. The incentive distributions are to be calculated in increments based on the amount by which quarterly distributions on the limited partnership units of BRELP exceed specified target levels as set forth in the amended and restated partnership agreement.

Master Services Agreement

Brookfield Renewable entered into an agreement with Brookfield Asset Management pursuant to which Brookfield Asset Management has agreed to provide oversight of the business and provide the services of senior officers to Brookfield Renewable for a management service fee. The fee is paid on a quarterly basis and has a fixed quarterly component of $5 million and a variable component calculated as a percentage of the increase in the total capitalization value of Brookfield Renewable over an initial reference value (subject to an annual escalation by a specified inflation factor beginning on January 1, 2013). Total capitalization value as of December 31, 2017 is $14billion, which against the initial reference value of $8 billion and factoring in the annual amount of $21 million (as adjusted for inflation), resulted in a management service fee payment for the year ended December 31, 2017 of $82million (2016: $62 million and 2015: $48 million).

BRELP Voting Agreement

In 2011, Brookfield Renewable entered into a voting agreement with Brookfield pursuant to which Brookfield Renewable, through BRPL, has a number of voting rights, including the right to direct all eligible votes in the election of the directors of BRELP’s general partner.

Revenue Agreements

Contract Amendments

In 2011, two long-term power purchase agreements associated with the generating assets in Ontario held by Great Lakes Power Limited (“GLPL”) and Mississagi Power Trust (“MPT”), were amended.

The amended GLPL power purchase agreement requires Brookfield to support the price that GLPL receives for energy generated by certain facilities in Canada at a price of C$82 per MWh subject to an annual adjustment equal to 40% of the Consumer Price Index (“CPI”) in the previous year. The GLPL agreement has an initial term to 2029, and the contract automatically renews for successive 20-year periods with certain termination provisions. If the contract is not terminated prior to 2029, the price under this agreement reverts back to the original C$68 per MWh subject to an annual adjustment equal to 40% of the CPI for each year.

The amended MPT power purchase agreement requires Brookfield to purchase the energy generated at a price of C$103 per MWh subject to an annual adjustment equal to 20% of the CPI in the previous year. The MPT contract terminates on December 1, 2029 and MPT has been granted the unilateral option to terminate the agreement, on 120 days written notice, at certain times between 2017 and 2024.

Energy Revenue Agreement

In 2011, an agreement was entered into between Brookfield and Brookfield Power U.S. Holdings America Co. (“BPUSHA”) that indirectly owns substantially all of the U.S. facilities of Brookfield Renewable. Brookfield will support the price that BPUSHA receives for energy generated by certain facilities in the United States at a price $75 per MWh. This price is to be increased annually on January 1 by an amount equal to 40% of the increase in the CPI during the previous calendar year, but not exceeding an increase of 3% in any calendar year. This agreement will have an initial term of 20 years, with automatic renewals for successive 20-year periods with certain termination provisions.

Other Revenue Agreements

Pursuant to a 20-year power purchase agreement, Brookfield purchases all energy from several power facilities in Maine and New Hampshire held by Great Lakes Holding America (“GLHA”) at $37 per MWh. The energy rates are subject to an annual adjustment equal to 20% of the increase in the CPI during the previous year.

Pursuant to a 20-year power purchase agreement, Brookfield purchases all energy from Lievre Power in Quebec at C$68 per MWh. The energy rates are subject to an annual adjustment equal to the lesser of 40% of the increase in the CPI during the previous calendar year or 3%.

Pursuant to a power guarantee agreement, Brookfield will purchase all energy from the two facilities of Hydro Pontiac Inc. at a price of C$68 per MWh, to be increased annually each calendar year beginning in 2010 by an amount equal to 40% of the increase in the CPI during the previous calendar year. This power guarantee agreement is scheduled to commence in 2019 for one facility and in 2020 for the other, upon the expiration of existing third-party power agreements. The agreement with Brookfield has an initial term to 2029 and automatically renews for successive 20-year period with certain termination provisions.

Pursuant to a 10-year Wind Levelization agreement expiring in 2019, Brookfield mitigates any potential wind variation from the expected annual generation of 506 GWh with regards to the Prince Wind assets in Ontario. Any excess generation compared to the expected generation results in a payment from Brookfield Renewable to Brookfield, while a shortfall would result in a payment from Brookfield to Brookfield Renewable.

Power Services Agreements

Power Agency Agreements

Certain Brookfield Renewable subsidiaries have entered into Power Agency Agreements appointing Brookfield as their exclusive agent in respect of the sales of electricity, including the procurement of transmission and other additional services. In addition, Brookfield will schedule, dispatch and arrange for transmission of the power produced and the power supplied to third-parties in accordance with prudent industry practice. Pursuant to each Agreement, Brookfield will be entitled to be reimbursed for any third-party costs incurred, and, in certain cases, receives an additional fee for its services in connection with the sale of power and for providing the other services.

Energy Marketing Agreement

Brookfield has agreed to provide energy marketing services to Brookfield Renewable’s North American businesses. Under this Agreement, Brookfield Renewable pays an annual energy marketing fee of $18 million per year (subject to increase by a specified inflation factor beginning on January 1, 2013). See Note 8 - Direct operating costs.

Voting Agreements

Brookfield Renewable entered into voting agreements with Brookfield whereby Brookfield, as managing member of entities related to the Brookfield Americas Infrastructure Fund (the “BAIF Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, agreed to assign to Brookfield Renewable their voting rights to elect the Boards of Directors of the BAIF Entities. Brookfield Renewable’s economic interests in the BAIF Entities in the United States and Brazil are 22% and 25%, respectively.

Brookfield Renewable entered into voting agreements with certain Brookfield subsidiaries whereby these subsidiaries, as managing members of entities related to Brookfield Infrastructure Fund II (the “BIF II Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, agreed to provide to Brookfield Renewable the authority to direct the election of the Boards of Directors of the BIF II Entities. Brookfield Renewable’s economic interests in the BIF II Entities are between 40% and 50.1%.

Except as set out below in respect to TerraForm Power and Isagen, Brookfield Renewable entered into a voting agreement with certain Brookfield subsidiaries that form part of Brookfield Infrastructure Fund III (the “BIF III Entities”) in which Brookfield Renewable holds investments in power generating operations with institutional investors, Brookfield agreed to provide to Brookfield Renewable the authority to direct the election of the Boards of Directors of the BIF III Entities. Brookfield Renewable’s economic interests in the BIF III Entities are between 24% and 31%.

The consortium holds its interest in Isagen through an entity (“Hydro Holdings”) which is entitled to appoint a majority of the board of directors of Isagen.  The general partner of Hydro Holdings is a controlled subsidiary of Brookfield Renewable.  Brookfield Renewable is entitled to appoint a majority of Hydro Holdings’ board of directors, provided that Brookfield Asset Management and its subsidiaries (including Brookfield Renewable) collectively are (i) the largest holder of Hydro Holdings’ limited partnership interests, and (ii) hold over 30% of Hydro Holdings’ limited partnership interests (the “Ownership Test”).  Brookfield Asset Management and its subsidiaries currently meet the Ownership Test.

Brookfield Renewable entered into a voting agreement with the Brookfield subsidiary that ultimately controls TerraForm Power. Pursuant to this voting agreement, Brookfield Renewable is entitled to direct the election of one of the four directors of the Brookfield subsidiary, thereby providing Brookfield Renewable with significant influence over this subsidiary.

Brookfield Asset Management has provided a $400 million committed unsecured revolving credit facility maturing in December 2018. See Note 13 – Long-term debt and credit facilities for further details. Brookfield Asset Management had also placed funds on deposit with Brookfield Renewable in the amount of $140 million during the first quarter of the current year, which was repaid prior to the end of the first quarter. The interest expense on the draws from the credit facility and the deposit totaled $1 million.

In 2011, on formation of Brookfield Renewable, Brookfield Asset Management transferred certain development projects to Brookfield Renewable for no upfront consideration but is entitled to receive variable consideration on commercial operation or sale of these projects.An amount of $8 million has been paid relating to the commissioning of a 25 MW hydroelectric facility in Brazil.

The following table reflects the related party agreements and transactions in the consolidated statements of income, for the year ended December 31:

(MILLIONS)			2017		2016		2015
Revenues
	Power purchase and revenue agreements	$	601	$	527	$	469
	Wind levelization agreement		6		8		6
		$	607	$	535	$	475
Direct operating costs
	Energy purchases	$	(13)	$	(3)	$	(5)
	Energy marketing fee		(24)		(23)		(22)
	Insurance services		(19)		(20)		(30)
		$	(56)	$	(46)	$	(57)
Management service costs		$	(82)	$	(62)	$	(48)

The following table reflects the impact of the related party agreements and transactions on the consolidated statements of financial position as at December 31:

(MILLIONS)			Related party		2017		2016
Current assets
Due from related parties
	Amounts due from		Brookfield	$	54	$	47
			Equity-accounted investments and other		6		7
				$	60	$	54
Current liabilities
Due to related parties
	Amount due to		Brookfield	$	48	$	48
	Accrued distributions payable on LP
		Units and Redeemable/Exchangeable
		partnership units	Brookfield		32		26
	Amount due to		Equity-accounted investments and other		32		2
				$	112	$	76

Current assets

Amounts due from Brookfield are non-interest bearing, unsecured and due on demand.

Current liabilities

Amounts due to Brookfield are unsecured, payable on demand and relate to recurring transactions.

XML

SUPPLEMENTAL INFORMATION

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

SUPPLEMENTAL INFORMATION

28. SUPPLEMENTAL INFORMATION

The net change in working capital balances for the year ended December 31 shown in the consolidated statements of cash flows is comprised of the following:

(MILLIONS)		2017		2016		2015
Trade receivables and other current assets	$	(40)	$	30	$	(72)
Accounts payable and accrued liabilities		32		(160)		2
Other assets and liabilities		(17)		(7)		8
	$	(25)	$	(137)	$	(62)

XML

PENSION AND EMPLOYEE FUTURE BENEFITS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

PENSION AND EMPLOYEE FUTURE BENEFITS

29. PENSION AND EMPLOYEE FUTURE BENEFITS

Brookfield Renewable offers a number of pension plans to its employees, as well as certain health care, dental care, life insurance and other benefits to certain retired employees pursuant to Brookfield Renewable’s policy. The plans are funded by contributions from Brookfield Renewable and from plan members. Pension benefits are based on length of service and final average earnings and some plans are indexed for inflation after retirement. The pension plans relating to employees of Brookfield Renewable have been included in the consolidated financial statements.

The Brookfield Renewable Pension Governance Committee (BRGC) is responsible for the implementation of strategic decisions and monitoring of the administration of Brookfield Renewable’s defined benefit pension plans.  Specifically, the BRGC will establish the investment strategies, approve the funding policies as well as assess that Brookfield Renewable has complied with all applicable law, fiduciary, reporting and disclosure requirements.

Actuarial valuations for Brookfield Renewable’s pension plans are required as per governing provincial or federal regulations. For the United States registered plans, actuarial valuations are required annually. For the Canadian registered plans, actuarial valuations are required on a triennial basis if the funding level of the plan is above a certain threshold. Currently, all Canadian plans are on a triennial schedule. In the Colombian business, there are obligations for pension plans and other employee benefits. Actuarial valuations on these obligations are performed annually by qualified, independent actuaries. 

The dates of the most recent actuarial valuations for Brookfield Renewable’s pension and non-pension benefit plans range from January 2015 to January 2018. Brookfield Renewable measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year.

The benefit liabilities represent the amount of pension and other employee future benefits that Brookfield Renewable’s employees and retirees have earned at year-end. The benefit obligation under these plans is determined through periodic actuarial reports which were based on the assumptions indicated in the following table.

Actuarial assumptions as at December 31:

		Defined benefit			Non-pension			Defined benefit			Non-pension			Defined benefit			Non-pension
		pension plans			benefit plans			pension plans			benefit plans			pension plans			benefit plans
		2017						2016						2015
		(%)						(%)						(%)
Discount rate		2.4	-	7.3	3.7	-	7.1	2.2	-	7.3	4.1	-	7.3	2.9	-	4.7	4.2	-	4.7
Rate of price inflation		1.5	-	3.5	N/A			1.5	-	3.5	N/A			2.0	-	2.5	N/A
Rate of compensation
	increases	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	3.0	2.5	-	3.0
Health care trend rate(1)		N/A			5.3	-	6.9	N/A			5.3	-	6.9	N/A			6.3	-	7.1

Assumed immediate trend rate at year-end.

Plan obligations and the annual pension expense are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, discount rates, rate of compensation increases and other assumptions. The discount rate, rate of price inflation and inflation-linked assumptions and health care cost trend rate are the assumptions that generally have the most significant impact on the benefit obligations.

The discount rate for benefit obligation purposes is determined, as far as possible, by reference to market yields on high quality corporate bonds. In Colombia deep market in bonds does not exist. Accordingly, the discount rate is determined by reference to yields on government bonds. Rate of compensation increases reflect the best estimate of merit increases to be provided, consistent with assumed inflation rates.

A 50 basis point change in the assumptions mentioned before, used for the calculation of the benefit obligations as at December 31, 2017, would result in the following increase (decrease) of the benefit obligations:

		Defined benefit		Non-pension
(MILLIONS)		pension plans		benefit plans
Discount rate
	50 basis point increase		(11)		(4)
	50 basis point decrease		13		5
Rate of price inflation and inflation-linked assumptions
	50 basis point increase		4		N/A
	50 basis point decrease		(4)		N/A
Health care cost trend rate
	50 basis point increase		N/A		4
	50 basis point decrease		N/A		(3)

The sensitivity analysis presented above may not be representative of the actual change in the defined benefit obligation as it is unlikely that the change in assumptions would occur in isolation of one another as some of the assumptions may be correlated.

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Current service costs			$	3	$	1	$	3	$	1	$	3	$	1
Past service costs (recovery)				(1)		-		-		-		1		(1)
Interest expense				2		3		2		3		1		2
Administrative expenses				1		-		1		-		1		-
Recognized in consolidated
	statement of income			5		4		6		4		6		2
Remeasurement of the net
	defined benefit liability:
	Return on plan assets			(8)		-		(2)		-		(1)		-
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Recognized in consolidated
	statement of comprehensive
	income			-		2		2		-		1		(6)
Total			$	5	$	6	$	8	$	4	$	7	$	(4)

The amounts included in the consolidated statements of financial position arising from Brookfield Renewable’s obligations in respect of its defined benefit plans are as follows:

		Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
		pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)			2017				2016				2015
Present value of defined
	benefit obligation	$	172	$	57	$	158	$	53	$	124	$	35
Fair value of plan assets			(135)		(5)		(119)		(5)		(103)		-
Net liability		$	37	$	52	$	39	$	48	$	21	$	35

Defined benefit obligations

The movement in the defined benefit obligation for the year ended December 31 is as follows:

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Balance, beginning of year			$	158	$	53	$	124	$	35	$	128	$	43
Current service cost				3		1		3		1		3		1
Past service (recovery) cost				(1)		-		-		-		1		(1)
Interest expense				7		3		7		3		5		2
Remeasurement losses (gains)
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Benefits paid				(7)		(2)		(8)		(2)		(5)		(2)
Business combination				-		-		25		14		-		-
Exchange differences				4		-		3		2		(10)		(2)
Balance, end of year			$	172	$	57	$	158	$	53	$	124	$	35

Expected employer’s contributions to the defined benefit plans for the year ended December 31, 2018 are $6 million.

Fair value of plan assets

The movement in the fair value of plan assets for the year ended December 31 is as follows:

	Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
	pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)		2017				2016				2015
Balance, beginning of year	$	119	$	5	$	103	$	-	$	108	$	-
Interest income		5		-		5		-		4		-
Return on plan assets		8		-		2		-		1		-
Employer contributions		5		2		7		3		5		2
Business combination		-		-		9		4		-		-
Benefits paid		(7)		(2)		(8)		(2)		(5)		(2)
Exchange differences		5		-		1		-		(10)		-
Balance, end of year	$	135	$	5	$	119	$	5	$	103	$	-

The composition of plan assets as at December 31 is as follows:

		2017	2016
		(%)	(%)
Asset category:
	Cash and cash equivalents	2	5
	Equity securities	54	50
	Debt securities	44	44
	Real estate	-	1
		100	100

XML

SUBSIDIARY PUBLIC ISSUERS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

SUBSIDIARY PUBLIC ISSUERS

30. SUBSIDIARY PUBLIC ISSUERS

The following tables provide consolidated summary financial information for Brookfield Renewable, BRP Equity, and Finco:

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
As at December 31, 2017:
Current assets		$	32	$	412	$	1,691	$	525	$	2,816	$	(3,810)	$	1,666
Long-term assets			4,483		262		-		20,142		29,508		(25,157)		29,238
Current liabilities			43		7		180		3,024		3,071		(3,811)		2,514
Long-term liabilities			-		-		1,505		693		12,670		(760)		14,108
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		6,298		-		6,298
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,843		-		-		2,843
Preferred equity			-		616		-		-		-		-		616
Preferred limited partners' equity			511		-		-		516		-		(516)		511
As at December 31, 2016:
Current assets		$	26	$	-	$	1,581	$	150	$	2,092	$	(2,942)	$	907
Long-term assets			3,779		620		-		18,415		27,250		(23,234)		26,830
Current liabilities			33		9		19		2,971		1,644		(2,943)		1,733
Long-term liabilities			-		-		1,556		738		12,775		(1,737)		13,332
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		5,589		-		5,589
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,680		-		-		2,680
Preferred equity			-		576		-		-		-		-		576
Preferred limited partners' equity			324		-		-		324		-		(324)		324

• Includes investments in subsidiaries under the equity method.
• Includes BRELP, BRP Bermuda Holdings I Limited, Brookfield BRP Holdings (Canada) Inc. and Brookfield BRP Europe Holdings Limited, together the “Holding Entities”.
• Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco and the Holding Entities.
• Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
For the year ended
	December 31, 2017
Revenues		$	-	$	-	$	-	$	-	$	2,625	$	-	$	2,625
Net income (loss)			(4)		10		(1)		(435)		631		(150)		51
For the year ended
	December 31, 2016
Revenues		$	-	$	-	$	-	$	1	$	2,451	$	-	$	2,452
Net income (loss)			(20)		-		(1)		(100)		558		(397)		40
For the year ended
	December 31, 2015
Revenues		$	-	$	-	$	-	$	8	$	1,620	$	-	$	1,628
Net income (loss)			2		-		(1)		(42)		235		(91)		103

• Includes investments in subsidiaries under the equity method.
• Includes the Holding Entities.
• Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco, and the Holding Entities.
• Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

See Note 13 – Long-term debt and credit facilities for additional details regarding the medium-term corporate notes issued by Finco. See Note 14 – Non-controlling interests for additional details regarding Class A Preference Shares issued by BRP Equity.

XML

SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2017

Disclosure Text Block [Abstract]

SUBSEQUENT EVENTS

31. SUBSEQUENT EVENTS

On January 16, 2018, Brookfield Renewable issued 10,000,000 Series 13 Preferred LP Units at a price of C$25 per unit for gross proceeds of C$250 million ($201 million).

On January 19, 2018, Brookfield Renewable completed financing associated with its equity-accounted 2.1 GW pumped storage facility in the United Kingdom by securing £60 million ($83 million) of long-term debt and £90 million ($125 million) letter of credit facility. The long-term debt matures in 2021 and bears interest at LIBOR plus a margin of 2.75%.

On January 29, 2018, Brookfield Renewable completed R$130 million ($40 million) of financing with respect to a 19 MW hydroelectric facility currently under construction in Brazil. The loan bears interest at a rate of TJLP plus 2.15% and matures in 2038.

On February 15, 2018, Brookfield Renewable completed a refinancing associated with a 296 MW hydroelectric facility in the United States. The financing was a $350 million interest only green bond bearing interest at 4.5%, maturing in 2033. Proceeds were used to repay the existing principal amount of $315 million and the excess was distributed to investors.

On February 22, 2018, TerraForm Global issued $400 million of senior notes at 6.13%, maturing in March 2026. Along with cash on the balance sheet, proceeds were used to repay the existing $760 million of 9.75% senior notes due in 2022. Additionally, TerraForm Global secured a $45 million revolving credit facility, maturing in February 2021.

On February 27, 2018, Brookfield Renewable completed a COP 750 billion ($262 million) bond refinancing associated with the Colombian business.

XML

BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES (POLICY)

12 Months Ended

Dec. 31, 2017

Policy Text Block [Abstract]

Statement Of IFRS Compliance

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The accounting policies used in the consolidated financial statements are based on the IFRS applicable as at December 31, 2017, which encompass individual IFRS, International Accounting Standards (“IAS”), and interpretations made by the International Financial Reporting Interpretations Committee (“IFRIC”) and the Standard Interpretations Committee (“SIC”).

Disclosure Of Reclassifications Or Changes In Presentation Explanatory

The policies set out below are consistently applied to all periods presented, unless otherwise noted.

Basis of presentation - Consolidation

These consolidated financial statements include the accounts of Brookfield Renewable and its subsidiaries, which are the entities over which Brookfield Renewable has control. An investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Non-controlling interests in the equity of Brookfield Renewable’s subsidiaries are shown separately in equity in the consolidated statements of financial position.

Brookfield Renewable has entered into a voting agreement with Brookfield, which provides Brookfield Renewable with control of the general partner of Brookfield Renewable Energy L.P. (“BRELP”), a holding subsidiary. Accordingly, Brookfield Renewable consolidates the accounts of BRELP and its subsidiaries. In addition, BRELP issued redeemable-exchangeable limited partnership units to Brookfield (“Redeemable/Exchangeable partnership units”), pursuant to which the holder may at its request require BRELP to redeem the Redeemable/Exchangeable partnership units for cash consideration. This right is subject to Brookfield Renewable’s right of first refusal which entitles it, at its sole discretion, to elect to acquire all of the Redeemable/Exchangeable partnership units so presented to BRELP that are tendered for redemption in exchange for LP Units. As Brookfield Renewable, at its sole discretion, has the right to settle the obligation with LP Units, the Redeemable/Exchangeable partnership units are classified as equity of Brookfield Renewable (“Participating non-controlling interests – in a holding subsidiary – Redeemable/Exchangeable units held by Brookfield”).

Brookfield Renewable has entered into voting agreements with Brookfield, whereby Brookfield Renewable gained control of the entities that own certain renewable power generating operations in the United States, Brazil, Europe and other countries (including India and China). Brookfield Renewable has also entered into a voting agreement with our consortium partners in respect of our Colombian operations. These voting agreements provide Brookfield Renewable the authority to direct the election of the Boards of Directors of the relevant entities, among other things, and therefore provide Brookfield Renewable with control. Accordingly, Brookfield Renewable consolidates the accounts of these entities. Refer to Note 27 - Related party transactions for further information.

For entities previously controlled by Brookfield Asset Management, the voting agreements entered into do not represent business combinations in accordance with IFRS 3, Business Combinations(“IFRS 3”), as all combining businesses are ultimately controlled by Brookfield Asset Management both before and after the transactions were completed. Brookfield Renewable accounts for these transactions involving entities under common control in a manner similar to a pooling of interest, which requires the presentation of pre-voting agreement financial information as if the transactions had always been in place. Refer to Note 1(o)(ii) - Critical judgments in applying accounting policies - Common control transactions for Brookfield Renewable’s policy on accounting for transactions under common control.

Basis of presentation - Equity-accounted investments and joint ventures

Equity-accounted investments are entities over which Brookfield Renewable has significant influence or joint arrangements representing joint ventures. Significant influence is the ability to participate in the financial and operating policy decisions of the investee, but without controlling or jointly controlling those investees. Such investments are accounted for using the equity method.

A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require unanimous consent of the parties sharing control. Brookfield Renewable accounts for its interests in joint ventures using the equity method.

Under the equity method, the carrying value of an interest in an investee is initially recognized at cost and adjusted for Brookfield Renewable’s share of net income, other comprehensive income (“OCI”), distributions by the equity-accounted investment and other adjustments to Brookfield Renewable’s proportionate interest in the investee.

Foreign currency translation

All figures reported in the consolidated financial statements and tabular disclosures to the consolidated financial statements are reflected in millions of U.S. dollars, which is the functional currency of Brookfield Renewable. Each of the foreign operations included in these consolidated financial statements determines its own functional currency, and items included in the financial statements of each subsidiary are measured using that functional currency.

Assets and liabilities of foreign operations having a functional currency other than the U.S. dollar are translated at the rate of exchange prevailing at the reporting date and revenues and expenses at the rate of exchange prevailing at the dates of the transactions during the period. Gains or losses on translation of foreign subsidiaries are included in OCI. Gains or losses on foreign currency denominated balances and transactions that are designated as hedges of net investments in these operations are reported in the same manner.

In preparing the consolidated financial statements of Brookfield Renewable, foreign currency denominated monetary assets and liabilities are translated into the functional currency using the closing rate at the applicable consolidated statement of financial position dates. Non-monetary assets and liabilities, denominated in a foreign currency and measured at fair value, are translated at the rate of exchange prevailing at the date when the fair value was determined and non-monetary assets measured at historical cost are translated at the historical rate. Revenues and expenses are measured in the functional currency at the rates of exchange prevailing at the dates of the transactions with gains or losses included in income.

Cash and cash equivalents

Cash and cash equivalents include cash, term deposits and money market instruments with original maturities of less than 90 days.

Restricted cash

Restricted cash includes cash and cash equivalents, where the availability of funds is restricted primarily by credit agreements.

Property, plant and equipment and revaluation method

Power generating assets are classified as property, plant and equipment and are accounted for using the revaluation method under IAS 16, Property, Plant and Equipment (“IAS 16”). Property, plant and equipment are initially measured at cost and subsequently carried at their revalued amount, being the fair value at the date of the revaluation, less any subsequent accumulated depreciation and any subsequent accumulated impairment losses.

Brookfield Renewable generally determines the fair value of its property, plant and equipment by using a 20-year discounted cash flow model. This model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. The model also includes estimates of future electricity prices, anticipated long-term average generation, estimated operating and capital expenditures, and assumptions about future inflation rates and discount rates by geographical location. Construction work-in-progress (“CWIP”) is revalued when sufficient information exists to determine fair value using the discounted cash flow method. Revaluations are made on an annual basis as at December 31 to ensure that the carrying amount does not differ significantly from fair value. For power generating assets acquired through business combinations during the year, Brookfield Renewable initially measures the assets at fair value consistent with the policy described in Note 1(l) – Business combinations. Accordingly, in the year of acquisition, power generating assets are not revalued at year-end unless there is an indication that assets are impaired.

Where the carrying amount of an asset increased as a result of a revaluation, the increase is recognized in income to the extent the increase reverses a previously recognized decrease recorded through income, with the remainder of the increase recognized in OCI and accumulated in equity under revaluation surplus and non-controlling interest. Where the carrying amount of an asset decreased, the decrease is recognized in OCI to the extent that a balance exists in revaluation surplus with respect to the asset, with the remainder of the decrease recognized in income.

Gains and losses on disposal of an item of property, plant and equipment are recognized in Other income in the consolidated statements of income. The revaluation surplus is reclassified within the respective components of equity and not reclassified to net income when the assets are disposed.

Property, plant and equipment - Depreciation

	Estimated service lives
Dams	Up to 115 years
Penstocks	Up to 60 years
Powerhouses	Up to 115 years
Hydroelectric generating units	Up to 115 years
Wind generating units	Up to 30 years
Solar generating units	Up to 30 years
Gas-fired co-generating (“Co-gen”) units	Up to 40 years
Other assets	Up to 60 years

Asset impairment

At each statement of financial position date, management assesses whether there is any indication that assets are impaired. For non-financial tangible and intangible assets (including equity-accounted investments), an impairment is recognized if the recoverable amount, determined as the greater of the estimated fair value, less costs to sell, and the discounted future cash flows generated from use and eventual disposal of an asset or cash-generating unit, is less than its carrying value. The projections of future cash flows take into account the relevant operating plans and management’s best estimate of the most probable set of conditions anticipated to prevail. Should an impairment loss subsequently reverse, the carrying amount of the asset is increased to the lesser of the revised estimate of the recoverable amount, and the carrying amount that would have been recorded had no impairment loss been recognized previously.

Trade receivables and other current assets

Trade receivables and other current assets are recognized initially at fair value, and subsequently measured at amortized cost using the effective interest method, less any allowance for uncollectability.

Financial instruments

All financial instruments are classified into one of the following categories: assets and liabilities at fair value through profit or loss (“FVTPL”), cash, loans and receivables, financial instruments used for hedging, and other financial liabilities. All financial instruments are recorded at fair value at recognition. Subsequent to initial recognition, financial assets classified as loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method. Financial assets and financial liabilities classified as financial instruments used for cash-flow hedging continue to be recognized at fair value through OCI. Other financial assets and financial liabilities and non-hedging financial instruments are recorded at fair value through profit and loss.

Brookfield Renewable presents the liability and equity components separately upon recognition of such financial instruments. The amount of accretion relating to the liability component is recognized in profit or loss; and the amount of consideration relating to the equity component is recognized in equity.

Hedge accounting

Brookfield Renewable selectively utilizes derivative financial instruments to manage financial risks, including interest rate, commodity and foreign exchange risks. A derivative is a financial instrument, which requires little or no initial investment, settles at a future date, and has a value that changes in response to the change in a specified variable such as an interest rate, financial instrument price, commodity price, foreign exchange rate, index of prices or rates, credit rating or credit index. Hedge accounting is applied when the derivative is designated as a hedge of a specific exposure, and it is highly probable that it will continue to be effective as a hedge based on an expectation of offsetting cash flows or fair value. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as a hedge or the hedging relationship is terminated. Once discontinued, the cumulative change in fair value of a derivative that was previously recorded in equity by the application of hedge accounting is recognized in income over the remaining term of the original hedging relationship, unless the originally forecasted transaction is no longer expected to occur, at which point it is released to income. The fair values of derivative financial instruments are included in financial instrument assets or financial instrument liabilities, respectively.

(i) Items qualifying as hedges

Cash flow hedge

The effective portion of unrealized gains and losses on interest rate forward and swap contracts designated as hedges of future interest rate payments are included in equity as cash flow hedges when the interest rate risk relates to an anticipated interest payment. The periodic exchanges of payments on interest rate swap contracts designated as hedges of debt are recorded on an accrual basis as an adjustment to interest expense. The periodic exchanges of payments on interest rate contracts designated as hedges of future interest payments are recorded in income over the term of the corresponding interest payments.

Net investment hedge

Realized and unrealized gains and losses on foreign exchange forward contracts designated as hedges of currency risks are included in equity when the currency risk relates to a net investment in a subsidiary with a functional currency other than the U.S. dollar and are included in income in the period in which the subsidiary is disposed.

(ii) Items not qualifying as hedges

Upon initial recognition of a derivative financial instrument that is not designated as a hedge, a derivative asset or liability is recorded with an offsetting deferred liability or asset, respectively. Gains or losses arising from changes in fair value of the derivative asset or liability are recognized in income through fair value gains or losses in the period the changes occur. The deferred liability or asset is amortized through income, on a straight-line basis, over the life of the derivative financial instrument.

Available-for-sale investments

Brookfield Renewable maintains a portfolio of marketable securities comprised of liquid equity and debt securities categorized as available-for-sale when it is not Brookfield Renewable’s strategic intent to sell the securities and the securities were not acquired principally for their near-term sale.  Available-for-sale equity and debt investments are recorded at fair value with unrealized gains and losses recorded in OCI. Realized gains and losses are recorded in income when investments are sold and are calculated using the average carrying amount of securities sold. If the fair value of an investment declines below the carrying amount, qualitative and quantitative assessments of whether the impairment is either significant or prolonged is undertaken. All relevant facts and circumstances in this assessment are undertaken to determine, particularly the length of time and extent to which fair value has declined below the carrying amount. In the case of significant or prolonged decline in fair value of an investment, an impairment loss is recognized.

Revenue recognition

Revenue is derived from the sale of electricity and is recorded at the time power is provided based upon the output delivered and capacity provided at rates specified under either contract terms or prevailing market rates. The revenue must be considered collectible and the costs incurred to provide the electricity to be measurable before recognizing the related revenue.

Expense recognition

Costs related to the purchases of power or fuel are recorded upon delivery. All other costs are recorded as incurred.

Income taxes

Current income tax assets and liabilities are measured at the amount expected to be paid to tax authorities, net of recoveries, based on the tax rates and laws enacted or substantively enacted at the statement of financial position dates. Current income tax assets and liabilities are included in trade receivables and other current assets and accounts payable and accrued liabilities, respectively.

Deferred tax is recognized on taxable temporary differences between the tax bases and the carrying amounts of assets and liabilities. Deferred tax is not recognized if the temporary difference arises from goodwill or from initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither taxable profit nor accounting profit. Deferred income tax assets are recognized for all deductible temporary differences, carry forwards of unused tax credits and unused tax losses, to the extent that it is probable that deductions, tax credits and tax losses can be utilized. The carrying amount of deferred income tax assets is reviewed at each statement of financial position date and reduced to the extent it is no longer probable that the income tax assets will be recovered. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the statement of financial position dates.

Current and deferred income taxes relating to items recognized directly in OCI are also recognized directly in OCI.

Business combinations

The acquisition of a business is accounted for using the acquisition method. The consideration for an acquisition is measured at the aggregate of the fair values, at the date of exchange, of the assets transferred, the liabilities incurred to former owners of the acquired business, and equity instruments issued by the acquirer in exchange for control of the acquired business. The acquired business’ identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognized at their fair values at the acquisition date, except for income taxes which are measured in accordance with IAS 12, Income Taxes, share-based payments which are measured in accordance with IFRS 2, Share-based Payment and non-current assets that are classified as held-for-sale which are measured at fair value less costs to sell in accordance with IFRS 5, Non-current Assets Held for Sale and Discontinued Operations. The non-controlling interest in the acquiree is initially measured at the non-controlling interest’s proportion of the net fair value of the identifiable assets, liabilities and contingent liabilities recognized or when applicable, at the fair value of the shares outstanding.

To the extent that the aggregate of the fair value of consideration paid, the amount of any non-controlling interest and the fair value of any previously held interest in the acquiree exceeds the fair value of the net identifiable tangible and intangible assets acquired, goodwill is recognized. To the extent that this difference is negative, the amount is recognized as a gain in income. Goodwill is not amortized and is not deductible for tax purposes. However, after initial recognition, goodwill will be measured at cost less any accumulated impairment losses. An impairment assessment will be performed at least annually, and whenever circumstances such as significant declines in expected revenues, earnings or cash flows indicate that it is more likely than not that goodwill might be impaired. Goodwill impairment charges are not reversible.

When a business combination is achieved in stages, previously held interests in the acquired entity are re-measured to fair value at the acquisition date, which is the date control is obtained, and the resulting gain or loss, if any, is recognized in income. Amounts arising from interests in the acquired business prior to the acquisition date that have previously been recognized in OCI are reclassified to income. Upon disposal or loss of control of a subsidiary, the carrying amount of the net assets of the subsidiary (including any OCI relating to the subsidiary) are derecognized with the difference between any proceeds received and the carrying amount of the net assets recognized as a gain or loss in income.

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in fair values are adjusted against the cost of the acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as liabilities will be recognized in the consolidated statements of income, whereas changes in the fair values of contingent consideration classified within equity are not subsequently re-measured.

Capitalized costs

Capitalized costs related to CWIP include all eligible expenditures incurred in connection with the development and construction of the power generating asset. The expenditures consist of cost of materials, direct labor and any other costs directly attributable to bringing the asset to a working condition for its intended use, and the costs of dismantling and removing the items and restoring the site on which they are located. Interest and borrowing costs are capitalized when activities that are necessary to prepare the asset for its intended use or sale are in progress, expenditures for the asset have been incurred and funds have been used or borrowed to fund the construction or development. Capitalization of costs ceases when the asset is ready for its intended use.

Pension and employees future benefits

Pension and employee future benefits are recognized in the consolidated financial statements in respect of employees of the operating entities within Brookfield Renewable. The costs of retirement benefits for defined benefit plans and post-employment benefits are recognized as the benefits are earned by employees. The project unit credit method, using the length of service and management’s best estimate assumptions, is used to value its pension and other retirement benefits. All actuarial gains and losses are recognized immediately through OCI in order for the net pension asset or liability recognized in the consolidated statements of financial position to reflect the full value of the plan deficit or surplus. Net interest is calculated by applying the discount rate to the net defined benefit asset or liability. Changes in the net defined benefit obligation related to service costs (comprising of current service costs, past services costs, gains and losses on curtailments and non-routine settlements), and net interest expense or income are recognized in the consolidated statements of income.

Re-measurements, comprising of actuarial gains or losses, the effect of the asset ceiling, and the return on plan assets (excluding net interest), are recognized immediately in the consolidated statements of financial position with a corresponding debit or credit to retained earnings through OCI in the period in which they occur. Re-measurements are not reclassified to profit or loss in subsequent periods. For defined contribution plans, amounts are expensed based on employee entitlement.

Decommisioning, restoration and environmental liabilities

Legal and constructive obligations associated with the retirement of property, plant and equipment are recorded as liabilities when those obligations are incurred and are measured at the present value of the expected costs to settle the liability, using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The liability is accreted up to the date the liability will be incurred with a corresponding charge to operating expenses. The carrying amount of decommissioning, restoration and environmental liabilities is reviewed annually with changes in the estimates of timing or amount of cash flows added to or deducted from the cost of the related asset.

Interest and borrowing costs

Interest and borrowing costs are capitalized when such costs are directly attributable to the acquisition, construction or production of a qualifying asset. A qualifying asset is an asset that takes a substantial period of time to prepare for its intended use.

Provisions

A provision is a liability of uncertain timing or amount. A provision is recognized if Brookfield Renewable has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount can be reliably estimated. Provisions are not recognized for future operating losses. The provision is measured at the present value of the best estimate of the expenditures expected to be required to settle the obligation using a discount rate that reflects the current market assessments of the time value of money and the risks specific to the obligation. Provisions are re-measured at each statement of financial position date using the current discount rate. The increase in the provision due to the passage of time is recognized as interest expense.

Interest income

Interest income is earned with the passage of time and is recorded on an accrual basis.

Government grants

Brookfield Renewable becomes eligible for government grants by constructing or purchasing renewable power generating assets, and by bringing those assets to commercial operation, coupled with a successful application to the applicable program or agency. The assessment of whether or not a project has complied with the conditions and that there is reasonable assurance the grants will be received will be undertaken on a case by case basis. Brookfield Renewable reduces the cost of the asset by the amount of the grant. The grant amounts are recognized in income on a systematic basis as a reduction of depreciation over the periods, and in the proportions, in which depreciation on those assets is charged.

With respect to grants related to income, the government assistance (in the form of the difference between market price and guaranteed fixed price) typically becomes payable once electricity is produced and delivered to the relevant grid. It is at this point that the receipt of the grant becomes reasonably assured, and therefore the grant is recognized as revenue in the month that delivery of the electricity occurs.

Critical estimates and judgements in applying accounting policies

(n) Critical estimates

Brookfield Renewable makes estimates and assumptions that affect the carrying value of assets and liabilities, disclosure of contingent assets and liabilities and the reported amount of income and OCI for the year. Actual results could differ from these estimates. The estimates and assumptions that are critical to the determination of the amounts reported in the consolidated financial statements relate to the following:

(i) Property, plant and equipment

The fair value of Brookfield Renewable’s property, plant and equipment is calculated using estimates and assumptions about future electricity prices from renewable sources, anticipated long-term average generation, estimated operating and capital expenditures, future inflation rates and discount rates, as described in Note 12 - Property, plant and equipment, at fair value. Judgment is involved in determining the appropriate estimates and assumptions in the valuation of Brookfield Renewable’s property, plant and equipment. See Note 1(o)(iii) - Critical judgments in applying accounting policies - Property, plant and equipment for further details.

Estimates of useful lives and residual values are used in determining depreciation and amortization. To ensure the accuracy of useful lives and residual values, these estimates are reviewed on an annual basis.

(ii) Financial instruments

Brookfield Renewable makes estimates and assumptions that affect the carrying value of its financial instruments, including estimates and assumptions about future electricity prices, long-term average generation, capacity prices, discount rates and the timing of energy delivery. Non-financial instruments are valued using estimates of future electricity prices which are estimated by considering broker quotes for the years in which there is a liquid market and, for the subsequent years, Brookfield Renewable’s best estimate of electricity prices that would allow new entrants into the market. The fair value of interest rate swaps is the estimated amount that another party would receive or pay to terminate the swap agreements at the reporting date, taking into account current market interest rates. This valuation technique approximates the net present value of future cash flows. See Note 5 - Risk management and financial instruments for more details.

(iii) Deferred income taxes

The consolidated financial statements include estimates and assumptions for determining the future tax rates applicable to subsidiaries and identifying the temporary differences that relate to each subsidiary. Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply during the year when the assets are realized or the liabilities settled, using the tax rates and laws enacted or substantively enacted at the consolidated statement of financial position dates. Operating plans and forecasts are used to estimate when the temporary difference will reverse.

(o) Critical judgments in applying accounting policies

The following are the critical judgments that have been made in applying the accounting policies used in the consolidated financial statements and that have the most significant effect on the amounts in the consolidated financial statements:

(i) Preparation of consolidated financial statements

These consolidated financial statements present the financial position, results of operations and cash flows of Brookfield Renewable. Judgment is required in determining what assets, liabilities and transactions are recognized in the consolidated financial statements as pertaining to Brookfield Renewable’s operations.

(ii) Common control transactions

Common control business combinations specifically fall outside of scope of IFRS 3 and as such management has used its judgment to determine an appropriate policy to account for these transactions, considering other relevant accounting guidance that is within the framework of principles in IFRS and that reflects the economic reality of the transactions, in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. As a result, the consolidated financial statements account for assets and liabilities acquired at the previous carrying value on the predecessor’s financial statements. Differences between the consideration given and the assets and liabilities received are recorded directly to equity.

(iii) Property, plant and equipment

The accounting policy relating to Brookfield Renewable’s property, plant and equipment is described in Note 1(f) - Property, plant and equipment and revaluation method. In applying this policy, judgment is used in determining whether certain costs are additions to the carrying amount of the property, plant and equipment as opposed to repairs and maintenance. If an asset has been developed, judgment is required to identify the point at which the asset is capable of being used as intended and to identify the directly attributable costs to be included in the carrying value of the development asset. The useful lives of property, plant and equipment are determined by independent engineers periodically with an annual review by management.

Annually, Brookfield Renewable determines the fair value of its property, plant and equipment using a methodology that it has judged to be reasonable. The methodology is generally a 20-year discounted cash flow model. Twenty years is the period considered reasonable as Brookfield Renewable has 20-year capital plans and it believes a reasonable third party would be indifferent between extending the cash flows further in the model versus using a discounted terminal value.

The valuation model incorporates future cash flows from long-term power purchase agreements that are in place where it is determined that the power purchase agreements are linked specifically to the related power generating assets. With respect to estimated future generation that does not incorporate long-term power purchase agreement pricing, the cash flow model uses estimates of future electricity prices using broker quotes from independent sources for the years in which there is a liquid market. The valuation of power generating assets not linked to long-term power purchase agreements also requires the development of a long-term estimate of future electricity prices. In this regard the valuation model uses a discount to the all-in cost of construction with a reasonable return, to secure energy from new renewable on-shore wind development resources as the benchmark that will establish the market price for electricity for renewable resources.

Brookfield Renewable’s long-term view is anchored to the cost of securing new energy from renewable sources to meet future demand growth by the year 2025 in North America and Colombia, 2023 in Europe, and 2021 in Brazil. Based on current supply and demand fundamentals, Brookfield Renewable revised the year of new entry in North America to 2025 from 2023. The year of new entry is viewed as the point when generators must build additional capacity to maintain system reliability and provide an adequate level of reserve generation with the retirement of older coal fired plants and rising environmental compliance costs in North America and Europe, and overall increasing demand in Colombia and Brazil. For the North American and European businesses, Brookfield Renewable has estimated a discount to these new-build wind prices to determine renewable electricity prices for hydroelectric and wind facilities. In Brazil and Colombia, the estimate of future electricity prices is based on a similar approach as applied in North America using a forecast of the all-in cost of development.

Terminal values are included in the valuation of hydroelectric assets in North America and Colombia. For the hydroelectric assets in Brazil, cash flows have been included based on the duration of the authorization or useful life of a concession asset without consideration of potential renewal value.

Discount rates are determined each year by considering the current interest rates, average market cost of capital as well as the price risk and the geographical location of the operational facilities as judged by management. Inflation rates are also determined by considering the current inflation rates and the expectations of future rates by economists. Operating costs are based on long-term budgets escalated for inflation. Each operational facility has a 20-year capital plan that it follows to ensure the maximum life of its assets is achieved. Foreign exchange rates are forecasted by using the spot rates and the available forward rates, extrapolated beyond the period available. The inputs described above to the discounted cash flow model require management to consider facts, trends and plans in making its judgments as to what derives a reasonable fair value of its property, plant and equipment.

(iv) Financial instruments

The accounting policy relating to Brookfield Renewable’s financial instruments is described in Note 1(i) - Financial instruments. In applying the policy, judgments are made in applying the criteria set out in IAS 39, Financial Instruments: Recognition and Measurement (“IAS 39”), to record financial instruments at fair value through profit and loss, and the assessments of the effectiveness of hedging relationships.

(v) Deferred income taxes

The accounting policy relating to Brookfield Renewable’s income taxes is described in Note 1(k) - Income taxes. In applying this policy, judgments are made in determining the probability of whether deductions, tax credits and tax losses can be utilized.

IFRS 9 [Member]

Disclosure of expected impact of initial application of new standards or interpretations [line items]

Future changes in accounting policies

Standard	Description	Effective date	Effect on financial statements
In July 2014, the IASB issued the final version of IFRS 9, Financial Instruments (“IFRS 9”).	The standard reflects all phases of the financial instruments project and replaces IAS 39, Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. This standard establishes principles for the financial reporting of financial assets and financial liabilities that will present relevant and useful information to users of financial statements for their assessment of the amounts, timing and uncertainty of an entity’s future cash flows. The new standard makes several improvements to IAS 39; mostly notably adopting a principle based approach to hedge accounting. While this does not change the type of hedging relationships or the requirement to measure ineffectiveness, it simplifies the application of hedge accounting and should allow for better alignment of risk management strategies with accounting presentation. Other changes include replacing the multiple financial asset impairment models in IAS 39 with a single model based on expected credit losses on all financial assets, and replacing the existing complex classifications structure with a business model approach based on the intent and nature of the cash flows.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 9 is a significant initiative for Brookfield Renewable.Management has chosen to adopt the standard retrospectively with no restatement of comparative periods. The assessment of financial assets and liabilities under the new classification methodology has been completed. Hedging documentation has been updated for compliance with IFRS 9 and updated risk management policies and internal controls to align with the new standard. Management has also assessed the impact of the new impairment requirements for financial assets.There are no material adjustments from the adoption of the standard.

IFRS 15 [Member]

Disclosure of expected impact of initial application of new standards or interpretations [line items]

Future changes in accounting policies

Standard	Description	Effective date	Effect on financial statements
IFRS 15, Revenue from Contracts with Customers (“IFRS 15”) was issued by the IASB on May 28, 2014.	IFRS 15 outlines a single comprehensive model to account for revenue arising from contracts with customers and will replace the majority of existing IFRS requirements on revenue recognition including IAS 18, Revenue, IAS 11, Construction Contracts and related interpretations. The core principle of the standard is to recognize revenue to depict the transfer of goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard has prescribed a five-step model to apply the principles. The standard also specifies how to account for the incremental costs of obtaining a contract and the costs directly related to fulfilling a contract as well as requiring more informative and relevant disclosures. IFRS 15 applies to nearly all contracts with customers, unless covered by another standard, such as leases, financial instruments and insurance contracts.In April 2016, the IASB issued amendments to IFRS 15, which provided additional guidance on the identification of performance obligations, on assessing principal versus agent considerations and on licensing revenue. The amendments also provide additional transition relief upon initial adoption of IFRS 15 and have the same effective date as the IFRS 15 standard.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2018, with early adoption permitted.	The adoption of IFRS 15 is a significant initiative for Brookfield Renewable. Management has chosen to adopt the standard using the modified retrospective approach. This method results in a cumulative catch-up adjustment to equity as of January 1, 2018 as if the standard had always been in effect. Management has completed its review of material revenue streams. The majority of Brookfield Renewable’s revenue streams are within the scope of IFRS 15 and are include the sale of energy, capacity and renewable energy credits through power purchase agreements or through merchant mechanisms. Based on management’s analysis, substantially all of the contracts currently in place for the year beginning on January 1, 2018 do not contain a difference in the timing or measurement of revenue recognition under the new standard and the impact of both the cumulative catch up and ongoing revenue recognition is expected to not be material to the overall statements of Brookfield Renewable.

IFRS 16 [Member]

Disclosure of expected impact of initial application of new standards or interpretations [line items]

Future changes in accounting policies

Standard	Description	Effective date	Effect on financial statements
IFRS 16, Leases (“IFRS 16”) was issued by the IASB on January 13, 2016.	IFRS 16 brings most leases onto the statement of financial position for lessees under a single model, eliminating the distinction between operating and finance leases. Lessor accounting remains largely unchanged and the distinction between operating and finance leases is retained. Under IFRS 16 a lessee recognizes a right-of-use asset and a lease liability. The right-of-use asset is treated similarly to other non-financial assets and depreciated accordingly, and the liability accrues interest. The lease liability is initially measured at the present value of the lease payments payable over the lease term, discounted at the rate implicit in the lease. Lessees are permitted to make an accounting policy election, by class of underlying asset, to apply a method like IAS 17’s operating lease accounting and not recognize lease assets and lease liabilities for leases with a lease term of 12 months or less, and on a lease-by-lease basis, to apply a method similar to current operating lease accounting to leases for which the underlying asset is of low value. IFRS 16 supersedes IAS 17, Leases and related interpretations. A lessee will apply IFRS 16 to its leases either retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying IFRS 16 being recognized at the date of initial application.	The standard has a mandatory effective date for annual periods beginning on or after January 1, 2019, with early adoption permitted.	Management has formed its adoption working group and participated in planning sessions with Brookfield Asset Management. Management continues to evaluate the impact of IFRS 16 on the consolidated financial statements.

XML

BASIS OF PREPARATION AND SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Depreciation on power generating assets is calculated on a straight-line basis over the estimated service lives of the assets, which are as follows:

	Estimated service lives
Dams	Up to 115 years
Penstocks	Up to 60 years
Powerhouses	Up to 115 years
Hydroelectric generating units	Up to 115 years
Wind generating units	Up to 30 years
Solar generating units	Up to 30 years
Gas-fired co-generating (“Co-gen”) units	Up to 40 years
Other assets	Up to 60 years

XML

PRINCIPAL SUBSIDIARIES (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following table lists the subsidiaries of Brookfield Renewable which, in the opinion of management, significantly affects its financial position and results of operations as at December 31:

	Jurisdiction of	Percentage of
	Incorporation	voting securities
	or Organization	owned or controlled
Alta Wind VIII LLC(1)	Delaware	100
BIF II Safe Harbor Holdings LLC(1)	Delaware	100
BIF III Holtwood LLC(1)	Delaware	100
BRE GLBL Holdings L.P.(1)	Bermuda	100
BRI Green Energy Limited(1)	Republic of Ireland	100
Brookfield BRP Canada Corp.	Alberta	100
Brookfield Energia Comercializadora Ltda	Brazil	100
Brookfield Power US Holding America Co.	Delaware	100
Brookfield Power Wind Prince LP	Ontario	100
Brookfield Renewable UK Hydro Limited	England and Wales	100
Brookfield Smoky Mountain Hydropower LLC(1)	Delaware	100
Brookfield White Pine Hydro LLC(1)	Delaware	100
Catalyst Old River Hydroelectric Limited Partnership(2)	Louisiana	75
Erie Boulevard Hydropower, L.P.	Delaware	100
Granite Reliable Power, LLC(1)	Delaware	89.5
Great Lakes Hydro America, LLC	Delaware	100
Great Lakes Power Limited	Ontario	100
Hawks Nest Hydro LLC	Delaware	100
Isagen S.A. E.S.P.(1)	Colombia	99.5
Itiquira Energética S.A.	Brazil	100
Kwagis Power Limited Partnership	British Columbia	75
Lièvre Power L.P.	Québec	100
Mississagi Power Trust	Québec	100
Orion Canadian Holdings 1 AIV L.P.	Ontario	100
PEA - Parque Eólico da Serra, Unipessola S.A.(1)	Portugal	100
Powell River Energy Inc.	Canada	100
Rumford Falls Hydro LLC	Delaware	100
Safe Harbor Water Power Corporation(1)	Pennsylvania	100
Tangará Energia S.A.(1)	Brazil - São Paulo	100
Windstar Energy, LLC	California	100
2016 Comber Wind Limited Partnership	Ontario	100

• Voting control held through voting agreements with Brookfield.
• Non-voting economic interest held through preferred shares and secured notes.

XML

ACQUISITIONS (Tables)

12 Months Ended

Dec. 31, 2017

Acqusitions Completed In 2017

Acqusition Tables

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

	TerraForm		European
(MILLIONS)	Global		Wind		Total
Cash and cash equivalents	$	611	$	-	$	611
Restricted cash		90		-		90
Trade receivables and other current assets		62		1		63
Financial instruments		20		-		20
Property, plant and equipment, at fair value		1,208		37		1,245
Deferred tax assets		18		-		18
Other long-term assets		94		-		94
Current liabilities		(73)		(4)		(77)
Current portion of long-term debt		(1,183)		-		(1,183)
Financial instruments		(15)		-		(15)
Long-term debt		(5)		-		(5)
Deferred income tax liabilities		(15)		(2)		(17)
Other long-term liabilities		(54)		-		(54)
Non-controlling interests		(1)		-		(1)
Fair value of net assets acquired		757		32		789

Acqusitions Completed In 2016

Acqusition Tables

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Colombia		Brazil		Pennsylvania		Ireland		Total
Cash and cash equivalents	$	113	$	4	$	-	$	-	$	117
Trade receivables and other current assets		174		2		1		-		177
Property, plant and equipment, at fair value		4,772		100		859		10		5,741
Other long-term assets		15		-		-		-		15
Current liabilities		(463)		(3)		(1)		-		(467)
Long-term debt		(899)		-		-		-		(899)
Deferred income tax liabilities		(1,019)		-		-		(1)		(1,020)
Other long-term liabilities		(149)		-		-		-		(149)
Non-controlling interests		(1,417)		-		-		-		(1,417)
Fair value of net assets acquired		1,127		103		859		9		2,098
Goodwill (Note 17)		799		-		-		-		799
Purchase price	$	1,926	$	103	$	859	$	9	$	2,897

Acqusitions Completed In 2015

Acqusition Tables

Final purchase price allocations, at fair values, with respect to the acquisitions are as follows:

(MILLIONS)	Brazil		Portugal		Scotland		Total
Cash and cash equivalents	$	19	$	-	$	-	$	19
Restricted cash		16		5		-		21
Trade receivables and other current assets		16		3		1		20
Property, plant and equipment, at fair value		854		209		84		1,147
Current liabilities		(21)		(19)		(1)		(41)
Long-term debt		(280)		(111)		-		(391)
Other long-term liabilities		-		(16)		(12)		(28)
Non-controlling interests		(16)		-		-		(16)
Net assets acquired	$	588	$	71	$	72	$	731

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Disclosure of risk management strategy related to hedge accounting [line items]

The table below classifies the cash obligations related to Brookfield Renewables liabilities into relevant maturity groupings based on the remaining period from the statement of financial position dates to the contractual maturity date

AS AT DECEMBER 31, 2017
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	542	$	-	$	-	$	542
Financial instrument liabilities(1)		184		62		24		270
Due to related parties		112		-		-		112
Other long-term liabilities - concession payments		1		3		10		14
Long-term debt and credit facilities(1)		1,676		4,587		5,579		11,842
Interest payable on long-term debt(2)		634		1,924		1,697		4,255
Total	$	3,149	$	6,576	$	7,310	$	17,035
AS AT DECEMBER 31, 2016
(MILLIONS)		< 1 year	2-5 years		> 5 years		Total
Accounts payable and accrued liabilities	$	467	$	-	$	-	$	467
Financial instrument liabilities(1)		156		66		6		228
Due to related parties		76		-		-		76
Other long-term liabilities - concession payments		1		4		11		16
Long-term debt and credit facilities(1)		1,034		3,970		5,256		10,260
Interest payable on long-term debt(2)		589		1,821		1,449		3,859
Total	$	2,323	$	5,861	$	6,722	$	14,906

⁽¹⁾Includes both the current and long-term amounts.

⁽²⁾Represents aggregate interest payable expected to be paid over the entire term of the obligations, if held to maturity. Variable rate interest payments have been calculated based on estimated interest rates.

Brookfield Renewable classifies its assets and liabilities as outlined below

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2017	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	799	$	-	$	-	$	-	$	-	$	799
Restricted cash		181	-	-		-		-		-		181
Trade and other receivables(2)		442		-		-		-		-		442
Other current assets		-		-		-		-		112		112
Due from related parties(2)		60		-		-		-		-		60
Financial instrument assets(3)		-		20		6		159		-		185
Equity-accounted investments		-		-		-		-		721		721
Property, plant and equipment, at fair value		-		-		-		-		27,096		27,096
Goodwill		-		-		-		-		901		901
Deferred income tax assets		-		-		-		-		177		177
Other long-term assets		103		-		-		-		127		230
Total assets	$	1,585	$	20	$	6	$	159	$	29,134	$	30,904
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	542	$	-	$	542
Financial instrument liabilities(3)		-		145		125		-		-		270
Due to related parties(2)		-		-		-		112		-		112
Long-term debt and credit facilities(2)(3)		-		-		-		11,766		-		11,766
Deferred income tax liabilities		-		-		-		-		3,588		3,588
Other long-term liabilities		-		-		-		344		-		344
Total liabilities	$	-	$	145	$	125	$	12,764	$	3,588	$	16,622

• Measured at fair value with all gains and losses recorded in the consolidated statement of income.
• Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.
• Includes both the current and long-term amounts.

							Other		Non-financial
	Cash, loans				Derivatives		financial		assets and
AS AT DECEMBER 31, 2016	and		Assets/		used for		assets and		non-financial
(MILLIONS)	receivables		liabilities(1)		hedging		liabilities		liabilities		Total
Cash and cash equivalents	$	223	$	-	$	-	$	-	$	-	$	223
Restricted cash		121		-		-		-		-		121
Trade and other receivables(2)		365		-		-		-		-		365
Other current assets		-		-		-		-		89		89
Due from related parties(2)		54		-		-		-		-		54
Financial instrument assets(3)		-		14		50		136		-		200
Equity-accounted investments		-		-		-		-		206		206
Property, plant and equipment, at fair value		-		-		-		-		25,257		25,257
Goodwill		-		-		-		-		896		896
Deferred income tax assets		-		-		-		-		150		150
Other long-term assets		129		-		-		-		47		176
Total assets	$	892	$	14	$	50	$	136	$	26,645	$	27,737
Accounts payable and accrued liabilities(2)	$	-	$	-	$	-	$	467	$	-	$	467
Financial instrument liabilities(3)		-		11		217		-		-		228
Due to related parties(2)		-		-		-		76		-		76
Long-term debt and credit facilities(2)(3)		-		-		-		10,182		-		10,182
Deferred income tax liabilities		-		-		-		-		3,802		3,802
Other long-term liabilities		-		-		-		310		-		310
Total liabilities	$	-	$	11	$	217	$	11,035	$	3,802	$	15,065

• Measured at fair value with all gains and losses recorded in the consolidated statement of income.
• Measured at fair value at inception and subsequently recorded at amortized cost using the effective interest rate method.
• Includes both the current and long-term amounts.

The following table presents Brookfield Renewables assets and liabilities measured and disclosed at fair value classified by the fair value hierarchy as at December 31:

(MILLIONS)		Level 1		Level 2		Level 3		2017		2016
Assets measured at fair value:
Cash and cash equivalents		$	799	$	-	$	-	$	799	$	223
Restricted cash(1)			284		-		-		284		250
Financial instrument assets(2)
	Energy derivative contracts		-		-		-		-		8
	Interest rate swaps		-		6		-		6		7
	Foreign exchange swaps		-		20		-		20		49
	Available-for-sale investments(2)		79		80		-		159		136
Property, plant and equipment			-		-		27,096		27,096		25,257
Liabilities measured at fair value:
Financial instrument liabilities(3)
	Energy derivative contracts		-		(19)		-		(19)		(5)
	Interest rate swaps		-		(155)		-		(155)		(178)
	Foreign exchange swaps		-		(96)		-		(96)		(45)
Contingent consideration(4)			-		-		(18)		(18)		(16)
Liabilities for which fair value is disclosed:
	Long-term debt and credit facilities		-		(12,479)		-		(12,479)		(10,870)
Total		$	1,162	$	(12,643)	$	27,078	$	15,597	$	14,816

• Includes both the current amount and long-term amount included in Other long-term assets.
• Includes amounts in Level 2 that relate to the Brookfield Infrastructure Debt Fund holdings.
• Includes both current and long-term amounts.
• Amount relates to 2015 and 2014 business combinations with obligations lapsing in 2021 and 2024 respectively.

The aggregate amount of Brookfield Renewables net financial instrument positions as at December 31 are as follows:

				2017				2016
					Net Liabilities		Net Liabilities
(MILLIONS)	Assets		Liabilities		(Assets)		(Assets)
Energy derivative contracts	$	-	$	19	$	19	$	(3)
Interest rate swaps		6		155		149		171
Foreign exchange swaps		20		96		76		(4)
Available-for-sale securities		159		-		(159)		(136)
Total		185		270		85		28
Less: current portion		72		184		112		101
Long-term portion	$	113	$	86	$	(27)	$	(73)

The following table presents the change in Brookfield Renewables total net financial instrument liability position as at and for the year ended December 31:

(MILLIONS)		Note		2017		2016		2015
Balance, beginning of year			$	28	$	145	$	77
Increases (decreases) in the net financial instrument liability position:
	Unrealized loss (gain) through income on energy derivative contracts	(a)		5		-		(2)
	Unrealized loss through OCI on energy derivative contracts	(a)		17		28		3
	Unrealized (gain) loss through income on interest rate swaps	(b)		(1)		7		(2)
	Unrealized (gain) loss through OCI on interest rate swaps	(b)		(18)		1		20
	Unrealized loss (gain) through income on foreign exchange swaps	(c)		29		(3)		13
	Unrealized loss (gain) through OCI on foreign exchange swaps	(c)		94		61		(57)
	Unrealized loss through income on available-for-sale investments	(d)		-		-		25
	Unrealized loss (gain) through OCI on available-for-sale investments	(d)		20		(52)		-
	Acquisitions, settlements and other			(89)		(159)		68
Balance, end of year			$	85	$	28	$	145
Financial instrument liabilities not designated as hedging instruments:
Energy derivative contracts		(a)	$	5	$	3	$	-
Interest rate swaps		(b)		107		2		-
Foreign exchange swaps		(c)		33		6		-
Net positions			$	145	$	11	$	-
Financial instrument liabilities designated as hedging instruments:
Energy derivative contracts		(a)	$	14	$	2	$	1
Interest rate swaps		(b)		48		176		178
Foreign exchange swaps		(c)		63		39		12
Net positions			$	125	$	217	$	191
Financial instrument assets not designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(3)	$	-
Interest rate swaps		(b)		(1)		(1)		-
Foreign exchange swaps		(c)		(19)		(10)		(1)
Available-for-sale investments		(d)		(159)		(136)		(14)
Net positions			$	(179)	$	(150)	$	(15)
Financial instrument assets designated as hedging instruments:
Energy derivative contracts		(a)	$	-	$	(5)	$	(31)
Interest rate swaps		(b)		(5)		(6)		-
Foreign exchange swaps		(c)		(1)		(39)		-
Net positions			$	(6)	$	(50)	$	(31)
Total net positions			$	85	$	28	$	145

Credit risk [member]

Disclosure of risk management strategy related to hedge accounting [line items]

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes

(MILLIONS)		2017		2016
Cash and cash equivalents	$	799	$	223
Restricted cash(1)		284		250
Trade receivables and other short-term receivables		442		365
Financial instrument assets(1)		185		200
Due from related parties		60		54
	$	1,770	$	1,092

Includes both the current and long-term amounts.

Market risk [Member]

Disclosure of risk management strategy related to hedge accounting [line items]

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	4	$	1	$	2	$	79	$	51	$	10
5% decrease		(4)		(1)		(2)		(79)		(51)		(10)

Amounts represent the potential annual net pretax impact.

Interest rate risk [Member]

Disclosure of risk management strategy related to hedge accounting [line items]

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
1% increase	$	17	$	(17)	$	(15)	$	54	$	115	$	125
1% decrease		(17)		17		15		(54)		(115)		(125)

Amounts represent the potential annual net pretax impact.

Commodity price risk [member]

Disclosure of risk management strategy related to hedge accounting [line items]

The sensitivity analysis discussed below reflect the risks associated with instruments that Brookfield Renewable considers are market sensitive and the potential loss resulting from one or more selected hypothetical changes

	Effect on net income(1)						Effect on OCI(1)
(MILLIONS)		2017		2016		2015		2017		2016		2015
5% increase	$	(3)	$	(1)	$	(2)	$	(4)	$	(7)	$	(7)
5% decrease		3		1		2		4		7		7

Amounts represent the potential annual net pretax impact.

XML

SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following table reconciles Adjusted EBITDA and Funds From Operations, presented in the above tables, to net income as presented in the consolidated statements of income (loss), for the year ended December 31:

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Solar,		Corporate		Total	equity		to non-		As per
		North						North						Storage and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			945		191		243		161		46		26		67		-	1,679		(74)		1,020		2,625
Other income			1		2		12		-		-		-		6		19	40		(11)		18		47
Direct operating costs			(281)		(94)		(77)		(42)		(20)		(4)		(34)		(25)	(577)		28		(429)		(978)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		57		-		57
Adjusted EBITDA			665		99		178		119		26		22		39		(6)	1,142		-		609		-
Management service costs			-		-		-		-		-		-		-		(82)	(82)		-		-		(82)
Interest expense - borrowings			(180)		(42)		(18)		(45)		(10)		(6)		(17)		(89)	(407)		21		(246)		(632)
Current income taxes			1		(5)		(12)		-		(1)		-		(1)		-	(18)		1		(22)		(39)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(28)	(28)		-		-		(28)
	Preferred equity		-		-		-		-		-		-		-		(26)	(26)		-		-		(26)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(22)		-		(22)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(341)		(341)
Funds From Operations			486		52		148		74		15		16		21		(231)	581		-		-		-
Depreciation			(222)		(26)		(141)		(89)		(24)		(8)		(29)		-	(539)		22		(265)		(782)
Unrealized financial instrument loss			(3)		(3)		-		(1)		(12)		-		-		(10)	(29)		1		(5)		(33)
Deferred income tax expense			(67)		(10)		2		45		6		-		1		(3)	(26)		(3)		(20)		(49)
Other			(20)		6		(8)		(3)		(5)		2		(6)		(9)	(43)		13		2		(28)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(33)		-		(33)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		288		288
Net income (loss) attributable to Unitholders(2)			174		19		1		26		(20)		10		(13)		(253)	(56)		-		-		(56)

• Share of earnings from equity-accounted investments of $2 million is comprised of amounts found on the share of Adjusted EBITDA, share of interest and cash taxes and share of earnings lines. Net income attributable to participating non-controlling interests – in operating subsidiaries of $53 million is comprised of amounts found on Share of Funds From Operations attributable to non-controlling interests and Net Income attributable to non-controlling interests.
• Net income (loss) attributable to Unitholders includes net income (loss) attributable to GP interest, Redeemable/Exchangeable partnership units and LP Units. Total net income (loss) includes amounts attributable to Unitholders, non-controlling interests, preferred limited partners equity and preferred equity.

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		192		187		151		56		17		58		1	1,481		(37)		1,008		2,452
Other income			24		3		13		-		-		-		(1)		8	47		-		17		64
Direct operating costs			(295)		(107)		(70)		(36)		(24)		(4)		(26)		(24)	(586)		16		(468)		(1,038)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		21		-		21
Adjusted EBITDA			548		88		130		115		32		13		31		(15)	942		-		557		-
Management service costs			-		-		-		-		-		-		-		(62)	(62)		-		-		(62)
Interest expense - borrowings			(177)		(36)		(24)		(41)		(14)		(7)		(12)		(91)	(402)		12		(216)		(606)
Current income taxes			(4)		(6)		(9)		-		-		-		-		-	(19)		-		(25)		(44)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(15)	(15)		-		-		(15)
	Preferred equity		-		-		-		-		-		-		-		(25)	(25)		-		-		(25)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(12)		-		(12)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(316)		(316)
Funds From Operations			367		46		97		74		18		6		19		(208)	419		-		-		-
Depreciation			(244)		(31)		(125)		(80)		(38)		(4)		(18)		-	(540)		11		(252)		(781)
Unrealized financial instrument loss			1		-		-		-		-		-		2		(6)	(3)		(2)		1		(4)
Deferred income tax expense			31		6		7		49		6		-		-		(21)	78		-		19		97
Other			(27)		4		(5)		4		6		(1)		(2)		2	(19)		-		(19)		(38)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(9)		-		(9)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		251		251
Net income (loss) attributable to Unitholders(2)			128		25		(26)		47		(8)		1		1		(233)	(65)		-		-		(65)

																			Contribution
		Attributable to Unitholders																	from		Attributable
		Hydroelectric						Wind						Storage		Corporate		Total	equity		to non-		As per
		North						North						and					accounted		controlling		IFRS
($ MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other					investments		interests		financials(1)
Revenues			819		-		203		150		56		9		59		-	1,296		(44)		376		1,628
Other income			23		-		28		12		8		-		-		5	76		-		46		122
Direct operating costs			(285)		-		(67)		(38)		(20)		(1)		(31)		(23)	(465)		18		(105)		(552)
Share of Adjusted EBITDA from
	equity accounted investments		-		-		-		-		-		-		-		-	-		26		-		26
Adjusted EBITDA			557		-		164		124		44		8		28		(18)	907		-		317		-
Management service costs			-		-		-		-		-		-		-		(48)	(48)		-		-		(48)
Interest expense - borrowings			(179)		-		(18)		(48)		(12)		(3)		(5)		(81)	(346)		6		(89)		(429)
Current income taxes			(5)		-		(10)		-		-		-		-		-	(15)		-		(3)		(18)
Distributions attributable to
	Preferred limited partners equity		-		-		-		-		-		-		-		(1)	(1)		-		-		(1)
	Preferred equity		-		-		-		-		-		-		-		(30)	(30)		-		-		(30)
Share of interest and cash taxes from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(6)		-		(6)
Share of Funds From Operations
	attributable to non-controlling interests		-		-		-		-		-		-		-		-	-		-		(225)		(225)
Funds From Operations			373		-		136		76		32		5		23		(178)	467		-		-		-
Depreciation			(218)		-		(113)		(83)		(32)		(4)		(12)		-	(462)		9		(161)		(614)
Unrealized financial instrument loss			1		-		-		2		-		-		(1)		(15)	(13)		1		3		(9)
Deferred income tax recovery			36		-		4		16		2		-		-		20	78		-		2		80
Other			14		-		(8)		(30)		(1)		-		(4)		(39)	(68)		-		-		(68)
Share of earnings from
	equity accounted investments		-		-		-		-		-		-		-		-	-		(10)		-		(10)
Net income attributable to
	non-controlling interests		-		-		-		-		-		-		-		-	-		-		156		156
Net income (loss) attributable to Unitholders(2)			206		-		19		(19)		1		1		6		(212)	2		-		-		2

The following table presents information on a segmented basis about certain items in Brookfield Renewables statement of financial position:

																						Contribution
		Attributable to Unitholders																				from		Attributable
		Hydroelectric						Wind								Solar		Corporate		Total		equity		to non-		Total
		North						North								Storage and						accounted		controlling
(MILLIONS)		America		Colombia		Brazil		America		Europe		Brazil		Other		Other						investments		interests
As at December 31, 2017:
Property, plant and equipment, at fair value		$	11,396	$	1,303	$	1,908	$	1,798	$	482	$	304	$	11	$	1,227	$	-	$	18,429	$	(1,451)	$	10,118	$	27,096
Total assets			11,709		1,574		2,149		1,888		532		443		31		1,456		180		19,962		(1,040)		11,982		30,904
Total borrowings			3,049		447		200		1,005		233		192		9		752		2,552		8,439		(848)		4,175		11,766
Total liabilities			5,237		801		380		1,338		334		208		18		877		2,786		11,979		(1,039)		5,682		16,622
For the year ended December 31, 2017:
	Additions to property, plant and equipment		90		8		59		6		34		-		-		13		10		220		(10)		144		354
As at December 31, 2016:
Property, plant and equipment, at fair value		$	10,922	$	1,273	$	1,895	$	1,327	$	545	$	139	$	-	$	491	$	-		16,592	$	(428)	$	9,093	$	25,257
Total assets			11,219		1,577		2,059		1,389		587		153		-		561		182		17,727		(280)		10,290		27,737
Total borrowings			2,946		467		194		727		249		50		-		215		2,229		7,077		(232)		3,337		10,182
Total liabilities			5,414		824		340		990		337		51		-		268		2,418		10,642		(280)		4,703		15,065
For the year ended December 31, 2016:
	Additions to property, plant and equipment		86		9		79		3		18		1		-		18		8		222		(10)		146		358

The following table presents consolidated revenue split by geographical region:

(MILLIONS)		2017		2016		2015
United States	$	871	$	786	$	799
Colombia		797		819		-
Canada		480		442		426
Brazil		366		269		265
Europe		111		136		138
		2,625		2,452		1,628

The following table presents consolidated property, plant and equipment and equity-accounted investments split by geographical region:

(MILLIONS)		2017		2016
United States	$	11,131	$	10,163
Colombia		5,401		5,275
Canada		5,810		5,845
Brazil		3,479		2,922
Europe		1,332		1,258
Other		664		-
		27,817		25,463

XML

OTHER INCOME (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables other income for the year ended December 31 is comprised of the following:

(MILLIONS)			2017		2016		2015
Interest income and other		$	32	$	41	$	21
Gain on available for sale investments (Note 3)			15		-		-
Gains on settlement of foreign currency contracts			-		23		31
Gain on disposal(1)			-		-		53
Compensation related to expired Brazilian
	concession agreements(2)		-		-		17
		$	47	$	64	$	122

• In 2015, the sale of the 102 MW wind facility in California resulted in a gain of $53 million. Brookfield Renewable’s share of the gain was $12 million, representing the 22% interest in the facility, and is net of the cash portion of non-controlling interests.
• In 2015, concession agreements relating to two Brazilian hydroelectric facilities expired. Brookfield Renewable elected not to renew these agreements in exchange for compensation of $17 million.

XML

DIRECT OPERATING COSTS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables direct operating costs for the year ended December 31 are comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Operations, maintenance and administration		$	567	$	553	$	396
Water royalties, property taxes and other			161		149		119
Fuel and power purchases(1)			226		313		15
Energy marketing fees	27		24		23		22
		$	978	$	1,038	$	552

Fuel and power purchasesare primarily attributable to our portfolio in Colombia.

XML

OTHER (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables other for the year ended December 31 is comprised of the following:

(MILLIONS)	Notes		2017		2016		2015
Transaction costs		$	(9)	$	(22)	$	(6)
Change in fair value of property, plant and equipment	12		(33)		(36)		(45)
Unrealized loss on available-for-sale securities			-		-		(25)
Other			14		20		13
		$	(28)	$	(38)	$	(63)

XML

FOREIGN CURRENCY TRANSLATION (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables foreign currency translation for the year ended December 31 shown in the consolidated statements of comprehensive income is comprised of the following:

(MILLIONS)		Notes		2017		2016		2015
Foreign currency translation on
	Property, plant and equipment, at fair value	12	$	506	$	1,186	$	(1,975)
	Long-term debt and credit facilities			(282)		(244)		697
	Deferred income tax liabilities and assets			(82)		(157)		202
	Other assets and liabilities			48		201		(62)
			$	190	$	986	$	(1,138)

XML

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The major components of income tax recovery (expense) for the year ended December 31 are as follows:

(MILLIONS)		2017		2016		2015
Income tax (expense) recovery applicable to:
Current taxes
Attributed to the current period	$	(39)	$	(44)	$	(18)
Deferred taxes
Income taxes - origination and reversal of temporary differences	$	8	$	71	$	87
Relating to change in tax rates / imposition of new tax laws		(42)		35		6
Relating to unrecognized temporary differences and tax losses		(15)		(9)		(15)
	$	(49)	$	97	$	78
Total income tax (expense) recovery	$	(88)	$	53	$	60

The major components of deferred income tax recovery (expense) for the year ended December 31 recorded directly to OCI are as follows:

(MILLIONS)		2017		2016		2015
Deferred income taxes attributed to:
Financial instruments designated as cash flow hedges	$	(4)	$	2	$	8
Other		15		(7)		(17)
Revaluation surplus
Origination and reversal of temporary differences		(248)		(55)		(263)
Relating to changes in tax rates / imposition of new tax laws		586		19		(19)
	$	349	$	(41)	$	(291)

Brookfield Renewables effective income tax (expense) recovery for the year ended December 31 is different from its recovery at its statutory income tax rate due to the differences below:

(MILLIONS)			2017		2016		2015
Statutory income tax (expense) recovery(1)		$	(50)	$	5	$	(15)
(Reduction) increase resulting from:
	Increase in tax assets not recognized		(15)		(9)		(15)
	Deemed profit method differences in Brazil		1		(11)		10
	Differences between statutory rate and future tax rate		(38)		54		68
	Income or losses recorded not taxable to Brookfield Renewable		14		14		14
	Other		-		-		(2)
Effective income tax (expense) recovery		$	(88)	$	53	$	60

Statutory income tax expense is calculated at the domestic rates applicable to the profits in the country concerned.

The following table details the expiry date, if applicable, of the unrecognized deferred tax assets as at December 31:

(MILLIONS)		2017		2016
2018 to 2022	$	8	$	-
2023 and thereafter		108		98

The deferred tax assets and liabilities of the following temporary differences have been recognized in the consolidated financial statements for the year ended December 31:

			Amount available		Difference		Net deferred
	Non-capital		for future		between tax and		tax (liabilities)
(MILLIONS)	losses		deductions		carrying value		assets
As at January 1, 2015	$	403	$	88	$	(2,986)	$	(2,495)
Recognized in Net income (loss)		73		(11)		16		78
Recognized in equity		(1)		-		(279)		(280)
Business combination		5		-		(35)		(30)
Foreign exchange		(22)		(12)		223		189
As at December 31, 2015		458		65		(3,061)		(2,538)
Recognized in Net income (loss)		24		(10)		83		97
Recognized in equity		17		-		(48)		(31)
Business combination		-		-		(1,020)		(1,020)
Foreign exchange		-		1		(161)		(160)
As at December 31, 2016		499		56		(4,207)		(3,652)
Recognized in Net income (loss)		(97)		(5)		53		(49)
Recognized in equity		13		-		341		354
Business combination		79		-		(63)		16
Foreign exchange		14		4		(98)		(80)
As at December 31, 2017	$	508	$	55	$	(3,974)	$	(3,411)

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following table presents a reconciliation of property, plant and equipment at fair value:

							Solar and
(MILLIONS)		Notes	Hydroelectric		Wind		Other(1)		Total(2)
As at December 31, 2014			$	15,210	$	3,315	$	41	$	18,566
Additions				183		51		55		289
Acquisitions through business combinations		3		307		624		229		1,160
Disposal				-		(230)		-		(230)
Items recognized through OCI
	Change in fair value			1,141		52		16		1,209
	Foreign exchange			(1,585)		(336)		(54)		(1,975)
Items recognized through net income
	Change in fair value			(2)		(43)		-		(45)
	Depreciation			(407)		(200)		(9)		(616)
As at December 31, 2015			$	14,847	$	3,233	$	278	$	18,358
Additions				269		71		18		358
Acquisitions through business combinations		3		5,731		10		-		5,741
Items recognized through OCI
	Change in fair value			190		187		54		431
	Foreign exchange			1,114		21		51		1,186
Items recognized through net income
	Change in fair value			(17)		(10)		(9)		(36)
	Depreciation			(565)		(199)		(17)		(781)
As at December 31, 2016			$	21,569	$	3,313	$	375	$	25,257
Additions				253		95		6		354
Acquisitions through business combinations		3		-		618		627		1,245
Disposal		4		-		(338)		-		(338)
Items recognized through OCI
	Change in fair value			828		91		(32)		887
	Foreign exchange			332		177		(3)		506
Items recognized through net income
	Change in fair value			(20)		(8)		(5)		(33)
	Depreciation			(563)		(197)		(22)		(782)
As at December 31, 2017			$	22,399	$	3,751	$	946	$	27,096

• Includes solar, storage, biomass and Co-gen.
• Includes intangible assets of $13million (2016: $14 million and 2015: $13 million) and construction work in process (“CWIP”) of $601million (2016: $663 millionand 2015: $405 million).

Discount rates, terminal capitalization rates and exit dates used in the valuation methodology, are provided in the following table:

		North America		Colombia		Brazil		Europe
		2017	2016	2017	2016	2017	2016	2017	2016
Discount rate
	Contracted	4.9% - 6.0%	4.8% - 5.5%	11.3%	N/A	8.9%	9.2%	4.1% - 4.5%	4.1% - 5.0%
	Uncontracted	6.5% - 7.6%	6.6% - 7.2%	12.6%	N/A	10.2%	10.5%	5.9% - 6.3%	5.9% - 6.8%
Terminal
	capitalization rate(1)	6.2% - 7.5%	6.3% - 6.9%	0.126	N/A	N/A	N/A	NA	N/A
Exit date		2037	2036	2037	N/A	2032	2031	2031	2031

• Discount rates are not adjusted for asset specific risks.
• The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

The following table summarizes the impact of a change in discount rates, electricity prices and terminal capitalization rates on the fair value of property, plant and equipment:

	2017
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(710)	$	(130)	$	(50)	$	(20)	$	(910)
25 bps decrease in discount rates		770		130		50		20		970
5% increase in future electricity prices		620		310		70		20		1,020
5% decrease in future electricity prices		(620)		(310)		(70)		(20)		(1,020)
25 bps increase in terminal capitalization rate(1)		(180)		(50)		-		-		(230)
25 bps decrease in terminal capitalization rate(1)		190		50		-		-		240
	2016
	North
(MILLIONS)	America		Colombia		Brazil		Europe		Total
25 bps increase in discount rates	$	(670)	$	N/A	$	(50)	$	(20)	$	(740)
25 bps decrease in discount rates		730		N/A		50		20		800
5% increase in future electricity prices		540		N/A		70		20		630
5% decrease in future electricity prices		(540)		N/A		(70)		(20)		(630)
25 bps increase in terminal capitalization rate(1)		(180)		N/A		-		-		(180)
25 bps decrease in terminal capitalization rate(1)		190		N/A		-		-		190

The terminal capitalization rate applies only to hydroelectric assets in the United States, Canada and Colombia.

The following table summarizes the percentage of total generation contracted under power purchase agreements, power prices from long-term power purchase agreements that are linked specifically to the related power generating assets, and the estimates of future electricity prices:

	North America		Colombia		Brazil		Europe
1 - 10 years		58%		17%		66%		78%
11 - 20 years		42%		-		57%		35%

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	84	COP	211,000	R$	274	€	90
11 - 20 years		88		-		407		107

Assumes nominal prices based on weighted-average generation.

Per MWh(1)	North America		Colombia		Brazil		Europe
1 - 10 years	$	63	COP	238,000	R$	309	€	78
11 - 20 years		112		339,000		458		95

Assumes nominal prices based on weighted-average generation.

Had Brookfield Renewables revalued property, plant and equipment been measured on a historical cost basis, the carrying amounts, net of accumulated depreciation would have been as follows at December 31:

(MILLIONS)		2017		2016
Hydroelectric	$	12,740	$	12,761
Wind		3,030		2,688
Solar and other(1)		933		319
	$	16,703	$	15,768

Includes biomass and Co-gen.

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The composition of debt obligations as at December 31 is presented in the following table:

		2017						2016
		Weighted-average				Estimated		Weighted-average				Estimated
		Interest	Term	Carrying		Fair		Interest	Term	Carrying		Fair
(MILLIONS EXCEPT AS NOTED)		rate (%)	(years)	value		value		rate (%)	(years)	value		value
Corporate borrowings
	Series 3 (C$200)	5.3	0.8	$	159	$	163	5.3	1.8	$	149	$	158
	Series 4 (C$150)	5.8	18.9		119		144	5.8	19.9		111		132
	Series 7 (C$450)	5.1	2.8		358		382	5.1	3.8		334		368
	Series 8 (C$400)	4.8	4.1		318		344	4.8	5.1		298		331
	Series 9 (C$400)	3.8	7.4		318		321	3.8	8.4		298		308
	Series 10 (C$500)	3.6	9.0		398		400	3.6	10.0		372		380
		4.5	6.4	$	1,670	$	1,754	4.5	7.4	$	1,562	$	1,677
Credit facilities		2.6	4.5	$	887	$	887	1.9	4.5	$	673	$	673
Subsidiary borrowings
	Hydroelectric	6.3	8.8	$	6,392		6,813	6.9	7.8	$	6,249		6,600
	Wind	5.8	9.7		2,211		2,343	4.6	13.1		1,735		1,879
	Solar and other	11.0	8.2		682		682	8.9	18.8		41		41
		6.5	9.0	$	9,285	$	9,838	6.4	9.0	$	8,025	$	8,520
Total debt					11,842		12,479				10,260		10,870
Add: Unamortized premiums(1)					1						2
Less: Unamortized financing fees(1)					(77)						(80)
Less: Current portion(2)(3)					(1,676)						(1,034)
				$	10,090					$	9,148

The following table outlines changes in Brookfield Renewables borrowings for the year ended December 31:

			Cash flows from		Non-cash
(MILLIONS)	Jan 1		financing activities		Acquisition		Disposal		Other(1)		Dec 31
2017	$	10,182	$	267	$	1,188	$	(173)	$	302	$	11,766
2016	$	7,338	$	1,502	$	1,104	$	-	$	238	$	10,182

Future repayments of Brookfield Renewables debt obligations, for each of the next five years and thereafter are as follows:

(MILLIONS)		2018		2019		2020		2021		2022		Thereafter		Total
Corporate borrowings and
	credit facilities	$	159	$	202	$	377	$	-	$	984	$	835	$	2,557
Subsidiary borrowings
	Hydro		206		366		1,013		822		317		3,668		6,392
	Wind		665		115		122		125		132		1,052		2,211
	Solar and other		646		3		3		2		4		24		682
		$	1,676	$	686	$	1,515	$	949	$	1,437	$	5,579		11,842
Equity-accounted investments		$	110	$	116	$	112	$	716	$	602	$	3,003	$	4,659
														$	16,501

The following table outlines change in financing fees for the year ended December 31:

(MILLIONS)			2017		2016		2015
Corporate borrowings
	Unamortized financing fees, beginning of year	$	6	$	5	$	5
	Additional financing fees		-		2		1
	Amortization of financing fees		(1)		(1)		(1)
	Unamortized financing fees, end of year	$	5	$	6	$	5
Subsidiary borrowings
	Unamortized financing fees, beginning of year	$	74	$	54	$	66
	Additional financing fees		16		41		7
	Amortization of financing fees		(14)		(17)		(15)
	Foreign exchange translation and other		(4)		(4)		(4)
	Unamortized financing fees, end of year	$	72	$	74	$	54
Total		$	77	$	80	$	59

The following table summarizes the available portion of credit facilities as at December 31:

(MILLIONS)		2017		2016
Authorized credit facilities	$	2,090	$	1,890
Draws on credit facilities(1)		(685)		(673)
Issued letters of credit		(193)		(250)
Available portion of credit facilities	$	1,212	$	967

XML

NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables non-controlling interests are comprised of the following as at December 31:

(MILLIONS)			2017		2016
Participating non-controlling interests - in operating subsidiaries		$	6,298	$	5,589
General partnership interest in a holding subsidiary held by Brookfield			58		55
Participating non-controlling interests - in a holding subsidiary -
	Redeemable/Exchangeable units held by Brookfield		2,843		2,680
Preferred equity			616		576
		$	9,815	$	8,900

The net change in participating non-controlling interests in operating entities is as follows:

												Isagen
		Brookfield								Isagen		public
		Americas		Brookfield		Brookfield			The	institu-		non-con
	Infrastructure			Infrastructure		Infrastructure		Catalyst		tional		-trolling
(MILLIONS)		Fund		Fund II		Fund III		Group		investors		interests		Other		Total
As at December 31, 2014		$	914	$	937	$	-	$	126	$	-	$	-	$	85	$	2,062
Net income			26		27		-		14		-		-		2		69
OCI			89		144		-		(12)		-		-		(17)		204
Capital contributions			-		460		-		-		-		-		-		460
Distributions			(70)		(126)		-		(7)		-		-		(5)		(208)
Other			(1)		(1)		-		-		-		-		2		-
As at December 31, 2015		$	958	$	1,441	$	-	$	121	$	-	$	-	$	67	$	2,587
Net (loss) income			(18)		(16)		15		16		47		19		2		65
OCI			46		228		-		2		148		205		6		635
Capital contributions			-		74		1,074		-		1,473		-		-		2,621
Acquisition			-		-		-		-		-		1,417		-		1,417
Distributions			(23)		(73)		(7)		(12)		-		-		(4)		(119)
MTO adjustments			-		-		3		-		7		(1,627)		-		(1,617)
As at December 31, 2016		$	963	$	1,654	$	1,085	$	127	$	1,675	$	14	$	71	$	5,589
Net (loss) income			(29)		(13)		33		12		47		-		3		53
OCI			(76)		269		111		2		78		(1)		-		383
Capital contributions			-		89		186		-		19		-		-		294
Acquisition			-		-		525		-		-		-		-		525
Distributions			(8)		(317)		(88)		(7)		(115)		-		(4)		(539)
Purchase of Isagen shares			-		-		(1)		-		(5)		5		-		(1)
Other			-		-		1		-		2		(9)		-		(6)
As at December 31, 2017		$	850	$	1,682	$	1,852	$	134	$	1,701	$	9	$	70	$	6,298
Interests held by third parties			75-80%		50-60%		23-71%		25%		53%		0.5%	21-50%

The following tables summarize certain financial information of operating subsidiaries that have non-controlling interests that are material to Brookfield Renewable:

		Brookfield
		Americas		Brookfield		Brookfield
		Infrastructure		Infrastructure		Infrastructure		The Catalyst
(MILLIONS)		Fund		Fund II		Fund III(1)		Group		Isagen(2)		Other		Total
Interests held by third parties			75-80%		50-60%		69-71%		25%		76%		21-50%
Place of business		United States,Brazil		United States,Brazil,Europe		United States, Brazil, India, China, South Africa		United States		Colombia		United States,Brazil,Canada
For the year ended
	December 31, 2015:
Revenue		$	136	$	402	$	-	$	160	$	-	$	30	$	728
Net income			34		49		-		56		-		8		147
Total comprehensive
	income (loss)		144		247		-		8		-		(51)		348
Net income allocated to
	non-controlling interests		26		27		-		14		-		2		69
For the year ended
	December 31, 2016:
Revenue		$	118	$	394	$	28	$	164	$	819	$	27	$	1,550
Net (loss) income			(22)		(23)		(8)		62		110		5		124
Total comprehensive
	income (loss)		37		356		(8)		70		502		31		988
Net (loss) income allocated to
	non-controlling interests		(18)		(16)		(5)		16		86		2		65
As at December 31, 2016:
Property, plant and
	equipment, at fair value	$	1,807	$	4,816	$	848	$	970	$	5,275	$	417	$	14,133
Total assets			1,865		5,125		855		1,072		6,539		428		15,884
Total borrowings			571		1,881		313		450		1,924		41		5,180
Total liabilities			631		2,235		319		466		3,396		60		7,107
Carrying value of non-
	controlling interests	$	963	$	1,654	$	383	$	127	$	2,391	$	71	$	5,589
For the year ended
	December 31, 2017:
Revenue		$	123	$	430	$	53	$	135	$	797	$	32	$	1,570
Net (loss) income			(34)		(20)		18		47		89		7		107
Total comprehensive
	(loss) income		(133)		529		126		57		236		-		815
Net (loss) income allocated
	to non-controlling interests		(29)		(13)		13		12		67		3		53
As at December 31, 2017:
Property, plant and
	equipment, at fair value	$	1,667	$	5,153	$	2,149	$	964	$	5,401	$	411	$	15,745
Total assets			1,718		5,430		3,294		1,066		6,526		426		18,460
Total borrowings			556		2,040		1,502		413		1,858		42		6,411
Total liabilities			628		2,422		1,678		432		3,336		63		8,559
Carrying value of non-
	controlling interests	$	850	$	1,682	$	1,138	$	134	$	2,424	$	70	$	6,298

• Excludes information relating to Isagen which is presented separately.
• The total third parties ownership interest in Isagen as of December 31, 2017 was 75.9% and comprised of Brookfield Infrastructure Fund III: 22.9%, Isagen Institutional investors 52.5% and Isagen public non-controlling interests: 0.5%.

The composition of the distributions for the year ended December 31 is presented in the following table:

(MILLIONS)			2017		2016
General partnership interest in a holding
	subsidiary held by Brookfield	$	5	$	5
Incentive distribution			30		19
		$	35	$	24
Participating non-controlling interests - in a
	holding subsidiary - Redeemable/
	Exchangeable units held by Brookfield	$	243	$	232
		$	278	$	256

The following table summarizes certain financial information regarding General partnership interest in a holding subsidiary held by Brookfield and Participating non-controlling interests in a holding subsidiary Redeemable or Exchangeable units held by Brookfield:

(MILLIONS)		2017		2016		2015
For the year ended December 31:
Revenue		$	2,625	$	2,452	$	1,628
Net income			51		40		103
Comprehensive income			1,401		1,369		5
Net income allocated to(1):
	GP interest		(1)		-		-
	Redeemable/Exchangeable partnership units		(23)		(29)		1
As at December 31:
Property, plant and equipment, at fair value		$	27,096	$	25,257
Total assets			30,904		27,737
Total borrowings			11,766		10,182
Total liabilities			16,622		15,065
Carrying value of(2):
	GP interest		58		55
	Redeemable/Exchangeable partnership units		2,843		2,680

• Allocated based on weighted-average GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 173.5 million, respectively (2016: 2.7 million, 129.7 million, and 156.4 million, respectively and 2015: 2.7 million, 129.7 million, and 143.3million, respectively).
• Allocated based on outstanding GP interest, Redeemable/Exchangeable partnership units and LP Units of 2.7 million, 129.7 million, and 180.4million, respectively (2016: 2.7 million, 129.7 million, and 166.8million, respectively).

Brookfield Renewables preferred equity as at December 31 consists of Class A Preference Shares of Brookfield Renewable Power Preferred Equity Inc. (BRP Equity) as follows:

			Earliest	Dividends declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	dividend	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 1 (C$136)	5.45	3.36	Apr 30, 2020	$	4	$	3	$	108	$	101
Series 2 (C$113)(1)	4.51	3.63	Apr 30, 2020		3		3		90		84
Series 3 (C$249)	9.96	4.40	Jul 31, 2019		8		8		197		185
Series 5 (C$103)	4.11	5.00	Apr 30, 2018		4		4		82		76
Series 6 (C$175)	7.00	5.00	Jul 31, 2018		7		7		139		130
	31.03			$	26	$	25	$	616	$	576

Dividend rate represents annualized distribution based on the most recent quarterly floating rate.

XML

PREFERRED LIMITED PARTNERS EQUITY (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Disclsoure of preferred limited partners equity [text block]

			Earliest	Distributions declared
		Cumulative	permitted	for the year ended
(MILLIONS EXCEPT	Shares	distribution	redemption	December 31
AS NOTED)	outstanding	rate (%)	date	2017		2016		2017		2016
Series 5 (C$72)	2.89	5.59	Apr 30, 2018	$	4	$	3	$	49	$	49
Series 7 (C$175)	7.00	5.50	Jan 31, 2021		8		7		128		128
Series 9 (C$200)	8.00	5.75	Jul 31, 2021		8		5		147		147
Series 11 (C$250)	10.00	5.00	Apr 30, 2022		8		-		187		-
	27.89			$	28	$	15	$	511	$	324

XML

LIMITED PARTNERS EQUITY (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The composition of the distributions for the year ended December 31 is presented in the following table:

(MILLIONS)			2017		2016
General partnership interest in a holding
	subsidiary held by Brookfield	$	5	$	5
Incentive distribution			30		19
		$	35	$	24
Participating non-controlling interests - in a
	holding subsidiary - Redeemable/
	Exchangeable units held by Brookfield	$	243	$	232
		$	278	$	256

XML

GOODWILL (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following table provides a reconciliation of goodwill:

(MILLIONS)	2017		2016
Balance, beginning of year	$	896	$	-
Acquired through business acquisition		-		799
Foreign exchange		5		97
Balance, end of year	$	901	$	896

XML

CAPITAL MANAGEMENT (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables strategy during December 31, 2016, which was unchanged from 2015, was to maintain the measure set out in the following schedule as at December 31:

(MILLIONS)			2017		2016
Total debt
	Current portion of long-term debt(1)	$	1,676	$	1,034
	Long-term debt and credit facilities		10,090		9,148
			11,766		10,182
Deferred income tax liabilities, net(2)			3,411		3,652
Equity			14,282		12,672
Total capitalization		$	29,459	$	26,506
Debt to total capitalization			40%		38%

• As part of the TerraForm Global transaction, Brookfield Renewable acquired $841 million of borrowings that were immediately classified as current due to the change of control provision allowing the holders to direct TerraForm Global to redeem the bonds at 101% of par value in the first quarter of 2018. Brookfield Renewable redeemed these borrowings at approximately 107%of par value in the first quarter of 2018 with a combination of available cash on hand and proceeds from note offering that closed on February 22, 2018. See Note 20 – Cash and Cash Equivalents and Note 31 – Subsequent Events
• Deferred income tax liabilities less deferred income tax assets.

XML

EQUITY-ACCOUNTED INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following are Brookfield Renewables equity-accounted investments as at December 31:

	Principal place	Ownership	Carrying value
	of business	interest
(MILLIONS)		%		2017		2016
FHH (Guernsey) Limited	Europe	25	$	245	$	-
TerraForm Power Inc.(1)	United States,Canada	16		212		-
Bear Swamp Power Co. L.L.C.	United States	50		173		114
Galera Centrais Eletricas S.A.	Brazil	50		28		29
Pingston Power Inc.	Canada	50		57		58
Brookfield Infrastructure Fund II Investees	United States,Europe	14 - 50		6		5
			$	721	$	206

The following table outlines the changes in Brookfield Renewables equity-accounted investments for the year ended December 31:

(MILLIONS)		2017		2016		2015
Balance, beginning of year		$	206	$	197	$	273
Share of net income			2		-		10
Share of OCI
	Revaluation of property, plant and equipment		54		7		96
	Other		2		1		-
Dividends declared			(31)		(6)		(19)
Capital distributions, net			-		-		(144)
Acquisition of European Storage (Note 3)			248		-		-
Acquisition of TerraForm Power (Note 3)			221		-		-
Foreign exchange translation			19		7		(19)
Balance, end of year		$	721	$	206	$	197

The following tables summarize certain financial information of equity-accounted investments:

(MILLIONS)					2017		2016
As at December 31:
Current assets				$	477	$	45
Property, plant and equipment, at fair value					8,098		864
Other assets					213		70
Current liabilities					687		42
Long-term debt					4,294		463
Other liabilities					958		71
(MILLIONS)			2017		2016		2015
For the year ended December 31
Revenue		$	310	$	74	$	89
Net (loss) income			(24)		-		19
Share of net income (loss)
	Cash earnings		29		9		20
	Non-cash loss		(27)		(9)		(10)

XML

CASH AND CASH EQUIVALENTS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Brookfield Renewables cash and cash equivalents as at December 31 are as follows:

(MILLIONS)		2017		2016
Cash(1)	$	790	$	210
Short-term deposits		9		13
	$	799	$	223

XML

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

As at December 31, Brookfield Renewable had commitments for future minimum lease payments under non-cancellable leases which fall due as follows:

(MILLIONS)
2018	$	33
2019		32
2020		31
2021		30
2022		27
Thereafter		262
Total	$	415

As at December 31, letters of credit issued by Brookfield Renewable along with institutional investors and its subsidiaries were as follows:

(MILLIONS)		2017	2016
Brookfield Renewable along with institutional investors	$	76	$	66
Brookfield Renewable's subsidiaries		468		483
	$	544	$	549

XML

RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following table reflects the related party agreements and transactions in the consolidated statements of income, for the year ended December 31:

(MILLIONS)			2017		2016		2015
Revenues
	Power purchase and revenue agreements	$	601	$	527	$	469
	Wind levelization agreement		6		8		6
		$	607	$	535	$	475
Direct operating costs
	Energy purchases	$	(13)	$	(3)	$	(5)
	Energy marketing fee		(24)		(23)		(22)
	Insurance services		(19)		(20)		(30)
		$	(56)	$	(46)	$	(57)
Management service costs		$	(82)	$	(62)	$	(48)

XML

SUPPLEMENTAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The net change in working capital balances for the year ended December 31 shown in the consolidated statements of cash flows is comprised of the following:

(MILLIONS)		2017		2016		2015
Trade receivables and other current assets	$	(40)	$	30	$	(72)
Accounts payable and accrued liabilities		32		(160)		2
Other assets and liabilities		(17)		(7)		8
	$	(25)	$	(137)	$	(62)

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

Actuarial assumptions as at December 31:

		Defined benefit			Non-pension			Defined benefit			Non-pension			Defined benefit			Non-pension
		pension plans			benefit plans			pension plans			benefit plans			pension plans			benefit plans
		2017						2016						2015
		(%)						(%)						(%)
Discount rate		2.4	-	7.3	3.7	-	7.1	2.2	-	7.3	4.1	-	7.3	2.9	-	4.7	4.2	-	4.7
Rate of price inflation		1.5	-	3.5	N/A			1.5	-	3.5	N/A			2.0	-	2.5	N/A
Rate of compensation
	increases	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	4.0	2.5	-	3.0	2.5	-	3.0
Health care trend rate(1)		N/A			5.3	-	6.9	N/A			5.3	-	6.9	N/A			6.3	-	7.1

Expense recognized in the consolidated statements of income and consolidated statements of comprehensive income for the year ended December 31:

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Current service costs			$	3	$	1	$	3	$	1	$	3	$	1
Past service costs (recovery)				(1)		-		-		-		1		(1)
Interest expense				2		3		2		3		1		2
Administrative expenses				1		-		1		-		1		-
Recognized in consolidated
	statement of income			5		4		6		4		6		2
Remeasurement of the net
	defined benefit liability:
	Return on plan assets			(8)		-		(2)		-		(1)		-
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Recognized in consolidated
	statement of comprehensive
	income			-		2		2		-		1		(6)
Total			$	5	$	6	$	8	$	4	$	7	$	(4)

The amounts included in the consolidated statements of financial position arising from Brookfield Renewables obligations in respect of its defined benefit plans are as follows:

		Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
		pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)			2017				2016				2015
Present value of defined
	benefit obligation	$	172	$	57	$	158	$	53	$	124	$	35
Fair value of plan assets			(135)		(5)		(119)		(5)		(103)		-
Net liability		$	37	$	52	$	39	$	48	$	21	$	35

			Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
			pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)				2017				2016				2015
Balance, beginning of year			$	158	$	53	$	124	$	35	$	128	$	43
Current service cost				3		1		3		1		3		1
Past service (recovery) cost				(1)		-		-		-		1		(1)
Interest expense				7		3		7		3		5		2
Remeasurement losses (gains)
	Actuarial changes arising
		from changes in
		demographic assumptions		1		(2)		(1)		(1)		2		(5)
	Actuarial changes arising
		from changes in
		financial assumptions		7		3		5		1		(2)		(1)
	Experience adjustments			-		1		-		-		2		-
Benefits paid				(7)		(2)		(8)		(2)		(5)		(2)
Business combination				-		-		25		14		-		-
Exchange differences				4		-		3		2		(10)		(2)
Balance, end of year			$	172	$	57	$	158	$	53	$	124	$	35

The movement in the fair value of plan assets for the year ended December 31 is as follows:

	Defined benefit		Non-pension		Defined benefit		Non-pension		Defined benefit		Non-pension
	pension plans		benefit plans		pension plans		benefit plans		pension plans		benefit plans
(MILLIONS)		2017				2016				2015
Balance, beginning of year	$	119	$	5	$	103	$	-	$	108	$	-
Interest income		5		-		5		-		4		-
Return on plan assets		8		-		2		-		1		-
Employer contributions		5		2		7		3		5		2
Business combination		-		-		9		4		-		-
Benefits paid		(7)		(2)		(8)		(2)		(5)		(2)
Exchange differences		5		-		1		-		(10)		-
Balance, end of year	$	135	$	5	$	119	$	5	$	103	$	-

The composition of plan assets as at December 31 is as follows:

		2017	2016
		(%)	(%)
Asset category:
	Cash and cash equivalents	2	5
	Equity securities	54	50
	Debt securities	44	44
	Real estate	-	1
		100	100

XML

SUBSIDIARY PUBLIC ISSUERS (Tables)

12 Months Ended

Dec. 31, 2017

Table Text Block [Abstract]

The following tables provide consolidated summary balance sheet infromation for Brookfield Renewable, BRP Equity, and Finco:

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
As at December 31, 2017:
Current assets		$	32	$	412	$	1,691	$	525	$	2,816	$	(3,810)	$	1,666
Long-term assets			4,483		262		-		20,142		29,508		(25,157)		29,238
Current liabilities			43		7		180		3,024		3,071		(3,811)		2,514
Long-term liabilities			-		-		1,505		693		12,670		(760)		14,108
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		6,298		-		6,298
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,843		-		-		2,843
Preferred equity			-		616		-		-		-		-		616
Preferred limited partners' equity			511		-		-		516		-		(516)		511
As at December 31, 2016:
Current assets		$	26	$	-	$	1,581	$	150	$	2,092	$	(2,942)	$	907
Long-term assets			3,779		620		-		18,415		27,250		(23,234)		26,830
Current liabilities			33		9		19		2,971		1,644		(2,943)		1,733
Long-term liabilities			-		-		1,556		738		12,775		(1,737)		13,332
Participating non-controlling
	interests - in operating
	subsidiaries		-		-		-		-		5,589		-		5,589
Participating non-controlling
	interests -in a holding subsidiary
	- Redeemable/Exchangeable
	units held by Brookfield		-		-		-		2,680		-		-		2,680
Preferred equity			-		576		-		-		-		-		576
Preferred limited partners' equity			324		-		-		324		-		(324)		324

• Includes investments in subsidiaries under the equity method.
• Includes BRELP, BRP Bermuda Holdings I Limited, Brookfield BRP Holdings (Canada) Inc. and Brookfield BRP Europe Holdings Limited, together the “Holding Entities”.
• Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco and the Holding Entities.
• Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

The following tables provide consolidated summary Income Statement infromation for Brookfield Renewable, BRP Equity, and Finco:

														Brookfield
		Brookfield		BRP				Holding		Other		Consolidating		Renewable
(MILLIONS)		Renewable(1)		Equity		Finco		Entities(1)(2)		Subsidiaries(1)(3)		adjustments(4)		consolidated
For the year ended
	December 31, 2017
Revenues		$	-	$	-	$	-	$	-	$	2,625	$	-	$	2,625
Net income (loss)			(4)		10		(1)		(435)		631		(150)		51
For the year ended
	December 31, 2016
Revenues		$	-	$	-	$	-	$	1	$	2,451	$	-	$	2,452
Net income (loss)			(20)		-		(1)		(100)		558		(397)		40
For the year ended
	December 31, 2015
Revenues		$	-	$	-	$	-	$	8	$	1,620	$	-	$	1,628
Net income (loss)			2		-		(1)		(42)		235		(91)		103

• Includes investments in subsidiaries under the equity method.
• Includes the Holding Entities.
• Includes subsidiaries of Brookfield Renewable, other than BRP Equity, Finco, and the Holding Entities.
• Includes elimination of intercompany transactions and balances necessary to present Brookfield Renewable on a consolidated basis.

XML

PRINCIPAL SUBSIDIARIES (Details)	12 Months Ended
	Dec. 31, 2017
Alta Wind VIII LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
BIF II Safe Harbor Holdings LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
BIF III Holtwood LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
BRE GLBL Holdings L.P.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Bermuda
Percentage of voting securities owned or controlled	100.00%
BRI Green Energy Limited
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Republic of Ireland
Percentage of voting securities owned or controlled	100.00%
Brookfield BRP Canada Corp.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Alberta
Percentage of voting securities owned or controlled	100.00%
Brookfield Energia Comercializadora Ltda
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Brazil
Percentage of voting securities owned or controlled	100.00%
Brookfield Power US Holding America Co.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Brookfield Power Wind Prince LP
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Ontario
Percentage of voting securities owned or controlled	100.00%
Brookfield Renewable UK Hydro Limited
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	England and Wales
Percentage of voting securities owned or controlled	100.00%
Brookfield Smoky Mountain Hydropower LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Brookfield White Pine Hydro LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Catalyst Old River Hydroelectric Limited Partnership
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Louisiana
Percentage of voting securities owned or controlled	75.00%
Erie Boulevard Hydropower, L.P.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Granite Reliable Power, LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	89.50%
Great Lakes Hydro America, LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Great Lakes Power Limited
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Ontario
Percentage of voting securities owned or controlled	100.00%
Hawks Nest Hydro LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Isagen S.A. E.S.P.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Colombia
Percentage of voting securities owned or controlled	99.50%
Itiquira Energetica S.A.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Brazil
Percentage of voting securities owned or controlled	100.00%
Kwagis Power Limited Partnership
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	British Columbia
Percentage of voting securities owned or controlled	75.00%
Lievre Power L.P.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Québec
Percentage of voting securities owned or controlled	100.00%
Mississagi Power Trust
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Québec
Percentage of voting securities owned or controlled	100.00%
Orion Canadian Holdings 1 AIV L.P.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Ontario
Percentage of voting securities owned or controlled	100.00%
PEA - Parque Eolico da Serra, Unipessola S.A.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Portugal
Percentage of voting securities owned or controlled	100.00%
Powell River Energy Inc.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Canada
Percentage of voting securities owned or controlled	100.00%
Rumford Falls Hydro LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Delaware
Percentage of voting securities owned or controlled	100.00%
Safe Harbor Water Power Corporation
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Pennsylvania
Percentage of voting securities owned or controlled	100.00%
Tangara Energia S.A.
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Brazil - São Paulo
Percentage of voting securities owned or controlled	100.00%
Windstar Energy, LLC
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	California
Percentage of voting securities owned or controlled	100.00%
2016 Comber Wind Limited Partnership
Disclosure of subsidiaries [line items]
Jurisdiction of Incorporation or Organization	Ontario
Percentage of voting securities owned or controlled	100.00%

XML

ACQUISITIONS (Details) € in Millions, £ in Millions, BRL in Millions, $ in Millions		1 Months Ended											12 Months Ended
	Jan. 22, 2016 GWh	Dec. 31, 2017 USD ($)	Oct. 31, 2017 USD ($)	Aug. 31, 2017 GBP (£)	Aug. 31, 2017 USD ($)	Feb. 28, 2017	Sep. 30, 2016 USD ($)	Apr. 30, 2016 USD ($) GWh	Jan. 31, 2016 USD ($)	Jun. 30, 2015 USD ($) MW	Feb. 28, 2015 EUR (€) GWh MW	Nov. 30, 2014 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Aug. 31, 2017 USD ($)	Sep. 30, 2016 EUR (€)	Sep. 30, 2016 USD ($)	Jan. 31, 2016 BRL	Jan. 31, 2016 USD ($)	Jun. 30, 2015 GBP (£)	Jun. 30, 2015 USD ($)	Feb. 28, 2015 USD ($)	Nov. 30, 2014 BRL	Nov. 30, 2014 USD ($)
Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Gain (loss) on reclassification		$ 2	$ 13
Acquisition costs incurred and capitalized			$ 1
Brookfield Renewable | Acqusitions Completed In 2017
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents		611
Restricted cash		90
Trade receivables and other current assets		63
Financial instruments		20
Property, plant and equipment, at fair value		1,245
Deferred tax assets		18
Other long-term assets		94
Current liabilities		77
Current portion of long-term debt		1,183
Financial instruments		15
Long-term debt		5
Deferred income tax liabilities		17
Other long-term liabilities		54
Non-controlling interests		1
Fair value of net assets acquired		789
Brookfield Renewable | Acqusitions Completed In 2016
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents													$ 117
Restricted cash													0
Trade receivables and other current assets													177
Property, plant and equipment, at fair value													5,741
Other long-term assets													15
Current liabilities													467
Long-term debt													899
Deferred income tax liabilities													1,020
Other long-term liabilities													149
Non-controlling interests													1,417
Fair value of net assets acquired													2,098
Goodwill													799
Purchase price													2,897
Brookfield Renewable | Acqusitions Completed In 2015
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														$ 19
Restricted cash														21
Trade receivables and other current assets														20
Property, plant and equipment, at fair value														1,147
Current liabilities														41
Long-term debt														391
Other long-term liabilities														28
Non-controlling interests														16
Fair value of net assets acquired														731
FHH Guernsey Ltd | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree				FHH Guernsey Ltd	FHH Guernsey Ltd
Date of acquisition				August 2017	August 2017
Percentage of voting equity interests acquired				25.00%											25.00%
Percentage of voting equity interests Retained by Brookfield				7.00%											7.00%
Consideration transferred				£ 194											$ 248
Acquisition costs incurred and capitalized				£ 1	$ 1
TerraForm Power | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree			TerraForm Power
Date of acquisition			October 2017
Percentage of voting equity interests acquired			51.00%
Percentage of voting equity interests Retained by Brookfield			16.00%
Consideration transferred			$ 203
European Wind | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree						European Wind
Date of acquisition						February 2017
Percentage of voting equity interests acquired						100.00%
Percentage of voting equity interests Retained by Brookfield				40.00%											40.00%
Total cash consideration transferred				£ 24											$ 32
Acquisition costs incurred and capitalized					$ 1
European Wind | Brookfield Renewable | Acqusitions Completed In 2017
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents		0
Restricted cash		0
Trade receivables and other current assets		1
Financial instruments		0
Property, plant and equipment, at fair value		37
Deferred tax assets		0
Other long-term assets		0
Current liabilities		4
Current portion of long-term debt		0
Financial instruments		0
Long-term debt		0
Deferred income tax liabilities		2
Other long-term liabilities		0
Non-controlling interests		0
Fair value of net assets acquired		32
Terraform Global
Disclosure of detailed information about business combination [line items]
Consideration transferred		657
Fair Value of Interest Held at Acquisition Date		$ 100
Terraform Global | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree		TerraForm Global
Date of acquisition		December 2017
Percentage of voting equity interests acquired		100.00%
Percentage of voting equity interests Retained by Brookfield		31.00%
Revenue of acquiree since acquisition date		$ 250
Consideration transferred		202
Fair Value of Interest Held at Acquisition Date		30
Acquisition costs incurred and capitalized		1
Terraform Global | Brookfield Renewable | Acqusitions Completed In 2017
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents		611
Restricted cash		90
Trade receivables and other current assets		62
Financial instruments		20
Property, plant and equipment, at fair value		1,208
Deferred tax assets		18
Other long-term assets		94
Current liabilities		73
Current portion of long-term debt		1,183
Financial instruments		15
Long-term debt		5
Deferred income tax liabilities		15
Other long-term liabilities		54
Non-controlling interests		1
Fair value of net assets acquired		$ 757
Colombia Portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Percentage of voting equity interests acquired		99.50%
Colombia Portfolio | Brookfield Renewable | Acqusitions Completed In 2016
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents													113
Restricted cash													0
Trade receivables and other current assets													174
Property, plant and equipment, at fair value													4,772
Other long-term assets													15
Current liabilities													463
Long-term debt													899
Deferred income tax liabilities													1,019
Other long-term liabilities													149
Non-controlling interests													1,417
Fair value of net assets acquired													1,127
Goodwill													799
Purchase price													1,926
Isagen S.A. E.S.P. | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree	Isagen S.A. E.S.P
Date of acquisition	January 22, 2016
Percentage of voting equity interests acquired	57.60%	99.50%
Percentage of voting equity interests Retained by Brookfield		24.00%
Revenue of acquiree since acquisition date													900
Annual generation Energy, GWh | GWh	15,000
Acquisition costs incurred and capitalized													13
Brazil portfolio
Disclosure of detailed information about business combination [line items]
Consideration transferred														588
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														19
Restricted cash														16
Trade receivables and other current assets														16
Property, plant and equipment, at fair value														854
Current liabilities														(21)
Long-term debt														(280)
Other long-term liabilities														0
Non-controlling interests														(16)
Brazil portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Deferred consideration																		BRL 35	$ 9
Impact of the foreign currency contracts																		24	6
Brazil portfolio | Brookfield Renewable | Acqusitions Completed In 2016
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents													4
Restricted cash													0
Trade receivables and other current assets													2
Property, plant and equipment, at fair value													100
Other long-term assets													0
Current liabilities													3
Long-term debt													0
Deferred income tax liabilities													0
Other long-term liabilities													0
Non-controlling interests													0
Fair value of net assets acquired													103
Goodwill													0
Purchase price													103
Brazil portfolio | Brookfield Renewable | Acqusitions Completed In 2015
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														19
Restricted cash														16
Trade receivables and other current assets														16
Property, plant and equipment, at fair value														854
Current liabilities														21
Long-term debt														280
Other long-term liabilities														0
Non-controlling interests														16
Fair value of net assets acquired														$ 588
51 MW hydroelectric portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree									51 MW hydroelectric
Date of acquisition									January 2016
Total cash consideration transferred																		355	88
Consideration transferred																		BRL 417	$ 103
Acquisition costs incurred and capitalized									$ 1
488 MW portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree														488 MW portfolio
Date of acquisition														November 2014
Percentage of voting equity interests Retained by Brookfield																							40.00%	40.00%
Total cash consideration transferred																							BRL 1,717	$ 541
Revenue of acquiree since acquisition date														$ 93
Consideration transferred																							1,867	588
Acquisition costs incurred and capitalized												$ 2
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Non-controlling interests																							BRL 50	$ 16
North America portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Acquisition costs incurred and capitalized								$ 6
Pennsylvania Hydro | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree								Pennsylvania Hydro
Date of acquisition								April 2016
Percentage of voting equity interests Retained by Brookfield								28.60%
Total cash consideration transferred								$ 859
Revenue of acquiree since acquisition date													46
Annual generation Energy, GWh | GWh								1,109
Pennsylvania Portfolio | Brookfield Renewable | Acqusitions Completed In 2016
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents													0
Restricted cash													0
Trade receivables and other current assets													1
Property, plant and equipment, at fair value													859
Other long-term assets													0
Current liabilities													1
Long-term debt													0
Deferred income tax liabilities													0
Other long-term liabilities													0
Non-controlling interests													0
Fair value of net assets acquired													859
Goodwill													0
Purchase price													859
Ireland Portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Acquisition costs incurred and capitalized							$ 1
Ireland Portfolio | Brookfield Renewable | Acqusitions Completed In 2016
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents													0
Restricted cash													0
Trade receivables and other current assets													0
Property, plant and equipment, at fair value													10
Other long-term assets													0
Current liabilities													0
Long-term debt													0
Deferred income tax liabilities													1
Other long-term liabilities													0
Non-controlling interests													0
Fair value of net assets acquired													9
Goodwill													0
Purchase price													$ 9
19 MW wind development project | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree							19 MW wind development project
Date of acquisition							September 2016
Percentage of voting equity interests Retained by Brookfield																40.00%	40.00%
Total cash consideration transferred																€ 7	$ 8
Deferred consideration																1	1
Consideration transferred																€ 8	$ 9
Portugal Wind Portfolio | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree											Portugal Wind Portfolio
Date of acquisition											February 2015
Percentage of voting equity interests Retained by Brookfield											40.00%											40.00%
Total cash consideration transferred											€ 58											$ 63
Revenue of acquiree since acquisition date														28
Annual generation Energy, GWh | GWh											260
Aggregate Capacity, MW | MW											123
Consideration transferred											€ 65											$ 71
Scotland Wind Pipeline | Brookfield Renewable
Disclosure of detailed information about business combination [line items]
Name of acquiree										Scotland Wind Pipeline
Date of acquisition										June 2015
Total cash consideration transferred																				£ 40	$ 62
Deferred consideration																				6	9
Aggregate Capacity, MW | MW										1,200
Consideration transferred																				47	72
Acquisition costs incurred and capitalized										$ 1
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Other long-term liabilities																				£ 63	$ 97
Portugal Portfolio
Disclosure of detailed information about business combination [line items]
Consideration transferred														71
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														0
Restricted cash														5
Trade receivables and other current assets														3
Property, plant and equipment, at fair value														209
Current liabilities														(19)
Long-term debt														(111)
Other long-term liabilities														(16)
Non-controlling interests														0
Portugal Portfolio | Brookfield Renewable | Acqusitions Completed In 2015
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														0
Restricted cash														5
Trade receivables and other current assets														3
Property, plant and equipment, at fair value														209
Current liabilities														19
Long-term debt														111
Other long-term liabilities														16
Non-controlling interests														0
Fair value of net assets acquired														71
Scotland Portfolio
Disclosure of detailed information about business combination [line items]
Consideration transferred														72
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														0
Restricted cash														0
Trade receivables and other current assets														1
Property, plant and equipment, at fair value														84
Current liabilities														(1)
Long-term debt														0
Other long-term liabilities														(12)
Non-controlling interests														0
Scotland Portfolio | Brookfield Renewable | Acqusitions Completed In 2015
Amounts recognised as of acquisition date for each major class of assets acquired and liabilities assumed [abstract]
Cash and cash equivalents														0
Restricted cash														0
Trade receivables and other current assets														1
Property, plant and equipment, at fair value														84
Current liabilities														1
Long-term debt														0
Other long-term liabilities														12
Non-controlling interests														0
Fair value of net assets acquired														$ 72

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Sensitivity analysis) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of risk management strategy related to hedge accounting [line items]
Notional amount	$ 11,842	$ 10,260
Subsidiaries [member]
Disclosure of risk management strategy related to hedge accounting [line items]
Notional amount	9,285	8,025
Interest rate risk | Subsidiaries [member] | Floating interest rate [member]
Disclosure of risk management strategy related to hedge accounting [line items]
Notional amount	4,176	4,194
Hedged item, liabilities	824	966
Interest rate risk | Impact Of One Percent Increase | Floating interest rate [member]
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	17	(17)	$ (15)
Effect on other comprehensive income	54	115	125
Interest rate risk | Impact Of One Percent decrease | Floating interest rate [member]
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	(17)	17	15
Effect on other comprehensive income	(54)	(115)	(125)
Currency risk | Impact Of Five Percent Increase
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	4	1	2
Effect on other comprehensive income	79	51	10
Currency risk | Impact Of Five Percent Decrease
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	(4)	(1)	(2)
Effect on other comprehensive income	(79)	(51)	(10)
Commodity price risk | Impact Of Five Percent Increase
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	(3)	(1)	(2)
Effect on other comprehensive income	4	(7)	(7)
Commodity price risk | Impact Of Five Percent Decrease
Disclosure of risk management strategy related to hedge accounting [line items]
Effect on profit loss	3	1	2
Effect on other comprehensive income	$ 4	$ 7	$ 7

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Credit risk) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Credit Risk Exposure [Line Items]
Cash and cash equivalents	$ 799	$ 223	$ 63	$ 150
Restricted cash	284	250
Trade and other current receivables excluding prepaid	442	365
Financial instrument assets	185	200
Due from related parties	60	54
Total	$ 1,770	$ 1,092

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Cash obligations) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Accounts payable and accrued liabilities	$ 542	$ 467
Financial instrument liabilities	270	228
Due to related parties	112	76
Other long-term liabilities - concession payments	344	310
Long-term debt and credit facilities	11,842	10,260
Interest payable on long-term debt	4,255	3,859
Cash obligations	17,035	14,906
Concession Payments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Other long-term liabilities - concession payments	14	16
Less than 1 Year
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Accounts payable and accrued liabilities	542	467
Financial instrument liabilities	184	156
Due to related parties	112	76
Long-term debt and credit facilities	1,676	1,034
Interest payable on long-term debt	634	589
Cash obligations	3,149	2,323
Less than 1 Year | Concession Payments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Other long-term liabilities - concession payments	1	1
Between 2-5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Financial instrument liabilities	62	66
Due to related parties		0
Long-term debt and credit facilities	4,587	3,970
Interest payable on long-term debt	1,924	1,821
Cash obligations	6,576	5,861
Between 2-5 years | Concession Payments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Other long-term liabilities - concession payments	3	4
Greater than 5 years
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Financial instrument liabilities	24	6
Due to related parties		0
Long-term debt and credit facilities	5,579	5,256
Interest payable on long-term debt	1,697	1,449
Cash obligations	7,310	6,722
Greater than 5 years | Concession Payments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Other long-term liabilities - concession payments	$ 10	$ 11

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Classes of assets and liabilities table) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	$ 799	$ 223	$ 63	$ 150
Restricted cash	181	121
Trade and other receivables excluding prepaid	442	365
Other Current Assets	112	89
Due from related parties	60	54
Financial instrument assets	185	200
Equity-accounted investments	721	206	197	273
Property, plant and equipment, at fair value	27,096	25,257	18,358	$ 18,566
Goodwill	901	896
Deferred income tax assets	177	150
Other long-term assets	230	176
Total assets	30,904	27,737
Accounts payable and accrued liabilities	542	467
Financial instrument liabilities	270	228
Due to related parties	112	76
Borrowings	11,766	10,182	$ 7,338
Deferred income tax liabilities	3,588	3,802
Other long-term liabilities	344	310
Total liabilities	16,622	15,065
Cash, loans and receivables
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	799	223
Restricted cash	181	121
Trade and other receivables excluding prepaid	442	365
Other Current Assets	0	0
Due from related parties	60	54
Financial instrument assets	0	0
Equity-accounted investments	0	0
Property, plant and equipment, at fair value	0	0
Goodwill	0	0
Deferred income tax assets	0	0
Other long-term assets	103	129
Total assets	1,585	892
Accounts payable and accrued liabilities	0	0
Financial instrument liabilities	0	0
Due to related parties	0	0
Borrowings	0	0
Deferred income tax liabilities	0	0
Other long-term liabilities	0	0
Total liabilities	0	0
Assets/liabilities
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	0	0
Restricted cash	0	0
Trade and other receivables excluding prepaid	0	0
Other Current Assets	0	0
Due from related parties	0	0
Financial instrument assets	20	14
Equity-accounted investments	0	0
Property, plant and equipment, at fair value	0	0
Goodwill	0	0
Deferred income tax assets	0	0
Other long-term assets	0	0
Total assets	20	14
Accounts payable and accrued liabilities	0	0
Financial instrument liabilities	145	11
Due to related parties	0	0
Borrowings	0	0
Deferred income tax liabilities	0	0
Other long-term liabilities	0	0
Total liabilities	145	11
Derivatives used for hedging
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	0	0
Restricted cash	0	0
Trade and other receivables excluding prepaid	0	0
Other Current Assets	0	0
Due from related parties	0	0
Financial instrument assets	6	50
Equity-accounted investments	0	0
Property, plant and equipment, at fair value	0	0
Goodwill	0	0
Deferred income tax assets	0	0
Other long-term assets	0	0
Total assets	6	50
Accounts payable and accrued liabilities	0	0
Financial instrument liabilities	125	217
Due to related parties	0	0
Borrowings	0	0
Deferred income tax liabilities	0	0
Other long-term liabilities	0	0
Total liabilities	125	217
Other Financial Assets Liabilities
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	0	0
Restricted cash	0	0
Trade and other receivables excluding prepaid	0	0
Other Current Assets	0	0
Due from related parties	0	0
Financial instrument assets	159	136
Equity-accounted investments	0	0
Property, plant and equipment, at fair value	0	0
Goodwill	0	0
Deferred income tax assets	0	0
Other long-term assets	0	0
Total assets	159	136
Accounts payable and accrued liabilities	542	467
Financial instrument liabilities	0	0
Due to related parties	112	76
Borrowings	11,766	10,182
Deferred income tax liabilities	0	0
Other long-term liabilities	344	310
Total liabilities	12,764	11,035
Nonfinancial assets and nonfinancial liabilities
Disclosure of classification of assets liabilities [line items]
Cash and cash equivalents	0	0
Restricted cash	0	0
Trade and other receivables excluding prepaid	0	0
Other Current Assets	112	89
Due from related parties	0	0
Financial instrument assets	0	0
Equity-accounted investments	721	206
Property, plant and equipment, at fair value	27,096	25,257
Goodwill	901	896
Deferred income tax assets	177	150
Other long-term assets	127	47
Total assets	29,134	26,645
Accounts payable and accrued liabilities	0	0
Financial instrument liabilities	0	0
Due to related parties	0	0
Borrowings	0	0
Deferred income tax liabilities	3,588	3,802
Other long-term liabilities	0	0
Total liabilities	$ 3,588	$ 3,802

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Fair value hierarchy) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of financial assets [line items]
Cash and cash equivalents	$ 799	$ 223	$ 63	$ 150
Restricted Cash And Cash Equivalents	284	250
Financial instrument assets	185	200
Property, plant and equipment, at fair value	27,096	25,257	$ 18,358	$ 18,566
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	270	228
Contingent consideration	(18)	(16)
Liabilties for which fair value is disclosed
Long-term debt and credit facilities	(12,479)	(10,870)
Level 1
Disclosure of financial assets [line items]
Cash and cash equivalents	799
Restricted Cash And Cash Equivalents	284
Property, plant and equipment, at fair value	0
Disclosure Of Financial Liabilities [Line items]
Contingent consideration	0
Liabilties for which fair value is disclosed
Long-term debt and credit facilities	0
Level 2
Disclosure of financial assets [line items]
Cash and cash equivalents	0
Restricted Cash And Cash Equivalents	0
Property, plant and equipment, at fair value	0
Disclosure Of Financial Liabilities [Line items]
Contingent consideration	0
Liabilties for which fair value is disclosed
Long-term debt and credit facilities	(12,479)
Level 3
Disclosure of financial assets [line items]
Cash and cash equivalents	0
Restricted Cash And Cash Equivalents	0
Property, plant and equipment, at fair value	27,096
Disclosure Of Financial Liabilities [Line items]
Contingent consideration	(18)
Liabilties for which fair value is disclosed
Long-term debt and credit facilities	0
Energy Derivative Contracts
Disclosure of financial assets [line items]
Financial instrument assets	0	8
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(19)	(5)
Energy Derivative Contracts | Level 1
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Energy Derivative Contracts | Level 2
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(19)
Energy Derivative Contracts | Level 3
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Interest Rate Swaps
Disclosure of financial assets [line items]
Financial instrument assets	6	7
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(155)	(178)
Interest Rate Swaps | Level 1
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Interest Rate Swaps | Level 2
Disclosure of financial assets [line items]
Financial instrument assets	6
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(155)
Interest Rate Swaps | Level 3
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Foreign exchange swaps
Disclosure of financial assets [line items]
Financial instrument assets	20	49
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(96)	(45)
Foreign exchange swaps | Level 1
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Foreign exchange swaps | Level 2
Disclosure of financial assets [line items]
Financial instrument assets	20
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	(96)
Foreign exchange swaps | Level 3
Disclosure of financial assets [line items]
Financial instrument assets	0
Disclosure Of Financial Liabilities [Line items]
Financial instrument liabilities	0
Available-for-sale investments
Disclosure of financial assets [line items]
Financial instrument assets	159	$ 136
Available-for-sale investments | Level 1
Disclosure of financial assets [line items]
Financial instrument assets	79
Available-for-sale investments | Level 2
Disclosure of financial assets [line items]
Financial instrument assets	80
Available-for-sale investments | Level 3
Disclosure of financial assets [line items]
Financial instrument assets	$ 0

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Net position) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	$ 85	$ 28	$ 145	$ 77
Assets
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	185
Financial assets liabilities net position current portion	72
Financial assets liabilities net position noncurrent portion	113
Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	270
Financial assets liabilities net position current portion	184
Financial assets liabilities net position noncurrent portion	86
Net (Assets) Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	85	28
Financial assets liabilities net position current portion	112	101
Financial assets liabilities net position noncurrent portion	(27)	(73)
Energy Derivative Contracts | Assets
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	0
Energy Derivative Contracts | Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	19
Energy Derivative Contracts | Net (Assets) Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	19	(3)
Interest Rate Swaps | Assets
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	6
Interest Rate Swaps | Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	155
Interest Rate Swaps | Net (Assets) Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	149	171
Foreign exchange swaps | Assets
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	20
Foreign exchange swaps | Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	96
Foreign exchange swaps | Net (Assets) Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	76	(4)
Available-for-sale investments | Assets
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	159
Available-for-sale investments | Net (Assets) Liabilities
Disclosure of derivative assets liabilities net position [Line Items]
Financial assets liabilities net position	$ (159)	$ (136)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Continuity) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of derivative assets liabilities net position [Line Items]
Balance, beginning of year	$ 28	$ 145	$ 77
Unrealized financial instruments loss	33	4	9
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	4	8	10
Unrealized (loss) gain on foreign currency swaps - net investment hedge	(94)	(66)	55
Unrealized gain on available-for-sale securities	(22)	61	0
Acquisitions, settlements and other	(89)	(159)	68
Balance, end of year	85	28	145
Energy Derivative Contracts
Disclosure of derivative assets liabilities net position [Line Items]
Unrealized financial instruments loss	5	0	(2)
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	17	28	3
Interest Rate Swaps
Disclosure of derivative assets liabilities net position [Line Items]
Unrealized financial instruments loss	(1)	7	(2)
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	(18)	1	20
Foreign exchange swaps
Disclosure of derivative assets liabilities net position [Line Items]
Unrealized financial instruments loss	29	(3)	13
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	94	61	(57)
Available-for-sale investments
Disclosure of derivative assets liabilities net position [Line Items]
Unrealized financial instruments loss	0	0	25
Gain (loss) arising during the period on financial instruments designated as cash-flow hedges	20	(52)	0
Unrealized gain on available-for-sale securities	$ 20	$ (52)	$ 25

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Breakdown hedged not hedged) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	$ 270	$ 228
Financial instrument assets	185	200
Net Position	85	28	$ 145	$ 77
Financial Instruments Liabilities Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Net Position	145	11	0
Financial Instruments Liabilities Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Net Position	125	217	191
Financial Instruments Assets Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Net Position	(179)	(150)	(15)
Financial Instruments Assets Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Net Position	(6)	(50)	(31)
Energy Derivative Contracts
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	(19)	(5)
Financial instrument assets	0	8
Energy Derivative Contracts | Financial Instruments Liabilities Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	5	3	0
Energy Derivative Contracts | Financial Instruments Liabilities Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	14	2	1
Energy Derivative Contracts | Financial Instruments Assets Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	0	(3)	0
Energy Derivative Contracts | Financial Instruments Assets Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	0	(5)	(31)
Interest Rate Swaps
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	(155)	(178)
Financial instrument assets	6	7
Interest Rate Swaps | Financial Instruments Liabilities Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	107	2	0
Interest Rate Swaps | Financial Instruments Liabilities Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	48	176	178
Interest Rate Swaps | Financial Instruments Assets Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	(1)	(1)	0
Interest Rate Swaps | Financial Instruments Assets Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	(5)	(6)	0
Foreign exchange swaps
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	(96)	(45)
Financial instrument assets	20	49
Foreign exchange swaps | Financial Instruments Liabilities Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	33	6	0
Foreign exchange swaps | Financial Instruments Liabilities Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument liabilities	63	39	12
Foreign exchange swaps | Financial Instruments Assets Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	(19)	(10)	(1)
Foreign exchange swaps | Financial Instruments Assets Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	(1)	(39)	0
Available-for-sale investments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	159	136
Available-for-sale investments | Financial Instruments Assets Not Designated As Hedging Instruments
Disclosure of financial assets and liabilities [line items]
Financial instrument assets	$ (159)	$ (136)	$ (14)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Details - Explanation) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of risk management strategy related to hedge accounting [line items]
Reclassification adjustments for amounts recognized in net (loss) income	$ (1)	$ (41)	$ (32)
Notional amount	11,842	10,260
Energy Derivative Contracts
Disclosure of risk management strategy related to hedge accounting [line items]
Reclassification adjustments for amounts recognized in net (loss) income	23	48	32
Gain (loss) expected to be reclassed in the next twelve months	9	6	25
Interest Rate Swaps
Disclosure of risk management strategy related to hedge accounting [line items]
Reclassification adjustments for amounts recognized in net (loss) income	20	16	0
Gain (loss) expected to be reclassed in the next twelve months	18	110	114
Notional amount	1,704	2,397
Interest Rate Swaps | Not Designated as Hedging Instrument
Disclosure of risk management strategy related to hedge accounting [line items]
Notional amount	$ 780	$ 871
Derivative, Weighted Average Fixed interest rate	4.50%	2.50%
Foreign exchange swaps
Disclosure of risk management strategy related to hedge accounting [line items]
Reclassification adjustments for amounts recognized in net (loss) income	$ 48	$ 1	12
Notional amount	2,306	1,325
Foreign exchange swaps | Not Designated as Hedging Instrument
Disclosure of risk management strategy related to hedge accounting [line items]
Notional amount	718	283
Available-for-sale investments
Disclosure of risk management strategy related to hedge accounting [line items]
Reclassification adjustments for amounts recognized in net (loss) income	2	$ 9	$ 0
Gain (loss) expected to be reclassed in the next twelve months	$ 20

XML

SEGMENTED INFORMATION (Details - FFO reconciliation) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of operating segments [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Other income	47	64	122
Share of Adjusted EBITDA from equity accounted investments	57	21	26
Direct operating costs	978	1,038	552
Adjusted EBITDA	0	0	0
Management service costs	(82)	(62)	(48)
Interest expense borrowings	(632)	(606)	(429)
Current income taxes	(39)	(44)	(18)
Distributions to preferred limited partners	(28)	(15)	(1)
Distributions attributable to Preferred equity	(26)	(25)	(30)
Share of interest and cash taxes from equity accounted investments	(22)	(12)	(6)
Share of Funds From Operations attributable to non-controlling interests	(341)	(316)	(225)
Funds From Operations	0	0	0
Depreciation	782	781	616
Unrealized financial instruments loss	33	4	9
Deferred income tax (recovery) expense	(49)	97	80
Other	(28)	(38)	(63)
Share of earnings from associates	(33)	(9)	(10)
Net income attributable to non-controlling interest	288	251	156
Net Income Loss Attributable To Unit Holders	(56)	(65)	2
Colombia
Disclosure of operating segments [line items]
Revenues	797	819	0
Europe
Disclosure of operating segments [line items]
Revenues	111	136	138
Brazil
Disclosure of operating segments [line items]
Revenues	366	269	265
Attributable to Unitholders
Disclosure of operating segments [line items]
Revenues	1,679	1,481	1,296
Other income	40	47	76
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(577)	(586)	(465)
Adjusted EBITDA	1,142	942	907
Management service costs	82	62	48
Interest expense borrowings	407	402	346
Current income taxes	18	19	15
Distributions to preferred limited partners	(28)	(15)	(1)
Distributions attributable to Preferred equity	(26)	(25)	(30)
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	581	419	467
Depreciation	539	540	462
Unrealized financial instruments loss	(29)	(3)	(13)
Deferred income tax (recovery) expense	(26)	78	78
Other	(43)	(19)	(68)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	(56)	(65)	2
Attributable to Unitholders | Hydroelectric | North America
Disclosure of operating segments [line items]
Revenues	945	819	819
Other income	1	24	23
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(281)	(295)	(285)
Adjusted EBITDA	665	548	557
Management service costs	0	0	0
Interest expense borrowings	180	177	179
Current income taxes	(1)	4	5
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	486	367	373
Depreciation	222	244	218
Unrealized financial instruments loss	(3)	1	1
Deferred income tax (recovery) expense	(67)	31	36
Other	(20)	(27)	14
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	174	128	206
Attributable to Unitholders | Hydroelectric | Colombia
Disclosure of operating segments [line items]
Revenues	191	192	0
Other income	2	3	0
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(94)	(107)	0
Adjusted EBITDA	99	88	0
Management service costs	0	0	0
Interest expense borrowings	42	36	0
Current income taxes	5	6	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	52	46	0
Depreciation	26	31	0
Unrealized financial instruments loss	(3)	0	0
Deferred income tax (recovery) expense	(10)	6	0
Other	6	4	0
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	19	25	0
Attributable to Unitholders | Hydroelectric | Brazil
Disclosure of operating segments [line items]
Revenues	243	187	203
Other income	12	13	28
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(77)	(70)	(67)
Adjusted EBITDA	178	130	164
Management service costs	0	0	0
Interest expense borrowings	18	24	18
Current income taxes	12	9	10
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	148	97	136
Depreciation	141	125	113
Unrealized financial instruments loss	0	0	0
Deferred income tax (recovery) expense	2	7	4
Other	(8)	(5)	(8)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	1	(26)	19
Attributable to Unitholders | Wind | North America
Disclosure of operating segments [line items]
Revenues	161	151	150
Other income	0	0	12
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(42)	(36)	(38)
Adjusted EBITDA	119	115	124
Management service costs	0	0	0
Interest expense borrowings	45	41	48
Current income taxes	0	0	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	74	74	76
Depreciation	89	80	83
Unrealized financial instruments loss	(1)	0	2
Deferred income tax (recovery) expense	45	49	16
Other	(3)	4	(30)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	26	47	(19)
Attributable to Unitholders | Wind | Europe
Disclosure of operating segments [line items]
Revenues	46	56	56
Other income	0	0	8
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(20)	(24)	(20)
Adjusted EBITDA	26	32	44
Management service costs	0	0	0
Interest expense borrowings	10	14	12
Current income taxes	1	0	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	15	18	32
Depreciation	24	38	32
Unrealized financial instruments loss	(12)	0	0
Deferred income tax (recovery) expense	6	6	2
Other	(5)	6	(1)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	(20)	(8)	1
Attributable to Unitholders | Wind | Brazil
Disclosure of operating segments [line items]
Revenues	26	17	9
Other income	0	0	0
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(4)	(4)	(1)
Adjusted EBITDA	22	13	8
Management service costs	0	0	0
Interest expense borrowings	6	7	3
Current income taxes	0	0	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	16	6	5
Depreciation	8	4	4
Unrealized financial instruments loss	0	0	0
Deferred income tax (recovery) expense	0	0	0
Other	2	(1)	0
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	10	1	1
Attributable to Unitholders | Solar, Storage and Other
Disclosure of operating segments [line items]
Revenues	67	58	59
Other income	6	(1)	0
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(34)	(26)	(31)
Adjusted EBITDA	39	31	28
Management service costs	0	0	0
Interest expense borrowings	17	12	5
Current income taxes	1	0	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	21	19	23
Depreciation	29	18	12
Unrealized financial instruments loss	0	2	(1)
Deferred income tax (recovery) expense	1	0	0
Other	(6)	(2)	(4)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	(13)	1	6
Attributable to Unitholders | Corporate
Disclosure of operating segments [line items]
Revenues	0	1	0
Other income	19	8	5
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(25)	(24)	(23)
Adjusted EBITDA	(6)	(15)	(18)
Management service costs	82	62	48
Interest expense borrowings	89	91	81
Current income taxes	0	0	0
Distributions to preferred limited partners	(28)	(15)	(1)
Distributions attributable to Preferred equity	(26)	(25)	(30)
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	(231)	(208)	(178)
Depreciation	0	0	0
Unrealized financial instruments loss	(10)	(6)	(15)
Deferred income tax (recovery) expense	(3)	(21)	20
Other	(9)	2	(39)
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	(253)	(233)	(212)
Contribution from equity accounted investments
Disclosure of operating segments [line items]
Revenues	(74)	(37)	(44)
Other income	(11)	0	0
Share of Adjusted EBITDA from equity accounted investments	57	21	26
Direct operating costs	28	16	18
Adjusted EBITDA	0	0	0
Management service costs	0	0	0
Interest expense borrowings	(21)	(12)	(6)
Current income taxes	(1)	0	0
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	(22)	(12)	(6)
Share of Funds From Operations attributable to non-controlling interests	0	0	0
Funds From Operations	0	0	0
Depreciation	(22)	(11)	(9)
Unrealized financial instruments loss	1	(2)	1
Deferred income tax (recovery) expense	(3)	0	0
Other	13	0	0
Share of earnings from associates	(33)	(9)	(10)
Net income attributable to non-controlling interest	0	0	0
Net Income Loss Attributable To Unit Holders	0	0	0
Attributable to non-controlling interests
Disclosure of operating segments [line items]
Revenues	1,020	1,008	376
Other income	18	17	46
Share of Adjusted EBITDA from equity accounted investments	0	0	0
Direct operating costs	(429)	(468)	(105)
Adjusted EBITDA	609	557	317
Management service costs	0	0	0
Interest expense borrowings	246	216	89
Current income taxes	22	25	3
Distributions to preferred limited partners	0	0	0
Distributions attributable to Preferred equity	0	0	0
Share of interest and cash taxes from equity accounted investments	0	0	0
Share of Funds From Operations attributable to non-controlling interests	(341)	(316)	(225)
Funds From Operations	0	0	0
Depreciation	265	252	161
Unrealized financial instruments loss	(5)	1	3
Deferred income tax (recovery) expense	(20)	19	2
Other	2	(19)	0
Share of earnings from associates	0	0	0
Net income attributable to non-controlling interest	288	251	156
Net Income Loss Attributable To Unit Holders	$ 0	$ 0	$ 0

XML

SEGMENTED INFORMATION (Details - Balance Sheet) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	$ 27,096	$ 25,257	$ 18,358	$ 18,566
Total assets	30,904	27,737
Total borrowings	11,766	10,182	7,338
Total liabilities	16,622	15,065
For the year ended December 31: Additions to Property Plant and Equipment	354	358
Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	18,429	16,592
Total assets	19,962	17,727
Total borrowings	8,439	7,077
Total liabilities	11,979	10,642
For the year ended December 31: Additions to Property Plant and Equipment	220	222
Contribution from equity accounted investments
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	(1,451)	(428)
Total assets	(1,040)	(280)
Total borrowings	(848)	(232)
Total liabilities	(1,039)	(280)
For the year ended December 31: Additions to Property Plant and Equipment	(10)	(10)
Attributable to non-controlling interests
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	10,118	9,093
Total assets	11,982	10,290
Total borrowings	4,175	3,337
Total liabilities	5,682	4,703
For the year ended December 31: Additions to Property Plant and Equipment	144	146
Hydroelectric
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	22,399	21,569	14,847	15,210
Hydroelectric | North America | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	11,396	10,922
Total assets	11,709	11,219
Total borrowings	3,049	2,946
Total liabilities	5,237	5,414
For the year ended December 31: Additions to Property Plant and Equipment	90	86
Hydroelectric | Colombia | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	1,303	1,273
Total assets	1,574	1,577
Total borrowings	447	467
Total liabilities	801	824
For the year ended December 31: Additions to Property Plant and Equipment	8	9
Hydroelectric | Brazil | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	1,908	1,895
Total assets	2,149	2,059
Total borrowings	200	194
Total liabilities	380	340
For the year ended December 31: Additions to Property Plant and Equipment	59	79
Wind
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	3,751	3,313	$ 3,233	$ 3,315
Wind | North America | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	1,798	1,327
Total assets	1,888	1,389
Total borrowings	1,005	727
Total liabilities	1,338	990
For the year ended December 31: Additions to Property Plant and Equipment	6	3
Wind | Europe | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	482	545
Total assets	532	587
Total borrowings	233	249
Total liabilities	334	337
For the year ended December 31: Additions to Property Plant and Equipment	34	18
Wind | Brazil | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	304	139
Total assets	443	153
Total borrowings	192	50
Total liabilities	208	51
For the year ended December 31: Additions to Property Plant and Equipment	0	1
Solar, Storage and Other | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	1,227	491
Total assets	1,456	561
Total borrowings	752	215
Total liabilities	877	268
For the year ended December 31: Additions to Property Plant and Equipment	13	18
Corporate | Attributable to Unitholders
Disclosure of operating segments [line items]
Property, plant and equipment, at fair value	0	0
Total assets	180	182
Total borrowings	2,552	2,229
Total liabilities	2,786	2,418
For the year ended December 31: Additions to Property Plant and Equipment	$ 10	$ 8

XML

SEGMENTED INFORMATION (Details - Geographical Information) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of operating segments [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Consolidated property, plant and equipment and equity-accounted investments	27,817	25,463
United States
Disclosure of operating segments [line items]
Revenues	871	786	799
Consolidated property, plant and equipment and equity-accounted investments	11,131	10,163
Colombia
Disclosure of operating segments [line items]
Revenues	797	819	0
Consolidated property, plant and equipment and equity-accounted investments	5,401	5,275
Canada
Disclosure of operating segments [line items]
Revenues	480	442	426
Consolidated property, plant and equipment and equity-accounted investments	5,810	5,845
Brazil
Disclosure of operating segments [line items]
Revenues	366	269	265
Consolidated property, plant and equipment and equity-accounted investments	3,479	2,922
Europe
Disclosure of operating segments [line items]
Revenues	111	136	$ 138
Consolidated property, plant and equipment and equity-accounted investments	1,332	1,258
Other
Disclosure of operating segments [line items]
Consolidated property, plant and equipment and equity-accounted investments	$ 664	$ 0

XML

OTHER INCOME (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other income [line items]
Interest income and other	$ 32	$ 41	$ 21
Gain on available for sale investments	15	0	0
Gains on settlement of foreign currency contracts	0	23	31
Gains on disposal	0	0	53
Compensation related to expired Brazilian concession agreements	0	0	17
Other Income, net	$ 47	$ 64	122
Brookfield Renewable
Other income [line items]
Gains on disposal			$ 12
102 MW wind facility California | Brookfield Renewable
Other income [line items]
Percentage of equity interest			22.00%

XML

DIRECT OPERATING COSTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Direct Operating Costs [Abstract]
Operations, maintenance and administration	$ 567	$ 553	$ 396
Water royalties, property taxes and other	161	149	119
Fuel and power purchases	226	313	15
Energy marketing fees	24	23	22
Direct operating costs, net	$ 978	$ 1,038	$ 552

XML

OTHER (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Other [Abstract]
Transaction costs	$ (9)	$ (22)	$ (6)
Change in fair value of property, plant and equipment	(33)	(36)	(45)
Unrealized loss on available-for-sale securities	0	0	(25)
Other	14	20	13
Other expenses, net	$ (28)	$ (38)	$ (63)

XML

FOREIGN CURRENCY TRANSLATION (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Foreign currency translation on
Property, plant and equipment, at fair value	[1]	$ 506	$ 1,186	$ (1,975)
Long-term debt and credit facilities		(282)	(244)	697
Other assets and liabilities		48	201	(62)
Foreign currency translation, net		$ 190	$ 986	$ (1,138)

[1] Includes intangible assets of $ 13 million (201 6 : $ 1 4 million and 2015: $ 13 million ) and construction work in process (“CWIP”) of $ 601 million (201 6 : $ 663 million and 2015: $ 405 million ).

XML

INCOME TAXES (Details - Components of tax PL) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current tax expense (income) and adjustments for current tax of prior periods [abstract]
Current	$ (39)	$ (44)	$ (18)
Income tax (expense) recovery
Income taxes - origination and reversal of temporary differences	8	71	87
Relating to change in tax rates / imposition of new tax laws	(42)	35	6
Relating to unrecognized temporary differences and tax losses	(15)	(9)	(15)
Deferred taxes, net	(49)	97	80
Total Income Tax recovery (expense)	$ (88)	$ 53	$ 60

XML

INCOME TAXES (Details - Components of tax OCI) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax attributed to
Financial instruments designated as cash flow hedges	$ (4)	$ 2	$ 8
Other components of deferred tax expense (income)	15	(7)	(17)
Revaluation surplus
Origination and reversal of temporary differences	(248)	(55)	(263)
Income tax relating to changes in revaluation surplus of other comprehensive income for tax rate changes or imposition of new taxes	586	19	(19)
Total deferred income taxes	$ 349	$ (41)	$ (291)

XML

INCOME TAXES (Details - Expense reconciliation) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective income tax [abstract]
Statutory income tax (expense) recovery	$ (50)	$ 5	$ (15)
(Reduction) increase resulting from
Increase decrease in tax assets not recognised	(15)	(9)	(15)
Deemed profit method difference in Brazil	1	(11)	10
Differences between statutory rate and future tax rate	(38)	54	68
Income or losses recorded not taxable to Brookfield Renewable	14	14	14
Other	0	0	(2)
Total Income Tax recovery (expense)	$ (88)	$ 53	$ 60
Effective income tax rate	63.31%	384.03%

XML

INCOME TAXES (Details - Unrecognized deferred tax) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
2018 to 2022
Disclosure of deductible temporary differences for which no deferred tax asset is recognised [line items]
Unrecognized deferred tax assets	$ 8	$ 0
2023 and Thereafter
Disclosure of deductible temporary differences for which no deferred tax asset is recognised [line items]
Unrecognized deferred tax assets	$ 108	$ 98

XML

INCOME TAXES (Details - Reconciliation net labilities) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets and liabilities [line items]
Recognized in Net income (loss)	$ (49)	$ 97	$ 80
Deferred tax liability related to property, plant and equipment revaluations	2,561	2,948
The taxable temporary difference attributable to Brookfield Renewables interest in its subsidiaries	1,549	1,380
Net deferred tax liability decreased	546
Net decrease in tax liability recorded as tax recovery in the other comprehensive income	587
Noncapital losses
Deferred tax assets and liabilities [line items]
Balance, beginning of year	499	458	403
Recognized in Net income (loss)	(97)	24	73
Recognized in equity	13	17	(1)
Business combination	79	0	5
Foreign exchange	14	0	(22)
Balance, end of year	508	499	458
Amount available for future deductions
Deferred tax assets and liabilities [line items]
Balance, beginning of year	56	65	88
Recognized in Net income (loss)	(5)	(10)	(11)
Recognized in equity	0	0	0
Business combination	0	0	0
Foreign exchange	4	1	(12)
Balance, end of year	55	56	65
Difference between tax and carrying value
Deferred tax assets and liabilities [line items]
Balance, beginning of year	(4,207)	(3,061)	(2,986)
Recognized in Net income (loss)	53	83	16
Recognized in equity	341	(48)	(279)
Business combination	(63)	(1,020)	(35)
Foreign exchange	(98)	(161)	223
Balance, end of year	(3,974)	(4,207)	(3,061)
Deferred tax liability asset
Deferred tax assets and liabilities [line items]
Balance, beginning of year	(3,652)	(2,538)	(2,495)
Recognized in Net income (loss)	(49)	97	78
Recognized in equity	354	(31)	(280)
Business combination	16	(1,020)	(30)
Foreign exchange	(80)	(160)	189
Balance, end of year	(3,411)	$ (3,652)	$ (2,538)
Net deferred tax liability decreased	$ 41

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Details - Continuity) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Disclosure of detailed information about property, plant and equipment [line items]
Balance, as at Jan 1		$ 25,257	$ 18,358		$ 18,566
Additions	[1]	354	358		289
Acquisitions through business combinations	[1]	1,245	5,741		1,160
Disposals property plant and equipment	[1]	(338)			(230)
Items recognized through OCI
Change in fair value	[1]	887	431		1,209
Foreign exchange	[1]	506	1,186		(1,975)
Items recognized through net income
Change in fair value	[1]	(33)	(36)		(45)
Depreciation	[1]	(782)	(781)		(616)
Balance, as at Dec 31		27,096	25,257		18,358
Other intangible assets		13	14		13
Construction in progress		601	663		405
Hydroelectric
Disclosure of detailed information about property, plant and equipment [line items]
Balance, as at Jan 1		21,569	14,847		15,210
Additions		253	269		183
Acquisitions through business combinations		0	5,731		307
Items recognized through OCI
Change in fair value		828	190		1,141
Foreign exchange		332	1,114		(1,585)
Items recognized through net income
Change in fair value		(20)	(17)		(2)
Depreciation		(563)	(565)		(407)
Balance, as at Dec 31		22,399	21,569		14,847
Wind
Disclosure of detailed information about property, plant and equipment [line items]
Balance, as at Jan 1		3,313	3,233		3,315
Additions		95	71		51
Acquisitions through business combinations		618	10		624
Disposals property plant and equipment		(338)			(230)
Items recognized through OCI
Change in fair value		91	187		52
Foreign exchange		177	21		(336)
Items recognized through net income
Change in fair value		(8)	(10)		(43)
Depreciation		(197)	(199)		(200)
Balance, as at Dec 31		3,751	3,313		3,233
Other
Disclosure of detailed information about property, plant and equipment [line items]
Balance, as at Jan 1		375	278	[2]	41	[2]
Additions	[2]	6	18		55
Acquisitions through business combinations	[2]	627	0		229
Items recognized through OCI
Change in fair value	[2]	(32)	54		16
Foreign exchange	[2]	(3)	51		(54)
Items recognized through net income
Change in fair value	[2]	(5)	(9)		0
Depreciation	[2]	(22)	(17)		(9)
Balance, as at Dec 31		$ 946	$ 375		$ 278	[2]

[1] Includes intangible assets of $ 13 million (201 6 : $ 1 4 million and 2015: $ 13 million ) and construction work in process (“CWIP”) of $ 601 million (201 6 : $ 663 million and 2015: $ 405 million ).

[2] Includes solar, storage, biomass and Co-gen.

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Details - Rates)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
North America
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Exit date	2037	2036
North America | Bottom of range
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Terminal capitalization rate	6.20%	6.30%
North America | Bottom of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	4.90%	4.80%
North America | Bottom of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	6.50%	6.60%
North America | Top of range
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Terminal capitalization rate	7.50%	6.90%
North America | Top of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	6.00%	5.50%
North America | Top of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	7.60%	7.20%
Colombia
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Terminal capitalization rate	12.60%
Exit date	2037	2031
Colombia | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	11.30%
Colombia | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	12.60%
Europe
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Exit date	2031	2031
Europe | Bottom of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	4.10%	4.10%
Europe | Bottom of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	5.90%	5.90%
Europe | Top of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	4.50%	5.00%
Europe | Top of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	6.30%	6.80%
Brazil
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Exit date	2032	2031
Brazil | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate		9.20%
Brazil | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate		10.50%
Brazil | Bottom of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	8.90%
Brazil | Bottom of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	10.20%
Brazil | Top of range | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	9.20%
Brazil | Top of range | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Discount rate	10.50%

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Details - Sensitivity) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment	[1]	$ 887	$ 431	$ 1,209
Hydroelectric
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		828	190	$ 1,141
Impact Of Five Percent Increase | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		1,020	630
Impact Of Five Percent Decrease | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(1,020)	(630)
25 bps increase | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(910)	(740)
25 bps increase | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(230)	(180)
25 bps decrease | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		970	800
25 bps decrease | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		240	190
North America | Impact Of Five Percent Increase | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		620	540
North America | Impact Of Five Percent Decrease | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(620)	(540)
North America | 25 bps increase | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(710)	(670)
North America | 25 bps increase | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(180)	(180)
North America | 25 bps decrease | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		770	730
North America | 25 bps decrease | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		190	190
Colombia | Impact Of Five Percent Increase | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ 310
Useful life		310000000
Colombia | Impact Of Five Percent Decrease | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ (310)
Colombia | 25 bps increase | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(130)
Colombia | 25 bps increase | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(50)
Colombia | 25 bps decrease | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		130
Colombia | 25 bps decrease | Terminal capitalization rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		50
Europe | Impact Of Five Percent Increase | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ 20	20
Useful life		20000000
Europe | Impact Of Five Percent Decrease | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ (20)	(20)
Europe | 25 bps increase | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(20)	(20)
Europe | 25 bps decrease | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ 20	$ 20
Brazil | Hydroelectric
Changes in Property Plant And Equipment [Line Items]
Useful life		15	15
Additional fair value of Brazil hydro assets		$ 1,500
Additional useful life		20
Brazil | Impact Of Five Percent Increase | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ 70	$ 70
Useful life		70000000
Brazil | Impact Of Five Percent Decrease | Future electricity prices
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ (70)	(70)
Brazil | 25 bps increase | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		(50)	(50)
Brazil | 25 bps decrease | Discount rate
Changes in Property Plant And Equipment [Line Items]
Revaluation increase (decrease), property, plant and equipment		$ 50	$ 50

[1] Includes intangible assets of $ 13 million (201 6 : $ 1 4 million and 2015: $ 13 million ) and construction work in process (“CWIP”) of $ 601 million (201 6 : $ 663 million and 2015: $ 405 million ).

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Details - Prices and Generation) $ in Millions		12 Months Ended
		Dec. 31, 2017 USD ($) $ / MWh COP / MWh € / MWh BRL / MWh	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Change in fair value | $	[1]	$ 887	$ 431	$ 1,209
North America | 1-10 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		58.00%
Eletricity prices | $ / MWh		84
North America | 1-10 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | $ / MWh		63
North America | 11-20 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		42.00%
Eletricity prices | $ / MWh		88
North America | 11-20 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | $ / MWh		112
Colombia | 1-10 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		17.00%
Eletricity prices | COP / MWh		211,000
Colombia | 1-10 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | COP / MWh		238,000
Colombia | 11-20 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		0.00%
Eletricity prices | COP / MWh		0
Colombia | 11-20 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | COP / MWh		339,000
Europe | 1-10 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		78.00%
Eletricity prices | € / MWh		90
Europe | 1-10 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | € / MWh		78
Europe | 11-20 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		35.00%
Eletricity prices | € / MWh		107
Europe | 11-20 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | € / MWh		95
Brazil | 1-10 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		66.00%
Eletricity prices | BRL / MWh		274
Brazil | 1-10 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | BRL / MWh		309
Brazil | 11-20 years | Contracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Percentage of generation		57.00%
Eletricity prices | BRL / MWh		407
Brazil | 11-20 years | Uncontracted
Disclosure of significant unobservable inputs used in fair value measurement of assets [line items]
Eletricity prices | BRL / MWh		458

[1] Includes intangible assets of $ 13 million (201 6 : $ 1 4 million and 2015: $ 13 million ) and construction work in process (“CWIP”) of $ 601 million (201 6 : $ 663 million and 2015: $ 405 million ).

XML

PROPERTY, PLANT AND EQUIPMENT, AT FAIR VALUE (Details - Historical costs) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property Plant and Equipment carrying amount at cost of revalued assets [Line Items]
Property, plant and equipment, revalued assets, at cost	$ 16,703	$ 15,768
Hydroelectric
Property Plant and Equipment carrying amount at cost of revalued assets [Line Items]
Property, plant and equipment, revalued assets, at cost	12,740	12,761
Wind
Property Plant and Equipment carrying amount at cost of revalued assets [Line Items]
Property, plant and equipment, revalued assets, at cost	3,030	2,688
Other
Property Plant and Equipment carrying amount at cost of revalued assets [Line Items]
Property, plant and equipment, revalued assets, at cost	$ 933	$ 319

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Composition of debt) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure Of Detailed Information About Borrowings Line Items
Notional amount	$ 11,842	$ 10,260
Long-term debt and credit facilities	10,090	9,148
Current portion of long-term debt	1,676	1,034
Unamortised Financing Fees	77	80	$ 59
Unamortised Premiums	1	2
Long-term debt and credit facilities	$ 11,766	$ 10,182	7,338
Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	4.50%	4.50%
Weighted Average Borrowings Term	6.4	7.4
Notional amount	$ 1,670	$ 1,562
Estimated fair value	1,754	1,677
Unamortised Financing Fees	$ 5	$ 6	5	$ 5
Credit facilities
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	2.60%	1.90%
Weighted Average Borrowings Term	4.5	4.5
Notional amount	$ 887	$ 673
Estimated fair value	$ 887	$ 673
Sudsidiary
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	6.50%	6.40%
Weighted Average Borrowings Term	9	9
Notional amount	$ 9,285	$ 8,025
Estimated fair value	9,838	8,520
Unamortised Financing Fees	$ 72	$ 74	$ 54	$ 66
Sudsidiary | Hydroelectric
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	6.30%	6.90%
Weighted Average Borrowings Term	8.8	7.8
Notional amount	$ 6,392	$ 6,249
Estimated fair value	$ 6,813	$ 6,600
Sudsidiary | Wind
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	5.80%	4.60%
Weighted Average Borrowings Term	9.7	13.1
Notional amount	$ 2,211	$ 1,735
Estimated fair value	$ 2,343	$ 1,879
Sudsidiary | Solar and Other
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	11.00%	8.90%
Weighted Average Borrowings Term	8.2	18.8
Notional amount	$ 682	$ 41
Estimated fair value	$ 682	$ 41
Series 3 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	5.30%	5.30%
Weighted Average Borrowings Term	0.8	1.8
Notional amount	$ 159	$ 149
Estimated fair value	$ 163	$ 158
Series 4 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	5.80%	5.80%
Weighted Average Borrowings Term	18.9	19.9
Notional amount	$ 119	$ 111
Estimated fair value	$ 144	$ 132
Series 7 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	5.10%	5.10%
Weighted Average Borrowings Term	2.8	3.8
Notional amount	$ 358	$ 334
Estimated fair value	$ 382	$ 368
Series 8 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	4.80%	4.80%
Weighted Average Borrowings Term	4.1	5.1
Notional amount	$ 318	$ 298
Estimated fair value	$ 344	$ 331
Series 9 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	3.80%	3.80%
Weighted Average Borrowings Term	7.4	8.4
Notional amount	$ 318	$ 298
Estimated fair value	$ 321	$ 308
Series 10 | Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Weighted Average Interest Rate	3.60%	3.60%
Weighted Average Borrowings Term	9	10
Notional amount	$ 398	$ 372
Estimated fair value	$ 400	$ 380

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Changes over year) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
LONG-TERM DEBT AND CREDIT FACILITIES [Abstract]
Cash flows from financing activities	$ 267	$ 1,502
Non-cash
Acquisition	1,188	1,104
Disposal	(173)	0
Other	$ 302	$ 238

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Maturity schedule) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	$ 11,766	$ 10,182	$ 7,338
Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	2,557
Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	11,842
Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	6,392
Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	2,211
Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	682
Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	4,659
2018 | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	159
2018 | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	1,676
2018 | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	206
2018 | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	665
2018 | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	646
2018 | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	110
2019 | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	202
2019 | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	686
2019 | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	366
2019 | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	115
2019 | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	3
2019 | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	116
2020 | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	377
2020 | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	1,515
2020 | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	1,013
2020 | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	122
2020 | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	3
2020 | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	112
2021 | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	0
2021 | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	949
2021 | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	822
2021 | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	125
2021 | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	2
2021 | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	716
2022 | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	984
2022 | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	1,437
2022 | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	317
2022 | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	132
2022 | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	4
2022 | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	602
Thereafter
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	16,501
Thereafter | Corporate borrowings and credit facilities
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	835
Thereafter | Subsidiary borrowings
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	5,579
Thereafter | Subsidiary borrowings | Hydroelectric
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	3,668
Thereafter | Subsidiary borrowings | Wind
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	1,052
Thereafter | Subsidiary borrowings | Solar and Other
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	24
Thereafter | Equity-accounted investments
Disclosure of maturity analysis for non-derivative financial liabilities [line items]
Borrowings	$ 3,003

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Financing fees) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financing Fees
Unamortised Financing Fees, beginning of year	$ 80	$ 59
Unamortised Financing Fees, end of year	77	80	$ 59
Corporate Borrowings
Financing Fees
Unamortised Financing Fees, beginning of year	6	5	5
Amortisation Finance Fees	(1)	(1)	(1)
Additional Financing Fees	0	2	1
Unamortised Financing Fees, end of year	5	6	5
Sudsidiary
Financing Fees
Unamortised Financing Fees, beginning of year	74	54	66
Amortisation Finance Fees	(14)	(17)	(15)
Additional Financing Fees	16	41	7
Finance Fees Foreign Exchange Translation Other	(4)	(4)	(4)
Unamortised Financing Fees, end of year	$ 72	$ 74	$ 54

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Financings during the year) € in Millions, £ in Millions, CAD in Millions, BRL in Millions, $ in Millions	1 Months Ended					12 Months Ended
	Oct. 31, 2017 EUR (€)	Jul. 31, 2017 USD ($)	Jun. 30, 2017 CAD	May 31, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2017 BRL	Dec. 31, 2017 CAD	Dec. 31, 2017 GBP (£)	Dec. 31, 2017 USD ($)	Oct. 31, 2017 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)
Disclosure Of Detailed Information About Borrowings Line Items
Principal value									$ 11,842			$ 10,260
Authorized credit facilities									2,090			1,890
Series 3 medium-term notes
Disclosure Of Detailed Information About Borrowings Line Items
Principal value							CAD 200		159
Borrowings, maturity						November 2018
Corporate Borrowings
Disclosure Of Detailed Information About Borrowings Line Items
Principal value									$ 1,670			$ 1,562
Borrowings, interest rate						4.50%	4.50%	4.50%	4.50%			4.50%
Borrowings Term						6.4	6.4	6.4	6.4			7.4
Credit facilities
Disclosure Of Detailed Information About Borrowings Line Items
Principal value									$ 887			$ 673
Borrowings, maturity			June 30, 2022
Borrowings, interest rate basis			banker’s acceptance rate, LIBOR or EURIBOR
Borrowings, interest rate						2.60%	2.60%	2.60%	2.60%			1.90%
Borrowings Term						4.5	4.5	4.5	4.5			4.5
Corporate credit facilities
Disclosure Of Detailed Information About Borrowings Line Items
Authorized credit facilities											$ 1,600
Brookfield Asset Management credit facilities
Disclosure Of Detailed Information About Borrowings Line Items
Authorized credit facilities					$ 400
Sudsidiary
Disclosure Of Detailed Information About Borrowings Line Items
Principal value									$ 9,285			$ 8,025
Borrowings, interest rate						6.50%	6.50%	6.50%	6.50%			6.40%
Borrowings Term						9	9	9	9			9
417 MW Hydroeletric facility
Disclosure Of Detailed Information About Borrowings Line Items
Principal value					$ 60
Borrowings, maturity					March 2022
Borrowings, interest rate					3.75%
44 MW hydroelectric portfolio
Disclosure Of Detailed Information About Borrowings Line Items
Principal value				$ 65
Borrowings, maturity				May 2027
Borrowings, interest rate				4.86%
11 MW wind asset
Disclosure Of Detailed Information About Borrowings Line Items
Principal value											$ 11
Borrowings, maturity			June 2024
Borrowings, interest rate			5.28%								5.28%
17 MW hydroeletric facility
Disclosure Of Detailed Information About Borrowings Line Items
Principal value			CAD 55								$ 43
Borrowings, maturity			May 2044
Borrowings, interest rate			4.49%								4.49%
360 MW hydroelectric portfolio
Disclosure Of Detailed Information About Borrowings Line Items
Principal value		$ 475
Borrowings, maturity		July 2032
Borrowings, interest rate		4.40%
47 MW wind portfolio
Disclosure Of Detailed Information About Borrowings Line Items
Principal value	€ 78									$ 92
Borrowings, maturity		2032
Borrowings, interest rate basis	EURIBOR
Working capital facility	€ 6									8
Debt reserve facility	€ 4									4
872 MW hydroelectric portfolio
Disclosure Of Detailed Information About Borrowings Line Items
Principal value										$ 305
Borrowings, maturity	December 2030
Borrowings, interest rate	4.29%									4.29%
28 MW Hydroelectric facility
Disclosure Of Detailed Information About Borrowings Line Items
Principal value						BRL 166			$ 50
Borrowings, maturity						2038
28 MW Hydroelectric facility | TJLP
Disclosure Of Detailed Information About Borrowings Line Items
Borrowings, interest rate						2.12%	2.12%	2.12%	2.12%
16 MW wind facility
Disclosure Of Detailed Information About Borrowings Line Items
Principal value								£ 17	$ 22
Borrowings, maturity						2035
16 MW wind facility | LIBOR
Disclosure Of Detailed Information About Borrowings Line Items
Borrowings, interest rate						2.20%	2.20%	2.20%	2.20%

XML

LONG-TERM DEBT AND CREDIT FACILITIES (Details - Available credit facilities) - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Disclosure of credit facilities line item
Authorized credit facilities			$ 2,090,000	$ 1,890,000
Draws on credit facilities			(685,000)	(673,000)
Letters of credit issued			(193,000)	(250,000)
Undrawn borrowing facilities			1,212,000	$ 967,000
Credit facilities
Disclosure of credit facilities line item
Draws on credit facilities			202,000
Borrowings, maturity	June 30, 2022
Brookfield Asset Management credit facilities
Disclosure of credit facilities line item
Authorized credit facilities		$ 400,000
Draws on credit facilities			$ 202,000
Interest rate margin		2.00%
Extension of Maturity Date		December 2018	June 2019
Brookfield Asset Management credit facilities | LIBOR
Disclosure of credit facilities line item
Interest rate margin			1.50%
Corporate credit facilities
Disclosure of credit facilities line item
Authorized credit facilities	$ 1,600,000
Interest rate margin	1.20%

XML

NON-CONTROLLING INTERESTS (Details - Summary) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Participating Non-controlling Interests Operating Subsidiaries
Disclosure of Non Controlling Interest [Line Items]
Non controlling Interests	$ 6,298	$ 5,589
General partnership interest in a holding subsidiary held by Brookfield
Disclosure of Non Controlling Interest [Line Items]
Non controlling Interests	58	55
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Disclosure of Non Controlling Interest [Line Items]
Non controlling Interests	2,843	2,680
Preferred equity
Disclosure of Non Controlling Interest [Line Items]
Non controlling Interests	$ 616	$ 576

XML

NON-CONTROLLING INTERESTS (Details - Continuity) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of subsidiaries [line items]
Profit Loss Attributable To Noncontrolling Interests	$ 288	$ 251	$ 156
Capital contributions	294	2,621	460
Acquisition	525	1,417
Other			1
Subsidiaries with material non-controlling interests
Disclosure of subsidiaries [line items]
Beginning Balance	5,589
Profit Loss Attributable To Noncontrolling Interests	53	65	69
Ending Balance	6,298	5,589
Brookfield Infrastructre Fund I
Disclosure of subsidiaries [line items]
Beginning Balance	963	958	914
Profit Loss Attributable To Noncontrolling Interests	(29)	(18)	26
Other comprehensive income, attributable to non-controlling interests	(76)	46	89
Capital contributions	0	0
Acquisition		0
Distributions	(8)	(23)	(70)
MTO adjustments	0	0
Other	0		(1)
Ending Balance	$ 850	963	958
Brookfield Infrastructre Fund I | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	75.00%
Brookfield Infrastructre Fund I | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	80.00%
Brookfield Infrastructre Fund III
Disclosure of subsidiaries [line items]
Beginning Balance	$ 1,085
Profit Loss Attributable To Noncontrolling Interests	33	15
Other comprehensive income, attributable to non-controlling interests	111	0	0
Capital contributions	186	1,074
Acquisition	525
Distributions	(88)	(7)	0
MTO adjustments	1	3
Other	1		0
Ending Balance	$ 1,852	1,085
Brookfield Infrastructre Fund III | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	69.00%
Brookfield Infrastructre Fund III | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	71.00%
Brookfield Infrastructre Fund II
Disclosure of subsidiaries [line items]
Beginning Balance	$ 1,654	1,441	937
Profit Loss Attributable To Noncontrolling Interests	(13)	(16)	27
Other comprehensive income, attributable to non-controlling interests	269	228	144
Capital contributions	89	74	460
Acquisition		0
Distributions	(317)	(73)	(126)
MTO adjustments	0	0
Other	0		(1)
Ending Balance	$ 1,682	1,654	1,441
Brookfield Infrastructre Fund II | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	50.00%
Brookfield Infrastructre Fund II | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	60.00%
The Cataylst Group
Disclosure of subsidiaries [line items]
Beginning Balance	$ 127	121	126
Profit Loss Attributable To Noncontrolling Interests	12	16	14
Other comprehensive income, attributable to non-controlling interests	2	2	(12)
Capital contributions	0	0
Acquisition		0
Distributions	(7)	(12)	(7)
MTO adjustments	0	0
Other	0		0
Ending Balance	$ 134	127	121
Interests held by third parties	25.00%
The Cataylst Group | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	25.00%
Brookfield Energia Renovavel
Disclosure of subsidiaries [line items]
Capital contributions		0
Acquisition		0
Isagen Institutional Investors
Disclosure of subsidiaries [line items]
Beginning Balance	$ 1,675
Profit Loss Attributable To Noncontrolling Interests	47	47
Other comprehensive income, attributable to non-controlling interests	78	148	0
Capital contributions	19	1,473
Acquisition		0
Distributions	(115)	0	0
MTO adjustments	2	7
Other	2		0
Ending Balance	$ 1,701	1,675
Interests held by third parties	53.00%
Isagen Institutional Investors | Brookfield and co-investors
Disclosure of subsidiaries [line items]
Owership percentage	99.50%
Number of additional shares acquired	3,358,523
Isagen Public non-controlling interests
Disclosure of subsidiaries [line items]
Beginning Balance	$ 14
Profit Loss Attributable To Noncontrolling Interests	0	19
Other comprehensive income, attributable to non-controlling interests	(1)	205	0
Capital contributions	0	0
Acquisition		1,417
Distributions	0	0	0
MTO adjustments	(9)	(1,627)
Other	(9)		0
Ending Balance	$ 9	14
Interests held by third parties	0.50%
Other
Disclosure of subsidiaries [line items]
Beginning Balance	$ 71	67	85
Profit Loss Attributable To Noncontrolling Interests	3	2	2
Other comprehensive income, attributable to non-controlling interests	0	6	(17)
Capital contributions	0	0
Acquisition		0
Distributions	(4)	(4)	(5)
MTO adjustments	0	0
Other	0		2
Ending Balance	$ 70	$ 71	$ 67
Other | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	21.00%
Other | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	50.00%

XML

NON-CONTROLLING INTERESTS (Details - Summary information) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Disclosure of subsidiaries [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Profit Loss	51	40	103
Comprehensive income	1,401	1,369	5
Profit Loss Attributable To Noncontrolling Interests	288	251	156
Property, plant and equipment, at fair value	27,096	25,257	18,358	$ 18,566
Assets	30,904	27,737
Liabilities	16,622	15,065
Borrowings	$ 11,766	10,182	7,338
Subsidiaries with material non-controlling interests
Disclosure of subsidiaries [line items]
Interest held by third parties Isagen total	75.90%
Revenues	$ 1,570	1,550	728
Profit Loss	107	124	147
Comprehensive income	815	988	348
Profit Loss Attributable To Noncontrolling Interests	53	65	69
Property, plant and equipment, at fair value	15,745	14,133
Assets	18,460	15,884
Liabilities	6,411	5,180
Borrowings	8,559	7,107
Non controlling Interests	$ 6,298	5,589
Brookfield Infrastructre Fund I
Disclosure of subsidiaries [line items]
Place of business	United States, Brazil
Revenues	$ 123	118	136
Profit Loss	(34)	(22)	34
Comprehensive income	(133)	37	144
Profit Loss Attributable To Noncontrolling Interests	(29)	(18)	26
Property, plant and equipment, at fair value	1,667	1,807
Assets	1,718	1,865
Liabilities	628	631
Borrowings	556	571
Non controlling Interests	$ 850	963	958	914
Brookfield Infrastructre Fund I | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	75.00%
Brookfield Infrastructre Fund I | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	80.00%
Brookfield Infrastructre Fund II
Disclosure of subsidiaries [line items]
Place of business	United States, Brazil, Europe
Revenues	$ 430	394	402
Profit Loss	(20)	(23)	49
Comprehensive income	529	356	247
Profit Loss Attributable To Noncontrolling Interests	(13)	(16)	27
Property, plant and equipment, at fair value	5,153	4,816
Assets	5,430	5,125
Liabilities	2,422	2,235
Borrowings	2,040	1,881
Non controlling Interests	$ 1,682	1,654	1,441	937
Brookfield Infrastructre Fund II | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	50.00%
Brookfield Infrastructre Fund II | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	60.00%
Brookfield Infrastructre Fund III
Disclosure of subsidiaries [line items]
Interest held by third parties Isagen total	22.90%
Place of business	United States, Brazil, India, China, South Africa
Revenues	$ 53	28
Profit Loss	18	(8)
Comprehensive income	126	(8)	0
Profit Loss Attributable To Noncontrolling Interests	33	15
Property, plant and equipment, at fair value	2,149	848
Assets	3,294	855
Liabilities	1,678	319
Borrowings	1,502	313
Non controlling Interests	$ 1,852	1,085
Brookfield Infrastructre Fund III | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	69.00%
Brookfield Infrastructre Fund III | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	71.00%
The Cataylst Group
Disclosure of subsidiaries [line items]
Interests held by third parties	25.00%
Place of business	United States
Revenues	$ 135	164	160
Profit Loss	47	62	56
Comprehensive income	57	70	8
Profit Loss Attributable To Noncontrolling Interests	12	16	14
Property, plant and equipment, at fair value	964	970
Assets	1,066	1,072
Liabilities	432	466
Borrowings	413	450
Non controlling Interests	$ 134	127	121	$ 126
The Cataylst Group | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	25.00%
Isagen
Disclosure of subsidiaries [line items]
Interest held by third parties Isagen total	0.50%
Place of business	Colombia
Revenues	$ 797	819
Profit Loss	89	110
Comprehensive income	236	502	0
Profit Loss Attributable To Noncontrolling Interests		86
Property, plant and equipment, at fair value	5,401	5,275
Assets	6,526	6,539
Liabilities	3,336	3,396
Borrowings	$ 1,858	1,924
Non controlling Interests		2,391
Isagen | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	76.00%
Other subsidiaries with material noncontrolling interests including Brazil
Disclosure of subsidiaries [line items]
Place of business	United States, Brazil, Canada
Revenues	$ 32	27	30
Profit Loss	7	5	8
Comprehensive income	0	31	(51)
Profit Loss Attributable To Noncontrolling Interests		2	$ 2
Property, plant and equipment, at fair value	411	417
Assets	426	428
Liabilities	63	60
Borrowings	$ 42	41
Non controlling Interests		71
Other subsidiaries with material noncontrolling interests including Brazil | Bottom of range
Disclosure of subsidiaries [line items]
Interests held by third parties	21.00%
Other subsidiaries with material noncontrolling interests including Brazil | Top of range
Disclosure of subsidiaries [line items]
Interests held by third parties	50.00%
Isagen Institutional Investors
Disclosure of subsidiaries [line items]
Interests held by third parties	53.00%
Interest held by third parties Isagen total	52.50%
Profit Loss Attributable To Noncontrolling Interests	$ 47	47
Non controlling Interests	$ 1,701	1,675
Isagen Public non-controlling interests
Disclosure of subsidiaries [line items]
Interests held by third parties	0.50%
Profit Loss Attributable To Noncontrolling Interests	$ 0	19
Non controlling Interests	$ 9	$ 14

XML

NON-CONTROLLING INTERESTS (Details - GP REU distributions and summary) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-controlling interests [member]
Disclosure of dividends [line items]
Distributions, Dollar	$ 278	$ 256
Disclosure of summary financial information [line items]
Revenues	2,625	2,452	$ 1,628
Comprehensive income	1,401	1,369	$ 5
Net (loss) income attributable to:
Property, plant and equipment, at fair value	27,096	25,257
Assets	30,904	27,737
Liabilities	$ 16,622	$ 15,065
Non-controlling interests [member] | BRELP
Disclosure of dividends [line items]
Distributions, per share	$ 0.4225
Incentive Distribution, Percent	25.00%
Non-controlling interests [member] | LP Units
Carrying value of:
Common units outstanding	180,400,000	166,800,000
Weighted average number of units	173,500,000	156,400,000	143,300,000
Non-controlling interests [member] | LP Units | BRELP
Disclosure of dividends [line items]
Distributions, per share	$ 0.375
Incentive Distribution, Percent	15.00%
Non-controlling interests [member] | Redeemable/Exchangeable partnership units
Carrying value of:
Common units outstanding	129,658,623	129,658,623
Weighted average number of units	129,700,000	129,700,000	129,700,000
Non-controlling interests [member] | Redeemable/Exchangeable partnership units | Brookfield Renewable
Disclosure of dividends [line items]
Owership percentage	100.00%
Non-controlling interests [member] | GP interests
Disclosure of dividends [line items]
Distributions, Dollar	$ 35	$ 24
Carrying value of:
Common units outstanding	2,651,506	2,651,506
Weighted average number of units	2,700,000	2,700,000	2,700,000
General partnership interest in a holding subsidiary held by Brookfield
Disclosure of summary financial information [line items]
Net (loss) income			$ 0
Net (loss) income attributable to:
Non-controlling interests	$ (1)	$ 0	0
Carrying value of:
Non controlling Interests	$ 58	55
General partnership interest in a holding subsidiary held by Brookfield | BRELP
Disclosure of dividends [line items]
Owership percentage	1.00%
General partnership interest in a holding subsidiary held by Brookfield | GP interests
Disclosure of dividends [line items]
Distributions, Dollar	$ 5	5
Incentive Distribution | GP interests
Disclosure of dividends [line items]
Distributions, Dollar	30	19
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Disclosure of summary financial information [line items]
Net (loss) income	(23)	(29)	1
Net (loss) income attributable to:
Non-controlling interests	(23)	(29)	$ 1
Carrying value of:
Non controlling Interests	2,843	2,680
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield | Redeemable/Exchangeable partnership units
Disclosure of dividends [line items]
Distributions, Dollar	$ 243	$ 232

XML

NON-CONTROLLING INTERESTS (Details - Preferred Equity) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2017
Series 1 (C$136)
Disclosure of preference shares [Line Items]
Shares outstanding	5,450
Cumulative dividend rate (%)	3.36%
Earliest permitted redemption date	Apr 30, 2020
Dividends declared for the year ended	$ 4	$ 3
Non controlling Interests	$ 108	101
Series 2 (C$113)
Disclosure of preference shares [Line Items]
Shares outstanding	4,510
Cumulative dividend rate (%)	3.63%
Earliest permitted redemption date	Apr 30, 2020
Dividends declared for the year ended	$ 3	3
Non controlling Interests	$ 90	84
Series 3 (C$249)
Disclosure of preference shares [Line Items]
Shares outstanding	9,960
Cumulative dividend rate (%)	4.40%
Earliest permitted redemption date	Jul 31, 2019
Dividends declared for the year ended	$ 8	8
Non controlling Interests	$ 197	185
Series 5 (C$103)
Disclosure of preference shares [Line Items]
Shares outstanding	4,110
Cumulative dividend rate (%)	5.00%
Earliest permitted redemption date	Apr 30, 2018
Dividends declared for the year ended	$ 4	4
Non controlling Interests	$ 82	76
Series 6 (C$175)
Disclosure of preference shares [Line Items]
Shares outstanding	7,000
Cumulative dividend rate (%)	5.00%
Earliest permitted redemption date	Jul 31, 2018
Dividends declared for the year ended	$ 7	7
Non controlling Interests	$ 139	$ 130
Class A Preference Shares
Disclosure of preference shares [Line Items]
Percentage of units for normal course issuer bid			10.00%

XML

PREFERRED LIMITED PARTNERS EQUITY (Details) CAD / shares in Units, CAD in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Feb. 28, 2017 CAD CAD / shares shares	Feb. 28, 2017 USD ($)	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($)	Jun. 30, 2017
Disclosure of preferred limited partners [Line Items]
Preferred limited partners' equity			$ 616	$ 576
Preferred Limited Partners Unit [Member]
Disclosure of preferred limited partners [Line Items]
Number of shares outstanding | shares			27,890,000
Dividends declared for the year ended				15
Preferred limited partners' equity			$ 511
Series 5 (C$72)
Disclosure of preferred limited partners [Line Items]
Number of shares outstanding | shares			2,890,000
Dividend rate			5.59%
Earliest redemption date			Apr 30, 2018
Dividends declared for the year ended			$ 4	3
Preferred limited partners' equity			$ 49	49
Series 7 (C$175)
Disclosure of preferred limited partners [Line Items]
Number of shares outstanding | shares			7,000,000
Dividend rate			5.50%
Earliest redemption date			Jan 31, 2021
Dividends declared for the year ended			$ 8	7
Preferred limited partners' equity			$ 128	128
Series 9 (C$200)
Disclosure of preferred limited partners [Line Items]
Number of shares outstanding | shares			8,000,000
Dividend rate			5.75%
Earliest redemption date			Jul 31, 2021
Dividends declared for the year ended			$ 8	5
Preferred limited partners' equity			$ 147	147
Series 11 (C$250)
Disclosure of preferred limited partners [Line Items]
Number of shares outstanding | shares			10,000,000
Dividend rate	5.00%	5.00%
Earliest redemption date			Apr 30, 2022
Dividends declared for the year ended			$ 8	0
Preferred limited partners' equity			$ 187	$ 0
Gross Proceeds From Issuing Shares	CAD 250	$ 190
Dividend rate reset period	April 30, 2022	April 30, 2022
Par Value Per Share | CAD / shares	CAD 25
Number of shares issued | shares	10,000,000
Series 11 (C$250) | Government of Canada Bond yield plus
Disclosure of preferred limited partners [Line Items]
Dividend rate	3.82%	3.82%
Series 11 (C$250) | T-Bill Rate plus
Disclosure of preferred limited partners [Line Items]
Dividend rate			3.82%
Class A Preference Shares
Disclosure of preferred limited partners [Line Items]
Percentage of units for normal course issuer bid					10.00%

XML

LIMITED PARTNERS EQUITY (Details) CAD / shares in Units, $ / shares in Units, CAD in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2017 $ / shares	Dec. 31, 2017 CAD shares	Dec. 31, 2017 USD ($) shares	Dec. 31, 2016 USD ($) shares	Jul. 06, 2017 CAD / shares shares
Brookfield Asset Management
Disclosure of limited partners equity [Line Items]
Number of shares outstanding		185,727,567	185,727,567
Ownership percentage		60.00%	60.00%
Brookfield Asset Management | Direct ownership | Ownership interest in BEP
Disclosure of limited partners equity [Line Items]
Ownership percentage		31.00%	31.00%
Brookfield Asset Management | Direct ownership | Ownership interest in BRELP
Disclosure of limited partners equity [Line Items]
Ownership percentage		42.00%	42.00%
Public shareholders
Disclosure of limited partners equity [Line Items]
Ownership percentage		40.00%	40.00%
LP Units
Disclosure of limited partners equity [Line Items]
Number of shares outstanding		180,388,361	180,388,361
Share issue related cost		CAD 15	$ 11
Gross Proceeds From Issuing Shares		CAD 550	422
Dividends recognised as distributions to owners | $			$ 328	$ 281
Dividends paid, ordinary shares per share | $ / shares	$ 1.87
LP Units | Distribution reinvestment plan
Disclosure of limited partners equity [Line Items]
Number of shares issued		302,037	302,037	298,946
LP Units | Brookfield Asset Management
Disclosure of limited partners equity [Line Items]
Number of shares outstanding		56,068,944	56,068,944	51,125,944
Dividends recognised as distributions to owners | $			$ 101	$ 83
LP Units | Brookfield Asset Management | Private Placement
Disclosure of limited partners equity [Line Items]
Number of shares issued					4,943,000
LP Units | Public shareholders
Disclosure of limited partners equity [Line Items]
Dividends recognised as distributions to owners | $			$ 227	$ 198
LP Units | Public shareholders | Ownership interest in BEP
Disclosure of limited partners equity [Line Items]
Maximum units for normal course issuer bid		9,000,000	9,000,000
Percentage of units for normal course issuer bid		5.00%	5.00%
LP Units | Public shareholders | Bought deal
Disclosure of limited partners equity [Line Items]
Gross Proceeds From Issuing Shares		CAD 350	$ 271
Amount Per Share | CAD / shares					CAD 42.15
Number of shares issued					8,304,000
Redeemable/Exchangeable partnership units
Disclosure of limited partners equity [Line Items]
Issue Of Equity Adjustment | $			62
GP interests
Disclosure of limited partners equity [Line Items]
Issue Of Equity Adjustment | $			$ 1
GP interests | Brookfield Asset Management | Ownership interest in BEP
Disclosure of limited partners equity [Line Items]
Ownership percentage		0.01%	0.01%
GP interests | Brookfield Asset Management | Ownership interest in BRELP
Disclosure of limited partners equity [Line Items]
Ownership percentage		1.00%	1.00%

XML

GOODWILL (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in goodwill [abstract]
Beginning of year	$ 896
Acquired through business acquisition	0	$ 799
Foreign exchange	5	97
End of year	$ 901	$ 896

XML

CAPITAL MANAGEMENT (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2018	Dec. 31, 2016	Dec. 31, 2015	Nov. 30, 2014
Disclosure of objectives, policies and processes for managing capital [line items]
Current portion of long-term debt	$ 1,676		$ 1,034
Non-current portion of non-current borrowings	10,090		9,148
Total borrowings	11,766		10,182	$ 7,338
Deferred income tax liabilities, net	3,411		3,652
Equity	14,282		12,672	$ 8,763	$ 8,881
Capitalization, net	$ 29,459		$ 26,506
Debt to total capitalization	40.00%		38.00%
Terraform Global
Disclosure of objectives, policies and processes for managing capital [line items]
Non-current portion of non-current borrowings	$ 342
Total borrowings	$ 841
Borrowings, maturity	2031
Redemption of bonds par value option, percent		101.00%
Redemption of bonds par value actual, percent		107.00%

XML

EQUITY-ACCOUNTED INVESTMENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of joint ventures [line items]
Carrying value	$ 721	$ 206	$ 197
Balance, beginning of year	206	197	273
Share of earnings from equity-accounted investments	2	0	10
Share of OCI: Revaluation of property, plant and equipment	54	7	96
Share of OCI: Other	2	1	0
Dividends received	(31)	(6)	(19)
Capital distributions, net	0	0	(144)
Foreign exchange translation	19	7	(19)
Balance, end of year	$ 721	206	197
First hydro
Disclosure of joint ventures [line items]
Name of joint venture	FHH (Guernsey) Limited
Ownership interest	25.00%
Carrying value	$ 245	0
Balance, beginning of year	0
Balance, end of year	245	0
European Storage
Disclosure of joint ventures [line items]
Acquisition	$ 248	0	0
TerraForm Power
Disclosure of joint ventures [line items]
Name of joint venture	TerraForm Power Inc.(1)
Ownership interest	16.00%
Carrying value	$ 0	0
Balance, beginning of year	0
Acquisition	221	0	$ 0
Balance, end of year	$ 212	0
Bear Swamp Power Co LLC
Disclosure of joint ventures [line items]
Name of joint venture	Bear Swamp Power Co. L.L.C.
Ownership interest	50.00%
Carrying value	$ 173	114
Balance, beginning of year	114
Balance, end of year	$ 173	114
Galera Centrais Eletricas SA
Disclosure of joint ventures [line items]
Ownership interest	50.00%
Carrying value	$ 28	29
Balance, beginning of year	29
Balance, end of year	$ 28	29
Pingston Power Inc
Disclosure of joint ventures [line items]
Ownership interest	50.00%
Carrying value	$ 57	58
Balance, beginning of year	58
Balance, end of year	$ 57	58
Brookfield Infrastructure Fund II Investees
Disclosure of joint ventures [line items]
Principal place of business	United States, Europe
Carrying value	$ 6	5
Balance, beginning of year	5
Balance, end of year	$ 6	$ 5
Brookfield Infrastructure Fund II Investees | Bottom of range
Disclosure of joint ventures [line items]
Ownership interest	14.00%
Brookfield Infrastructure Fund II Investees | Top of range
Disclosure of joint ventures [line items]
Ownership interest	50.00%

XML

EQUITY-ACCOUNTED INVESTMENTS (Details - Summary Information) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of joint ventures [line items]
Current assets	$ 477	$ 45
Property, plant and equipment, at fair value	8,098	864
Other assets	213	70
Current liabilities	687	42
Long-term debt	4,294	463
Other liabilities	958	71
Revenue	310	74	$ 89
Net (loss) income	(24)	0	19
Share of net income (loss): Cash Earnings	57	21	26
Share of net income (loss): Non-cash loss	$ (33)	$ (9)	$ (10)

XML

CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash And Cash Equivalents [Line Items]
Cash	$ 790	$ 210
Short-term deposit	9	13
Cash and cash equivalents, net	799	$ 223	$ 63	$ 150
Terraform Power global [Member] | Brookfield Renewable
Cash And Cash Equivalents [Line Items]
Cash and cash equivalents acquired	$ 611

XML

RESTRICTED CASH (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Restricted Cash [Abstract]
Operations	$ 195	$ 135
Credit obligations	85	104
Development projects	4	11
Restricted Cash And Cash Equivalents, net	284	250
Less: non-current	103	129
Current	$ 181	$ 121

XML

TRADE RECEIVABLES AND OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Trade Receivables and Other Current Assets [Abstract]
Trade receivables	$ 360	$ 262
Other short-term receivables	82	103
Prepaids and others	112	89
Trade receivables and other current assets, net	$ 554	$ 454
% of trade AR that is current	99.00%	95.00%
Description of significant payment terms in contracts with customers	Trade receivables are generally on 30-day terms and credit limits are assigned and monitored for all counterparties. In determining the recoverability of trade receivables, management performs a risk analysis considering the type and age of the outstanding receivables and the credit worthiness of the counterparties.
Allowance For Doubtful Trade Receivable Accounts	$ 0	$ 0

XML

OTHER LONG-TERM ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Other Long term assets [Line Items]
Restricted cash	$ 103	$ 129
Unamortized financing fees	5	6
Acqusition Downpayment	46	0
Other	76	41
Other long-term assets, net	230	$ 176
Cost
Other Long term assets [Line Items]
Restricted cash	103
Unamortized financing fees	32
Acqusition Downpayment	46
Other	82
Other long-term assets, net	263
Accumulated Amortization
Other Long term assets [Line Items]
Restricted cash	0
Unamortized financing fees	(27)
Acqusition Downpayment	0
Other	(6)
Other long-term assets, net	$ (33)

XML

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure Accounts Payable and Accured Liabilities [Abstract]
Operating accrued liabilities	$ 271	$ 147
Accounts payable	117	87
Current interest payable	64	68
Deferred consideration	35	55
Acquisition and related provisions	0	54
LP unitholders' distributions, preferred limited partnership unit distributions and preferred dividends payable	29	24
Other	26	32
Total accounts payable and accrued liabilities	$ 542	$ 467

XML

OTHER LONG-TERM LIABILITIES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure Other Long Term Liabilities [Line Items]
Acquisition related provisions	$ 80	$ 111
Pension obligations	89	87
Decommissioning retirement obligations	85	47
Contingent consideration	18	16
Commitments for power purchase agreement	13	0
Concession payment liability	9	10
Deferred Revenue	9	7
Other	41	32
Other long-term liabilities, net	$ 344	$ 310
Bottom of range
Disclosure Other Long Term Liabilities [Line Items]
Expected timing of outflows of provision for decommissioning restoration and rehabilitation costs	2031
Top of range
Disclosure Other Long Term Liabilities [Line Items]
Expected timing of outflows of provision for decommissioning restoration and rehabilitation costs	2138

XML

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	$ 415
Estimated contingent liabilities for letters of credit	$ 544	$ 549
Brazilian hydroelectric projects
Disclosure of finance lease and operating lease by lessee [line items]
Various agreements can be renewed and are extendable, maximum year	2091
Development Project Cost	$ 44
Development projects to be operational, Year	2018
Brookfield Renewable along with institutional investors
Disclosure of finance lease and operating lease by lessee [line items]
Estimated contingent liabilities for letters of credit	$ 76	66
Brookfield Renewable's subsidiaries
Disclosure of finance lease and operating lease by lessee [line items]
Estimated contingent liabilities for letters of credit	468	$ 483
2018
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	33
2019
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	32
2020
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	31
2021
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	30
2022
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	27
Thereafter
Disclosure of finance lease and operating lease by lessee [line items]
Minimum lease payments	$ 262

XML

RELATED PARTY (Details - PPA) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2011 USD ($) CAD / MWh	Dec. 31, 2017 USD ($) $ / MWh CAD / MWh GWh	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Nov. 28, 2011 USD ($)
Disclosure of transactions between related parties [line items]
Management Fee Expense		$ (82)	$ (62)	$ (48)
Energy marketing fees		24	23	22
Brookfield Renewable
Disclosure of transactions between related parties [line items]
Management Fee Expense		82	$ 62	$ 48
Management fee fixed component		21
Management fee fixed component quarterly		5
Capitalization for management fees		$ 14,000			$ 8,000
Energy marketing fees	$ 18
Brookfield Renewable | Power purchase agreement GLPL
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		40.00%
Initial expiry date of power purchase agreements		2029
Eletricity prices | CAD / MWh	68	82
Brookfield Renewable | Power purchase agreement MPT
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		20.00%
Initial expiry date of power purchase agreements		2029
Eletricity prices | CAD / MWh		103
Brookfield Renewable | Power purchase agreement BPUSHA
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		40.00%
Maximum annual increment in power purchase agreements		3.00%
Eletricity prices | $ / MWh		75
Brookfield Renewable | Power purchase agreement GLHA
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		20.00%
Eletricity prices | $ / MWh		37
Brookfield Renewable | Power purchase agreement Lievre power
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		40.00%
Maximum annual increment in power purchase agreements		3.00%
Eletricity prices | CAD / MWh		68
Brookfield Renewable | Power purchase agreement hydro pontiac one
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		40.00%
Initial expiry date of power purchase agreements		2029
Eletricity prices | CAD / MWh		68
Brookfield Renewable | Power purchase agreement hydro pontiac two
Disclosure of transactions between related parties [line items]
Annual increment as % of CPI		40.00%
Initial expiry date of power purchase agreements		2029
Eletricity prices | CAD / MWh		68
Brookfield Renewable | Power purchase agreement wind levelization
Disclosure of transactions between related parties [line items]
Initial expiry date of power purchase agreements		2019
Expected generation | GWh		506

XML

RELATED PARTY TRANSACTIONS (Details - Income Statement) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
Power purchase and revenue agreements	$ 601	$ 527	$ 469
Wind levelization agreement	6	8	6
Total related party revenues	607	535	475
Direct operating costs
Energy purchases	(13)	(3)	(5)
Energy marketing fee	(24)	(23)	(22)
Insurace services	(19)	(20)	(30)
Total related party direct operating costs	(56)	(46)	(57)
Management service costs	$ (82)	$ (62)	$ (48)

XML

RELATED PARTY TRANSACTIONS (Details - Balance Sheet) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Disclosure of transactions between related parties [line items]
Due from related parties	$ 60	$ 54
Due to related parties	112	76
Brookfield Renewable
Disclosure of transactions between related parties [line items]
Due from related parties	54	47
Due to related parties	48	48
Accrued distributions payable on LP Units and Redeemable/Exchangeable partnership units	32	26
Equity-accounted investments and other
Disclosure of transactions between related parties [line items]
Due from related parties	6	7
Due to related parties	$ 32	$ 2

XML

SUPPLEMENTAL INFORMATION (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental cash flow information:
Trade receivables and other current assets	$ (40)	$ 30	$ (72)
Accounts payable and accrued liabilities	32	(160)	2
Other assets and liabilities	(17)	(7)	8
Net change in working capital balances	$ 25	$ 137	$ 62

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Actuarial Assumptions)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined benefit pension plans | Bottom of range
Disclosure of actuarial assumptions [line items]
Actuarial assumption of discount rates	2.40%	2.20%	2.90%
Actuarial assumption of expected rates of inflation	1.50%	1.50%	2.00%
Actuarial assumption of expected rates of salary increases	2.50%	2.50%	2.50%
Defined benefit pension plans | Top of range
Disclosure of actuarial assumptions [line items]
Actuarial assumption of discount rates	7.30%	7.30%	4.70%
Actuarial assumption of expected rates of inflation	3.50%	3.50%	2.50%
Actuarial assumption of expected rates of salary increases	4.00%	4.00%	3.00%
Defined benefit nonpension plans | Bottom of range
Disclosure of actuarial assumptions [line items]
Actuarial assumption of discount rates	3.70%	4.10%	4.20%
Actuarial assumption of expected rates of salary increases	2.50%	2.50%	2.50%
Actuarial assumption of medical cost trend rates	5.30%	5.30%	6.30%
Defined benefit nonpension plans | Top of range
Disclosure of actuarial assumptions [line items]
Actuarial assumption of discount rates	7.10%	7.30%	4.70%
Actuarial assumption of expected rates of salary increases	4.00%	4.00%	3.00%
Actuarial assumption of medical cost trend rates	6.90%	6.90%	7.10%

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Sensitivity Analysis) $ in Millions	Dec. 31, 2017 USD ($)
Fifty basis point increase | Actuarial assumption of discount rates | Defined benefit pension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible increase in actuarial assumption	$ (11)
Fifty basis point increase | Actuarial assumption of discount rates | Defined benefit nonpension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible increase in actuarial assumption	(4)
Fifty basis point increase | Actuarial assumption of expected rates of inflation | Defined benefit pension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible increase in actuarial assumption	4
Fifty basis point increase | Actuarial assumption of medical cost trend rates | Defined benefit nonpension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible increase in actuarial assumption	4
Fifty basis point decrease | Actuarial assumption of discount rates | Defined benefit pension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible decrease in actuarial assumption	13
Fifty basis point decrease | Actuarial assumption of discount rates | Defined benefit nonpension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible decrease in actuarial assumption	5
Fifty basis point decrease | Actuarial assumption of expected rates of inflation | Defined benefit pension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible decrease in actuarial assumption	(4)
Fifty basis point decrease | Actuarial assumption of medical cost trend rates | Defined benefit nonpension plans
Disclosure of sensitivity analysis for actuarial assumptions [line items]
Increase (decrease) in defined benefit obligation due to reasonably possible decrease in actuarial assumption	$ (3)

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Expenses) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined benefit pension plans
Disclosure Of Defined Benefit Plans Expense [Line Items]
Current service cost	$ 3	$ 3	$ 3
Past service cost (recovery)	(1)	0	1
Interest expense	2	2	1
Administrative expense	1	1	1
Post-employment benefit expense, defined benefit plans	5	6	6
Remeasurement of net defined benefit liability
Return on plan assets	(8)	(2)	(1)
Actuarial changes arising from changes in demographic assumptions	1	(1)	2
Actuarial changes arising from changes in financial assumptions	7	5	(2)
Experience adjustments	0	0	2
Gain (loss) on remeasurement, net defined benefit liability (asset)	0	2	1
Defined benefit expense gain loss recognized, net	5	8	7
Defined benefit nonpension plans
Disclosure Of Defined Benefit Plans Expense [Line Items]
Current service cost	1	1	1
Past service cost (recovery)	0	0	(1)
Interest expense	3	3	2
Administrative expense	0	0	0
Post-employment benefit expense, defined benefit plans	4	4	2
Remeasurement of net defined benefit liability
Return on plan assets	0	0	0
Actuarial changes arising from changes in demographic assumptions	(2)	(1)	(5)
Actuarial changes arising from changes in financial assumptions	3	1	(1)
Experience adjustments	1	0	0
Gain (loss) on remeasurement, net defined benefit liability (asset)	2	0	(6)
Defined benefit expense gain loss recognized, net	$ 6	$ 4	$ (4)

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Net position) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined benefit pension plans
Disclosure of net defined benefit liability (asset) [line items]
Present value of defined benefit obligation	$ 172	$ 158	$ 124	$ 128
Plan assets, at fair value	(135)	(119)	(103)
Net defined benefit liability (asset)	37	39	21
Defined benefit nonpension plans
Disclosure of net defined benefit liability (asset) [line items]
Present value of defined benefit obligation	57	53	35	$ 43
Plan assets, at fair value	(5)	(5)	0
Net defined benefit liability (asset)	$ 52	$ 48	$ 35

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Defined benefit obligations) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined benefit pension plans
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	$ 158	$ 124	$ 128
Current service cost	3	3	3
Past service cost (recovery)	(1)	0	1
Remeasurement of net defined benefit liability
Actuarial changes arising from changes in demographic assumptions	1	(1)	2
Actuarial changes arising from changes in financial assumptions	7	5	(2)
Experience adjustments	0	0	2
Balance, end of year	172	158	124
Defined benefit pension plans | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	3	3	3
Past service cost (recovery)	(1)	0	1
Interest expense	7	7	5
Remeasurement of net defined benefit liability
Actuarial changes arising from changes in demographic assumptions	1	(1)	2
Actuarial changes arising from changes in financial assumptions	7	5	(2)
Experience adjustments	0	0	2
Benefits paid	(7)	(8)	(5)
Business combination	0	25	0
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	4	3	(10)
Defined benefit nonpension plans
Disclosure of net defined benefit liability (asset) [line items]
Balance, beginning of year	53	35	43
Current service cost	1	1	1
Past service cost (recovery)	0	0	(1)
Remeasurement of net defined benefit liability
Actuarial changes arising from changes in demographic assumptions	(2)	(1)	(5)
Actuarial changes arising from changes in financial assumptions	3	1	(1)
Experience adjustments	1	0	0
Balance, end of year	57	53	35
Defined benefit nonpension plans | Present value of defined benefit obligation
Disclosure of net defined benefit liability (asset) [line items]
Current service cost	1	1	1
Past service cost (recovery)	0	0	(1)
Interest expense	3	3	2
Remeasurement of net defined benefit liability
Actuarial changes arising from changes in demographic assumptions	(2)	(1)	(5)
Actuarial changes arising from changes in financial assumptions	3	1	(1)
Experience adjustments	1	0	0
Benefits paid	(2)	(2)	(2)
Business combination	0	14	0
Increase (decrease) through changes in foreign exchange rates, net defined benefit liability (asset)	$ 0	$ 2	$ (2)

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Plan assets) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined benefit pension plans
Disclosure of plan assets [line items]
Balance, beginning of year	$ (119)	$ (103)
Return on plan assets	(8)	(2)	$ (1)
Balance, end of year	(135)	(119)	(103)
Defined benefit pension plans | Plan assets
Disclosure of plan assets [line items]
Balance, beginning of year	119	103	108
Interest income	5	5	4
Return on plan assets	8	2	1
Employer contribution	5	7	5
Business combination	0	9	0
Benefits paid	(7)	(8)	(5)
Exchange differences	5	1	(10)
Balance, end of year	135	119	103
Defined benefit nonpension plans
Disclosure of plan assets [line items]
Balance, beginning of year	(5)	0
Return on plan assets	0	0	0
Balance, end of year	(5)	(5)	0
Defined benefit nonpension plans | Plan assets
Disclosure of plan assets [line items]
Balance, beginning of year	5	0	0
Interest income	0	0	0
Return on plan assets	0	0	0
Employer contribution	2	3	2
Business combination	0	4	0
Benefits paid	(2)	(2)	(2)
Exchange differences	0	0	0
Balance, end of year	$ 5	$ 5	$ 0

XML

PENSION AND EMPLOYEE FUTURE BENEFITS (Details - Category of assets)	Dec. 31, 2017	Dec. 31, 2016
Disclosure of fair value of plan assets [abstract]
Cash and cash equivalents	2.00%	5.00%
Equity securities	54.00%	50.00%
Debt securities	44.00%	44.00%
Real estate	0.00%	1.00%
Total	100.00%	100.00%

XML

SUBSIDIARY PUBLIC ISSUERS (Details - Balance Sheet) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2014
Disclosure of subsidiaries [line items]
Current assets	$ 1,666	$ 907
Current liabilities	2,514	1,733
Equity	14,282	12,672	$ 8,763		$ 8,881
Participating Non-controlling Interests Operating Subsidiaries
Disclosure of subsidiaries [line items]
Equity	6,298	5,589	2,587	$ 2,062
General partnership interest in a holding subsidiary held by Brookfield
Disclosure of subsidiaries [line items]
Equity	58	55	52	59
Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Disclosure of subsidiaries [line items]
Equity	2,843	2,680	2,559	2,865
Preferred equity
Disclosure of subsidiaries [line items]
Equity	616	576	$ 610	$ 728
Brookfield Renewable
Disclosure of subsidiaries [line items]
Current assets	32	26
Long-term assets	4,483	3,779
Current liabilities	43	33
Long-term liabilities	0	0
Equity	511	324
BRP Equity
Disclosure of subsidiaries [line items]
Current assets	412	0
Long-term assets	262	620
Current liabilities	7	9
Long-term liabilities	0	0
Equity	0	0
BRP Equity | Preferred equity
Disclosure of subsidiaries [line items]
Equity	616	576
Finco
Disclosure of subsidiaries [line items]
Current assets	1,691	1,581
Long-term assets	0	0
Current liabilities	180	19
Long-term liabilities	1,505	1,556
Equity	0	0
Holding Entities
Disclosure of subsidiaries [line items]
Current assets	525	150
Long-term assets	20,142	18,415
Current liabilities	3,024	2,971
Long-term liabilities	693	738
Equity	516	324
Holding Entities | Participating non-controlling interests - in a holding subsidiary - Redeemable/Exchangeable units held by Brookfield
Disclosure of subsidiaries [line items]
Equity	2,843	2,680
Other Subsidiaries
Disclosure of subsidiaries [line items]
Current assets	2,816	2,092
Long-term assets	29,508	27,250
Current liabilities	3,071	1,644
Long-term liabilities	12,670	12,775
Equity	0	0
Other Subsidiaries | Participating Non-controlling Interests Operating Subsidiaries
Disclosure of subsidiaries [line items]
Equity	6,298	5,589
Consolidating adjustments
Disclosure of subsidiaries [line items]
Current assets	(3,810)	(2,942)
Long-term assets	(25,157)	(23,234)
Current liabilities	(3,811)	(2,943)
Long-term liabilities	(760)	(1,737)
Equity	$ (516)	$ (324)

XML

SUBSIDIARY PUBLIC ISSUERS (Details - Income Statement) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of subsidiaries [line items]
Revenues	$ 2,625	$ 2,452	$ 1,628
Net (loss) income	51	40	103
Brookfield Renewable
Disclosure of subsidiaries [line items]
Revenues	0	0	0
Net (loss) income	(4)	(20)	2
BRP Equity
Disclosure of subsidiaries [line items]
Revenues	0	0	0
Net (loss) income	10	0	0
Finco
Disclosure of subsidiaries [line items]
Revenues	0	0	0
Net (loss) income	(1)	(1)	(1)
Holding Entities
Disclosure of subsidiaries [line items]
Revenues	0	1	8
Net (loss) income	(435)	(100)	(42)
Other Subsidiaries
Disclosure of subsidiaries [line items]
Revenues	2,625	2,451	1,620
Net (loss) income	631	558	235
Consolidating adjustments
Disclosure of subsidiaries [line items]
Revenues	0	0	0
Net (loss) income	$ (150)	$ (397)	$ (91)

XML

SUBSEQUENT EVENTS (Details) CAD / shares in Units, £ in Millions, COP in Millions, CAD in Millions, BRL in Millions, $ in Millions							1 Months Ended	12 Months Ended
	Feb. 22, 2018 USD ($)	Feb. 15, 2018 USD ($)	Jan. 29, 2018 BRL	Jan. 19, 2018 GBP (£)	Jan. 16, 2018 CAD CAD / shares shares	Jan. 16, 2018 USD ($)	Jun. 30, 2017	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Feb. 28, 2018 COP	Feb. 28, 2018 USD ($)	Jan. 29, 2018 USD ($)	Jan. 19, 2018 USD ($)
Disclosure of non-adjusting events after reporting period [line items]
Notional amount								$ 11,842	$ 10,260
Issuance of preferred limited partnership units								187	147	$ 128
Debt								10,090	9,148
Terraform Global
Disclosure of non-adjusting events after reporting period [line items]
Debt								$ 342
Borrowings, maturity								2031
Credit facilities
Disclosure of non-adjusting events after reporting period [line items]
Notional amount								$ 887	$ 673
Borrowings, interest rate								2.60%	1.90%
Borrowings, maturity							June 30, 2022
Senior Notes
Disclosure of non-adjusting events after reporting period [line items]
Borrowings, interest rate	9.75%
Borrowings, maturity	2022
Proceeds from refinancing of debt which were used to pay down existing debt	$ 760
Senior Notes | Terraform Global
Disclosure of non-adjusting events after reporting period [line items]
Debt	$ 400
Borrowings, interest rate	6.13%
Borrowings, maturity	2026
Revolving credit facility
Disclosure of non-adjusting events after reporting period [line items]
Debt	$ 45
Borrowings, maturity	2021
Bond Refinancing
Disclosure of non-adjusting events after reporting period [line items]
Debt											COP 750	$ 262
2.1 GW pumped storage facility | UNITED KINGDOM | Long-term debt
Disclosure of non-adjusting events after reporting period [line items]
Debt				£ 60										$ 83
Borrowings, maturity				2021
2.1 GW pumped storage facility | UNITED KINGDOM | Long-term debt | LIBOR
Disclosure of non-adjusting events after reporting period [line items]
Bears interest plus a margin				2.75%										2.75%
2.1 GW pumped storage facility | UNITED KINGDOM | Credit facilities
Disclosure of non-adjusting events after reporting period [line items]
Debt				£ 90										$ 125
19 MW hydroelectric facility | Brazil | Long-term debt
Disclosure of non-adjusting events after reporting period [line items]
Debt			BRL 130										$ 40
19 MW hydroelectric facility | Brazil | Long-term debt | TJLP
Disclosure of non-adjusting events after reporting period [line items]
Bears interest plus a margin			2.15%										2.15%
Borrowings, maturity			2038
296 MW hydroelectric facility | United States | Green Bond
Disclosure of non-adjusting events after reporting period [line items]
Debt		$ 350
Borrowings, interest rate		4.50%
Borrowings, maturity		2033
Proceeds from refinancing of debt which were used to pay down existing debt		$ 315
Series 13 Preferred LP Units [Member]
Disclosure of non-adjusting events after reporting period [line items]
Number of shares issued | shares					10,000,000
Par Value Per Share | CAD / shares					CAD 25
Issuance of preferred limited partnership units					CAD 250	$ 201